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 March 31, 2006

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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act).

Large accelerated filer þ                                            Accelerated filer o                                              Non-accelerated filer 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 March 31, 2006, 177,769,890 shares of DTE Energy’s common stock, substantially all held by non-affiliates, were outstanding.

DTE Energy Company
Quarterly Report on Form 10-Q
Quarter Ended March 31, 2006

Table of Contents

		Page
Definitions			1
Forward - Looking Statements			3
Part I - Financial Information
Item 1.	Financial Statements
	Consolidated Statement of Operations		27
	Consolidated Statement of Financial Position		28
	Consolidated Statement of Cash Flows		30
	Consolidated Statement of Changes in Shareholders’ Equity and Comprehensive Income		31
	Notes to Consolidated Financial Statements		32
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		4
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		25
Item 4.	Controls and Procedures		26
Part II - Other Information
Item 1.	Legal Proceedings		50
Item 1A.	Risk Factors		50
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		51
Item 6.	Exhibits		51
Signature			52
Computation of Ratio of Earnings to Fixed Charges
Chief Executive Officer Section 302 Form 10-Q Certification
Chief Financial Officer Section 302 Form 10-Q Certification
Chief Executive Officer Section 906 Form 10-Q Certification
Chief Financial Officer Section 906 Form 10-Q Certification

Definitions

Coke and Coke Battery	Raw coal is heated to high temperatures in ovens to separate 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 any 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) and any subsidiary companies
DTE Energy	DTE Energy Company, directly or indirectly the parent of Detroit Edison, MichCon and numerous non-utility subsidiaries
EPA	United States Environmental Protection Agency
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 wholly owned subsidiary of DTE Energy)
MichCon	Michigan Consolidated Gas Company (an indirect wholly owned subsidiary of DTE Energy) and any subsidiary companies
MDEQ	Michigan Department of Environmental Quality
MPSC	Michigan Public Service Commission
Non-utility	An entity that is not a public utility. Its conditions of service, prices of goods and services and other operating related matters are not directly 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 power supply cost recovery mechanism was suspended under Michigan’s restructuring legislation (signed into law June 5, 2000), which lowered and froze electric customer rates, and was reinstated by the MPSC effective January 1, 2004.
Production tax credits	Tax credits as authorized under Sections 45K and 45 of the Internal Revenue Code that are designed to stimulate investment in and development of alternate fuel sources. The amount of a production tax credit can vary each year as determined by the Internal Revenue Service.
Proved Reserves	Estimated quantities of natural gas, natural gas liquids and crude oil that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reserves under existing economic and operating conditions.
Securitization	Detroit Edison financed specific stranded costs at lower interest rates through the sale of rate reduction bonds by a wholly-owned special purpose entity, the Detroit Edison Securitization Funding LLC.

1

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 be recoverable if customers switch to alternative energy suppliers.
Synfuels	The fuel produced through a process involving chemically modifying and binding particles of coal. Synfuels are used for power generation and coke production. Synfuel production generates production tax credits.
Unconventional Gas	Includes those oil and gas deposits that originated and are stored in coal bed, tight sandstone and shale formations.
Units of Measurement
Bcf	Billion cubic feet of gas
Bcfe	Conversion metric of natural gas, the ratio of 6 Mcf of gas to 1 barrel of oil.
kWh	Kilowatthour of electricity
Mcf	Thousand cubic feet of gas
MMcf	Million cubic feet of gas
MW	Megawatt of electricity
MWh	Megawatthour of electricity

2

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 presently contemplated, projected, estimated or budgeted. Many factors may impact forward-looking statements including, but not limited to, the following:

• the higher price of oil and its impact on the value of production tax credits, and the ability to utilize and/or sell interests in facilities producing such credits, or the potential requirement to refund proceeds received from synfuel partners;

• the uncertainties of successful exploration of gas shale resources and inability to estimate gas reserves with certainty;

• 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, regulations, and the cost of remediation and compliance;

• nuclear regulations and operations associated with nuclear facilities;

• implementation of electric and gas Customer Choice programs;

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

• employee relations and the impact of collective bargaining agreements;

• unplanned outages;

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

• the timing and extent of changes in interest rates;

• the level of borrowings;

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

• effects of competition;

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

• contributions to earnings by non-utility subsidiaries;

• changes in and application of federal, state and local tax laws and their interpretations, including the Internal Revenue Code, regulations, rulings, court proceedings and audits;

• the ability to recover costs through rate increases;

• the availability, cost, coverage and terms of insurance;

• the cost of protecting assets against, or damage due to, terrorism;

• changes in and application of accounting standards and financial reporting regulations;

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

• uncollectible accounts receivable;

• litigation and related appeals; and

• changes in the economic and financial viability of our suppliers, customers and trading counterparties, and the continued ability of such parties to perform their obligations to the Company.

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

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DTE ENERGY COMPANY

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

OVERVIEW

DTE Energy is a growing and diversified energy company with 2005 revenues in excess of $9 billion and approximately $23 billion in assets. 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. We operate three energy-related non-utility segments with operations throughout the United States.

During the first quarter of 2006, our utilities and Fuel Transportation and Marketing segment generated most of our earnings. The 2006 increase in earnings at the utilities was primarily due to higher rates at MichCon and the negative impacts in the first quarter of 2005 due to the MPSC April 2005 gas cost recovery and final rate orders. Non-utility earnings were impacted by higher earnings in the Fuel Transportation and Marketing segment, offset by the deferral of a substantial portion of the potential gains from the sale of interests in our synfuel facilities.

The following table summarizes our income for both periods ending March 31:

(in millions, except Earnings per Share)	2006		2005
Net Income	$	136	$	122
Earnings per Diluted Share	$	.76	$	.70
Excluding Discontinued Operations and Accounting Changes
Income from Continuing Operations	$	136	$	126
Earnings per Diluted share	$	.76	$	.72

The items discussed below influenced our current financial performance and may affect future results:

• Effects of weather and collectibility of accounts receivable on utility operations;

• Synfuel-related earnings and the impact of higher oil prices on production credit phase-outs;

• Investments in our unconventional gas production business;

• Gains in our Fuel Transportation and Marketing business; and

• Cost reduction efforts and required capital investment.

UTILITY OPERATIONS

Weather - Earnings from our utility operations are seasonal and very sensitive to weather. Electric utility earnings are primarily dependent on hot summer weather, while the gas utility’s results are primarily dependent on cold winter weather. We experienced milder winter weather in the first quarter of 2006. The following table shows the dollar impact of weather relative to 30-year historical normal weather temperatures for each utility.

(in Millions)
	Estimated effect of weather on Net Income
Period	Electric			Gas
Ending March 31	Utility			Utility			Total
2006	$	(10	)	$	(12	)	$	(22	)
2005	$	1		$	3		$	4

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Receivables - Both utilities continue to experience high levels of past due receivables, especially within our Gas Utility operations. The increase is attributable to economic conditions in the service territories, high natural gas prices and the lack of adequate levels of government assistance for low-income customers.

We have taken aggressive actions to reduce the level of past due receivables, including increased customer disconnections, contracting with collection agencies and working with the State of Michigan and others to increase the share of low-income funding allocated to our customers. Our allowance for doubtful accounts expense for the two utilities increased to $39 million in the first quarter of 2006 compared to $32 million in the first quarter of 2005. In the first quarter of 2006, we sold previously written-off accounts of $44 million resulting in a gain and net proceeds of approximately $2 million. The gain was recorded as a recovery through the allowance for doubtful accounts expense, which is included within operation and maintenance expense.

The April 2005 MPSC gas rate order provided for an uncollectible true-up mechanism for MichCon. We filed the 2005 annual reconciliation during the first quarter of 2006 comparing our actual uncollectible expense to our designated revenue recovery of approximately $37 million on an annual basis. Ninety percent of the difference between the actual uncollectible expense and $37 million for the year will be refunded or surcharged after the conclusion of the annual reconciliation proceeding before the MPSC. As of March 31, 2006, we have accrued an underrecovery of $12 million under the uncollectible true-up mechanism.

NON-UTILITY OPERATIONS

We anticipate significant investment opportunities within our non-utility businesses. We employ disciplined investment criteria when assessing opportunities that will leverage our existing assets, skill and expertise. Specifically, we invest in targeted energy markets with attractive competitive dynamics where meaningful scale is in alignment with our risk profile. The primary source of investment capital is the estimated cumulative $1.2 billion of synfuel cash flows we anticipate through 2008, which consists of cash from operations, asset sales, hedge gains and the utilization of current and previously earned production tax credits to reduce tax payments. The estimated synfuel cash flows assume no phase-out of production tax credits in 2006 or 2007, and/or legislation passes that as proposed would result in no phase-out for 2006, as subsequently discussed. Tax credit carryforward utilization in part could be extended past 2008, if taxable income is reduced from current forecasts. Unless oil prices drop significantly or legislation is passed, the estimated cash flow from the synfuel business will be significantly less and the level of investments called for by this strategy will be adversely affected, unless we identify alternative sources of cash.

Power and Industrial Projects

We anticipate building around our core strengths in the markets where we operate. In determining the markets in which to compete, we closely examine the regulatory environment, the number of competitors and our ability to achieve sustainable margins. We plan to maximize the effectiveness of our inter-related businesses as we expand from our current regional focus. As we pursue growth opportunities, our first priority will be to achieve value-added returns.

We plan to focus on the following areas for growth:

• Optimizing our synfuel portfolio;

• Acquiring and developing landfill gas recovery facilities;

• Acquiring and developing on-site energy projects in the steel, automotive and pulp and paper industries, and expanding into new industries:

• Acquiring biomass-fired and renewable electric generating facilities; and

• Developing new tax advantaged opportunities.

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Synfuel-related earnings - We operate nine synthetic fuel production plants throughout the United States. Synfuel plants chemically change coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits are provided for the production and sale of solid synthetic fuel produced from coal. These tax credits expire on December 31, 2007. Our synthetic fuel plants generate operating losses which we expect to be offset by the resulting production tax credits. We have not had sufficient taxable income to fully utilize production tax credits earned in prior periods. As of March 31, 2006, we have $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 March 31, 2006. We will continue to evaluate opportunities to sell additional interests in our two remaining majority-owned plants. Proceeds from the sales are contingent upon production levels and the value of such credits. When we sell an interest in a synfuel project, we recognize the gain 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.

The value of a production tax credit can vary each year and is adjusted annually by an inflation factor published by the IRS in April of the following year. The value of the production 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. During 2005, the annual average wellhead price was 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 2005 through 2007 are as follows:

		Beginning Phase-Out	Ending Phase-Out
	Reference Price	Price	Price
2005 (actual)	$50.26	$      53.20	$      66.79
2006 (estimated)	Not Available	$          53	$          67
2007 (estimated)	Not Available	$          54	$          68

Through March 31, 2006, the NYMEX daily closing price of a barrel of oil for 2006 averaged approximately $63, which due to the wellhead/NYMEX difference, is comparable to an approximate $57 Reference Price. For the remaining life of the tax credits, if the Reference Price remains within or exceeds the phase-out range, the availability of production tax credits in that year would be reduced or eliminated. Any actual tax credit phase-out for 2006 and available tax credits, if any, will not be certain until the Reference Price is published by the IRS in April 2007. As of May 1, 2006, the realized and unrealized NYMEX daily closing price of a barrel of oil was approximately $72 for 2006, equating to an estimated Reference Price of $66, which is estimated to be within the phase-out range. The average NYMEX daily closing price of a barrel of oil would have to average less than approximately $56 for the remainder of 2006 in order that no phase-out of production tax credits occur. Unless oil prices drop significantly for the remainder of 2006 or legislation is passed, as subsequently discussed, we would experience a partial or full phase-out of the production tax credits in 2006, resulting in a reduction in the net income and cash flow from our synfuel business. A phase-out could have an adverse impact on our synthetic fuel production plans which, in turn, may have a material adverse impact on our results of operations, cash flow, and financial condition. However, we cannot predict with any certainty the Reference Price for the remainder of 2006 or beyond.

There is legislation pending in Congress that may impact the potential phase-out of production tax credits for 2006 and 2007. The legislation would use the prior year oil price to determine the current year Reference Price. If enacted, this legislation as proposed would result in no phase-out for 2006. At current oil prices, it may be uneconomic to operate most of the synfuel plants in the absence of the passage of legislation. We are unable to predict the outcome of this legislation.

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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. Additionally, based on estimates of tax credits allocated, our partners reimburse us (through the project entity) for the operating losses of the synfuel facilities, referred to as capital contributions. 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 and estimate the amount 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 changes in the agreements with certain of our synfuel partners and the exercise of existing rights by other synfuels partners, a higher percentage of the expected payments in 2006 may be variable payments. As a result, a larger portion of the 2006 synfuel payments may be subject to refund should a phase-out occur. We will defer gain recognition associated with variable and certain indemnified fixed note payments in 2006 until the probability of refund is remote and collectibility is assured. During the first quarter of 2006, we deferred $67 million pretax of synfuel-related gains and reserved $40 million pretax for the possible refund of partners’ capital contributions, compared to a pretax deferral of $41 million of synfuel-related gains during the same period in 2005. All or a portion of the deferred gains will be recognized when and if the gain recognition criteria is met. It is likely that additional potential gains will be deferred and potential refunds of partners’ capital contributions will be reserved in the second and/or third quarters unless there is persuasive evidence that no tax credit phase-out will occur or unless legislation passes. Our 2006 quarterly earnings from synfuels will likely be lower than 2005 until there is persuasive evidence regarding the effect of the tax credit phase-out. In addition, quarterly earnings in 2006 could be impacted by adjustments to previously established estimates of reserves for partners’ capital contributions and the value of tax credits allocated to us.

As discussed in Note 7, we have entered into derivative and other contracts to economically hedge a portion of our 2006 and 2007 synfuel cash flow exposure related to the risk of oil prices increasing. The derivative contracts are marked-to-market with changes in fair value recorded as an adjustment to synfuel gains. We recorded a pretax mark-to-market gain of $47 million during the first quarter of 2006 as compared to a $54 million pre-tax gain in the first quarter of 2005. As part of our synfuel-related risk management strategy, we continue to evaluate alternatives available to mitigate unhedged exposure to oil price volatility. These contracts, and other actions we can take and have taken, will protect approximately 70% of our 2006 synfuel cash flow and 25% of our 2007 cash flow. As our risk management position changes due to market volatility or legislative actions, we may adjust our hedging strategy in response to changing conditions.

In addition to entering into economic hedges, we can mitigate our exposure to a tax credit phase-out by shutting down or reducing production at our synfuel facilities, which decreases the amount of operating losses we generate. We regularly monitor oil prices and have created contingency plans to cease synfuel production. If oil prices remain at current levels and if legislation is not passed, synfuel production could be curtailed in the second quarter of 2006.

Assuming that there is no synfuel tax credit phase-out and/or that legislation previously discussed is passed, we expect cash flow from our synfuel business will be approximately $1.2 billion from 2006 to 2008. Unless oil prices drop significantly for the remainder of 2006 or legislation is passed, synfuel production levels may be reduced, which would reduce the income and cash flow from this business. If the Reference Price results in a phase-out of the synfuel tax credits for 2006, assuming the previously discussed current level of economic hedges and an early cessation of synfuel production to minimize operating losses, there is a potential negative impact of as much as approximately $200 million to 2006 net income and cash flow. In addition, a potential asset impairment of approximately $7 million pretax and a goodwill write-off of up to $41 million may be required due to the synfuel tax credit phase-out. We also have fixed notes receivable associated with the sales of interests in our synfuel facilities. A partial or full phase-out of production tax credits could adversely affect the collectibility of our receivables. The cash flow impact would reduce our ability to execute our investment and growth strategy, unless we find alternate sources of cash.

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Unconventional Gas Production

Current natural gas prices continue to provide attractive opportunities for our Unconventional Gas Production business segment. We are an experienced operator with 15 years of experience in the Antrim shale in northern Michigan, and have expanded our operations in the Barnett shale basin in north central Texas. Over the next few years, our goal is to continue to expand our existing leasehold acreage position and develop unproved acreage into proved reserves.

Antrim shale - We plan to grow through the extension of existing producing areas and acquisition of other producer’s properties. Additionally, we intend to develop existing acreage using the latest horizontal drilling techniques and to continue to search for expansion acreage. Approximately one-third of our long-term fixed-price obligations for production of Antrim gas expire from 2006 through 2008. This will create opportunities to remarket Antrim production at significantly higher current market rates.

Barnett shale - We anticipate significant opportunities in our existing Barnett shale acreage and expect continued extension of producing areas within the Fort Worth Basin. We are currently in the test and development phase for unproved and recently acquired Barnett shale acreage. We plan to continue to increase our leasehold acreage through small negotiated acquisitions.

Due to favorable natural gas prices and the potential for successes within the Barnett shale, more capital is being invested into the region. The competition for opportunities and goods and services may result in increased operating costs. However, our experience in the Antrim shale and our experienced Barnett shale personnel allow us to effectively manage the challenge. We expect to invest a combined amount of approximately $100 million to $130 million in our unconventional gas business in 2006.

Fuel Transportation and Marketing

Pipelines, Processing and Storage is in the process of expanding our storage capacity in Michigan and expanding and building new pipeline capacity to the northeast United States. Our Coal Transportation and Marketing business will seek to build our capacity to transport greater amounts of western coal and may seek to expand into coal terminals.

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 capacity positions. Most financial instruments are deemed derivatives, whereas the gas inventory, pipelines and storage assets are not derivatives. As a result, this segment may experience dramatic 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 accounting periods. We incur mark-to-market accounting gains or losses in one period that are subsequently reversed when transactions are settled.

During the first quarter of 2005, our earnings were negatively impacted by the economically favorable decision to delay previously planned withdrawals from gas storage due to a decrease in the current price for natural gas and an increase in the forward price for natural gas. In addition, we entered into forward power contracts to economically hedge certain physical and capacity power contracts. The financial impacts of these timing differences have begun to reverse and have favorably impacted results in the first quarter of 2006.

OPERATING SYSTEM AND PERFORMANCE EXCELLENCE PROCESS

We continuously review and adjust our cost structure and seek improvements in our processes. Beginning in 2002, we adopted the DTE Energy Operating System, which is the application of tools and operating practices that have resulted in operating efficiencies, inventory reductions and improvements in technology systems, among other enhancements. Some of these cost reductions may be returned to our customers in the form of lower PSCR charges and the remaining amounts may impact our profitability.

8

As an extension of this effort, in mid-2005, we initiated a company-wide review of our operations called the Performance Excellence Process. The overarching goal has been and remains to become more competitive by reducing costs, eliminating waste and optimizing business processes while improving customer service. Many of our customers are under intense economic pressure and will benefit from our efforts to keep down our costs and their rates. Additionally, we will need significant resources in the future to invest in the infrastructure necessary to compete. Specifically, we began a series of focused improvement initiatives within our Electric and Gas Utilities, and our corporate support function.

The process will be rigorous and challenging and seeks to yield sustainable performance to our customers and shareholders. We have identified the Performance Excellence Process as critical to our long-term growth strategy. We are entering the implementation phase and expect to begin to realize the benefits from the effort in 2006. The costs to execute the Performance Excellence Process are expected to result in restructuring charges in 2006.

CAPITAL INVESTMENT

We anticipate significant capital investment across all of our business segments. Most of our capital expenditures will be concentrated within our utility segments. Our electric utility currently expects to invest in total approximately $4 billion due to increased environmental requirements and reliability enhancement projects through 2010. Our gas utility currently expects to invest approximately $900 million on system expansion, pipeline safety and reliability enhancement projects through the same period. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base.

During 2005, we began the first wave of implementation of DTE2, an enterprise resource planning system initiative to improve existing processes and to implement new core information systems. We anticipate spending $165 million to $190 million over the next two years as the remaining system elements are developed and business segments fully adopt DTE2.

In the future, we may build a new base-load electric generating plant. The last base-load plant constructed within our electric utility service territory was approximately twenty years ago. A recently completed study, sponsored by the MPSC, projected that Michigan may need to install 7,000 MW of additional capacity over the next ten years. We estimate that a new 1,000 MW base-load plant will cost between $1 billion and $2 billion.

OUTLOOK

The next few years will be a period of rapid change for DTE Energy and for the energy industry. Our strong utility base combined with our integrated non-utility operations position us well for long-term growth. Due to the enactment of the Energy Policy Act of 2005 and the repeal of the Public Utility Holding Company Act of 1935 there are fewer barriers to mergers and acquisitions of utility companies. We anticipate greater industry consolidation over the next few years resulting in the creation of large regional utility providers.

Looking forward, we will focus on several areas that we expect will improve future performance:

• continuing to pursue regulatory stability and investment recovery for our utilities;

• managing the growth of our utility asset base;

• enhancing our cost structure across all business segments;

• improving our Electric and Gas Utility customer satisfaction;

• increasing the scale in our three non-utility business segments; and

• investing in businesses that integrate our assets and leverage our skills and expertise.

Along with pursuing a leaner organization, we expect to receive approximately $1.2 billion of synfuel cash flows through 2008 which consists of cash from operations, asset sales, hedge gains and the utilization of current and previously earned production tax credits to reduce tax payments, assuming that

9

there is no phase-out of production tax credits or that the legislation previously discussed is passed. Tax credit carryforward utilization in part could be extended past 2008, if taxable income is reduced from current forecasts. Unless oil prices drop significantly or legislation is passed, the estimated cash flow from the synfuel business will be significantly less and the level of investments called for by this strategy will be adversely affected, unless we identify alternative sources of cash.

Anticipated redeployment of this expected available cash will reduce DTE Energy’s debt and replace the value of synfuel operations inherent in our share price by pursuing investments in targeted energy markets. If adequate investment opportunities are not available, share repurchases may be used to build shareholder value. We remain committed to a strong balance sheet and financial coverage ratios, and paying an attractive dividend.

RESULTS OF OPERATIONS

Net income in the first quarter of 2006 was $136 million, or $.76 per diluted share, compared to net income of $122 million, or $.70 per diluted share, in the 2005 first quarter. The following sections provide a detailed discussion of our segments’ operating performance and future outlook.

(in Millions, except per share data)	2006			2005
Electric Utility	$	59		$	55
Gas Utility		50			13
Non-utility Operations:
Power and Industrial Projects		(2	)		68
Unconventional Gas Production		1			1
Fuel Transportation and Marketing		41			(10	)
Corporate & Other		(13	)		(1	)
Income (Loss) from Continuing Operations:
Utility		109			68
Non-utility		40			59
Corporate & Other		(13	)		(1	)
		136			126
Discontinued Operations		(1	)		(4	)
Cumulative Effect of Accounting Change		1			—
Net Income	$	136		$	122
Diluted Earnings Per Share
Total Utility	$	.61		$	.38
Non-utility Operations		.22			.34
Corporate & Other		(.07	)		—
Income from Continuing Operations		.76			.72
Discontinued Operations		—			(.02	)
Cumulative Effect of Accounting Change		—			—
Net Income	$	.76		$	.70

The earnings per share of any segment do 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 UTLILITY

Our Electric Utility segment consists of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.2 million customers in southeastern Michigan.

Factors impacting income: Net income increased $4 million for the 2006 first quarter. These results primarily reflect higher gross margins, partially offset by higher operation and maintenance expenses and increased depreciation and amortization expenses.

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	Three Months Ended
	March 31
	2006			2005
(in Millions)
Operating Revenues	$	1,050		$	990
Fuel and Purchased Power		309			301
Gross Margin		741			689
Operation and Maintenance		344			321
Depreciation and Amortization		167			150
Taxes Other Than Income		69			69
Operating Income		161			149
Other (Income) and Deductions		75			69
Income Tax Provision		27			25
Net Income	$	59		$	55
Operating Income as a Percent of Operating Revenues		15	%		15	%

Gross margins increased $52 million in the 2006 first quarter due to lower electric Customer Choice penetration, increased rates due to the expiration of the residential rate cap on January 1, 2006 and improved economic performance, partially offset by the impacts of milder winter weather in the first quarter of 2006.

Increase (Decrease) in Gross Margin Components
Compared to Prior Year	Three Months
(in Millions)
Weather related margin impacts	$	(10	)
Removal of residential rate caps effective January 1, 2006		22
Return of customers from electric Customer Choice		29
Service territory economic performance		14
Other, net		(3	)
Increase in gross margin performance	$	52

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Power Generated and Purchased	2006					2005
(in Thousands of MWh)
Power Plant Generation
Fossil		9,308		71	%		9,763		74	%
Nuclear		2,197		17			2,053		15
		11,505		88			11,816		89
Purchased Power		1,513		12			1,477		11
System Output		13,018		100	%		13,293		100	%
Less Line Loss and Internal Use		(825	)				(596	)
Net System Output		12,193					12,697
Average Unit Cost ($/MWh)
Generation (1)	$	14.66				$	14.40
Purchased Power	$	50.42				$	49.30
Overall Average Unit Cost	$	18.82				$	18.28

(1) Represents fuel costs associated with power plants.

(in Thousands of MWh)	2006		2005
Electric Sales
Residential		3,836		4,051
Commercial		4,008		3,364
Industrial		3,154		2,897
Wholesale		675		563
Other		106		104
		11,779		10,979
Interconnection sales (1)		414		1,718
Total Electric Sales		12,193		12,697
Electric Deliveries
Retail and Wholesale		11,779		10,979
Electric Choice		1,139		1,722
Electric Choice – Self Generators (2)		224		192
Total Electric Sales and Deliveries		13,142		12,893

(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 increased $23 million in the first quarter of 2006 due primarily to higher storm related costs and implementation costs associated with our Performance Excellence Process.

Depreciation and amortization expense increased $17 million in the first quarter of 2006 due to increased amortization of regulatory assets, including greater amortization of securitization assets resulting from higher sales volumes.

Other income and deductions increased $6 million primarily due to favorable adjustments in 2005 for settlements related to tax audits.

Outlook – We continue to improve the operating performance of Detroit Edison. During the past year, we have resolved many of our regulatory issues and continue to pursue additional regulatory solutions for structural problems within our competitive environment, mainly electric Customer Choice and the need to adjust rates for each customer class to reflect the full cost of service. In March 2006, the MPSC issued an order directing Detroit Edison to show cause by June 1, 2006 why its retail electric rates should not be reduced in 2007. We are unable to predict the outcome of this proceeding or its effect. In April 2006, an MPSC Administrative Law Judge issued a Proposal for Decision indicating that Detroit Edison’s position in the 2004 PSCR Reconciliation and the 2004 Net Stranded Cost Case proceeding is overstated. If this proposal is adopted by the MPSC, net income would be reduced by approximately $17 million. See Note

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4.

Concurrently, we will move forward in our efforts to improve performance. Looking forward, additional issues, such as rising prices for coal, uranium and health care, continued under-performance of Michigan’s economy and capital spending, will result in us taking meaningful action to address our costs while continuing to provide quality customer service. We will utilize the DTE Operating System and the Performance Excellence Process to seek opportunities to improve productivity, remove waste, decrease our costs, while improving customer satisfaction.

Long term, we will be required to invest an estimated $2.4 billion on emission controls through 2018. Should we be able to recover these costs in future rate cases, we may experience a growth in earnings. Additionally, our service territory may require additional generation capacity. A new base-load generating plant has not been built within the State of Michigan in the last 20 years. Should our regulatory environment be conducive to such a significant capital expenditure, we may build or expand a new base- load facility, with an estimated cost of $1 billion to $2 billion.

The following variables, either in combination or acting alone, will impact our future results:

• amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals, or new legislation;

• our ability to reduce costs;

• variations in market prices of power, coal and gas;

• plant performance;

• economic conditions within the State of Michigan;

• weather, including the severity and frequency of storms; and

• levels of customer participation in the electric Customer Choice program.

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 adequately addressed. We will accrue as regulatory assets any future unrecovered generation-related fixed costs (stranded costs) due to electric Customer Choice that we believe are recoverable under Michigan legislation and MPSC orders. We cannot predict the outcome of these matters. See Note 4.

GAS UTILITY

Our Gas Utility segment consists of MichCon and Citizens Fuel Gas Company (Citizens), natural gas utilities subject to regulation by the MPSC. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.3 million residential, commercial and industrial customers in the State of Michigan. MichCon also has subsidiaries involved in the gathering and transmission of natural gas in northern Michigan. MichCon operates one of the largest natural gas distribution and transmission systems in the United States. Citizens distributes natural gas in Adrian, Michigan.

Factors impacting income: Gas Utility’s net income increased $37 million. The results reflect increased rates and the impacts in 2005 of the MPSC’s April 2005 gas cost recovery and final gas rate orders, partially offset by the effects of milder winter weather in 2006.

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
	2006			2005
(in Millions)
Operating Revenues	$	877		$	852
Cost of Gas		635			644
Gross Margin		242			208
Operation and Maintenance		121			123
Depreciation and Amortization		24			26
Taxes Other Than Income		15			13
Asset (Gains) and Losses, net		—			4
Operating Income		82			42
Other (Income) and Deductions		15			14
Income Tax Provision		17			15
Net Income	$	50		$	13
Operating Income as a Percent of Operating Revenues		9	%		5	%

Gross margins increased $34 million in the first quarter of 2006 compared to the prior year. Gross margins in 2006 were favorably affected by higher base rates as a result of the April 2005 final gas rate order, and revenue associated with the uncollectible expense tracking mechanism authorized by the MPSC, partially offset by the effects of milder winter weather in 2006 and customer conservation. 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.

	Three Months Ended
	March 31
	2006		2005
Gas Markets (in Millions)
Gas sales	$	795	$	773
End user transportation		45		45
		840		818
Intermediate transportation		16		16
Other		21		18
	$	877	$	852
Gas Markets (in Bcf)
Gas sales		66		84
End user transportation		44		50
		110		134
Intermediate transportation		164		134
		274		268

Operation and maintenance expense decreased $2 million due to DTE Energy parent company no longer allocating merger-related interest to MichCon effective in April 2005 and the 2005 disallowance of certain environmental costs due to the April 2005 final gas rate order, partially offset by increased uncollectible accounts receivables expense, 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 2005 final gas rate order provided revenue for an uncollectible expense tracking mechanism to mitigate some of the effect of increasing uncollectible expense.

Asset (gains) and losses, net decreased $4 million due to the 2005 disallowance of certain computer equipment and related depreciation resulting from the April 2005 final gas rate order.

Income taxes increased $2 million primarily due to higher income, partially offset by a lower effective tax rate in 2006.

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Outlook – Operating results are expected to vary as a result of factors such as regulatory proceedings, weather, changes in economic conditions, customer conservation, usage declines due to technology/efficiency, cost containment efforts and process improvements. Higher gas prices and economic conditions have resulted in continued pressure on receivables and working capital requirements partially mitigated by the GCR mechanism. 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 for the prior calendar year 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.

NON-UTILITY OPERATIONS

Power and Industrial Projects

Power and Industrial Projects is comprised primarily of our synfuel projects, projects that deliver utility-type services to industrial, commercial and institutional customers, and biomass energy projects. We produce synthetic fuel from nine synfuel plants and produce coke from two coke batteries. The production of synthetic fuel from all of our synfuel plants and the production of coke from our coke batteries generate production tax credits (assuming no phase-out or the passage of legislation). We provide utility-type services using project assets usually located on the customers’ premises in the steel, automotive, paper and pulp, airport and other industries. These services include pulverized coal injection, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. We own and operate four gas-fired peaking electric generating plants and a biomass-fired electric generating plant and operate one additional gas-fired power plant under contract. We develop, own and operate landfill recovery systems throughout the United States and also own a waste coal recovery business.

Factors impacting income: Power and Industrial Projects had a net loss of $2 million in the first quarter of 2006 as compared to net income of $68 million in the 2005 first quarter. The comparability of results is affected by the deferral of potential gains from selling interests in our synfuel plants.

	Three Months Ended
	March 31
(in Millions)	2006			2005
Operating Revenues	$	381		$	311
Operation and Maintenance		425			320
Depreciation and Amortization		26			25
Taxes other than Income		8			7
Asset (Gains) and Losses, Net		(5	)		(82	)
Operating Income (Loss)		(73	)		41
Other (Income) and Deductions		(1	)		(4	)
Minority Interest		(71	)		(53	)
Income Taxes
Provision		7			37
Production Tax Credits		(6	)		(7	)
		1			30
Net Income (Loss)	$	(2	)	$	68

Operating revenues increased $70 million in the first quarter of 2006, reflecting higher synfuel sales. Operating expenses associated with synfuel projects exceed operating revenues and therefore generate operating losses, which generally have been more than offset by the resulting production 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. We also had higher revenues due to the acquisition of increased interests in two of our existing non-synfuel facilities and the acquisition of new facilities.

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Operation and maintenance expense increased $105 million, reflecting costs associated with increased synfuel production, 2005 acquisitions of energy projects and coke operations.

Asset gains and losses, net decreased $77 million in the first quarter of 2006 due to a decrease in synfuel gains of $61 million and an impairment loss of $16 million for the write down of fixed assets and patents at our waste coal recovery business. The decrease in synfuel gains is due to the deferral of gains from synfuel sales and a reserve for refund of partner capital contributions due to the increase in oil prices. The following table displays the various pre-tax components that comprise the determination of gains recorded in the first quarters of 2006 and 2005 related to synfuels.

(in Millions)	Three Months Ended March 31
Components of Synfuel Gains	2006			2005
Gains associated with fixed payments	$	31		$	28
Gains associated with variable payments		50			41
Deferred gains on fixed and variable payments		(67	)		(41	)
Reserve on partner capital contributions		(40	)		—
Unrealized hedge gains (mark-to-market)
2005 hedge program		—			50
2006 hedge program		38			4
2007 hedge program		9			—
Net synfuel gains recorded during the period	$	21		$	82

Minority interest increased $18 million in 2006, 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 taxes decreased $29 million in 2006, reflecting lower pretax income due to higher synfuel gain reserves and the write down of fixed assets and patents of our waste coal recovery business, compared to pre-tax income in the first quarter of 2005.

Outlook - We may sell additional interests in our synfuel plants and take actions to maximize our expected synfuel cash flows from the effect of an oil price-related phase-out. Synfuel-related tax credits expire on December 31, 2007. At current oil prices, it may be uneconomic to operate most of the synfuel plants in the absence of the passage of legislation, as previously discussed.

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. We expect solid earnings from our on-site energy business in 2006.

In addition to production tax credits generated by our synfuels business, our coke battery and landfill gas recovery businesses also generated production tax credits that are subject to oil price-related phase-out. Due to the relative level of production tax credits generated by our coke battery and landfill gas recovery businesses, a partial or full phase-out of production tax credits in these two businesses is not expected to have a material adverse impact on our results of operations, cash flow, and financial condition.

Unconventional Gas Production

Unconventional Gas Production is primarily engaged in natural gas exploration, development and production. Our Unconventional Gas Production business produces gas from the Antrim and Barnett shales and sells most of the gas to the Fuel Transportation and Marketing segment.

Factors impacting income: Unconventional Gas Production net income was unchanged for the first quarter of 2006. Operating revenues increased $6 million due to a combination of higher overall gas

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prices and increased production from the Barnett shale. Operation and maintenance costs increased $3 million due to increased costs associated with our emerging Barnett shale presence and higher corporate overhead costs. Depreciation and amortization increased $2 million due to higher depletion expenses associated with higher gas production. Taxes other than income increased $1 million due to higher severance taxes resulting from higher gas prices and increased production. Other deductions increased $1 million due to higher interest costs.

	Three Months Ended
	March 31
	2006		2005
(in Millions)
Operating Revenues	$	22	$	16
Operation and Maintenance		9		6
Depreciation and Amortization		6		4
Taxes Other Than Income		3		2
Operating Income		4		4
Other (Income) and Deductions		3		2
Income Tax Provision		—		1
Net Income	$	1	$	1

Outlook – We expect to continue to develop our proved areas, test unproved areas and prudently add new acreage in Michigan and Texas. Results from the Barnett shale test wells drilled during 2005 are expected during mid 2006. We expect to invest a combined amount of approximately $100 million to $130 million in our unconventional gas business in 2006.

Fuel Transportation and Marketing

Fuel Transportation and Marketing consists of DTE Energy Trading, Coal Transportation and Marketing and the Pipelines, Processing and Storage business.

DTE Energy Trading focuses on physical power and gas marketing, structured transactions, enhancement of returns from DTE Energy’s power plants and the optimization of contracted natural gas pipelines and storage capacity positions. Our customer base is predominantly utilities, local distribution companies, large industrials, and other marketing and trading companies. We enter into derivative financial instruments as part of our marketing and hedging activities. 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. We utilize forwards, futures, swaps and option contracts to mitigate risk associated with our marketing and trading activity as well as for proprietary trading within defined risk guidelines. DTE Energy Trading is integral in providing commodity risk management services to the other unregulated businesses within DTE Energy.

Coal Transportation and Marketing 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. We recently initiated a new business line, coal mine methane extraction, in which we recover methane gas from mine voids for processing and delivery to natural gas pipelines, industrial users, or for small power generation projects.

Pipelines, Processing and 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 operations.

Factors impacting income: Fuel Transportation and Marketing net income increased $51 million in the first quarter of 2006, primarily as a result of the reversal of timing differences which negatively impacted 2005 in the DTE Energy Trading business.

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	Three Months Ended
	March 31
	2006			2005
(in Millions)
Operating Revenues	$	413		$	316
Fuel, Purchased Power and Gas		181			173
Operation and Maintenance		164			157
Depreciation and Amortization		3			1
Taxes Other Than Income		2			1
Operating Income (Loss)		63			(16	)
Other (Income) and Deductions		(1	)		(1	)
Income Tax Provision (Benefit)		23			(5	)
Net Income (Loss)	$	41		$	(10	)

Operating revenues increased $97 million in the first quarter of 2006 due to mark-to-market gains at DTE Energy Trading related to power marketing, gas storage and gas trading.

Fuel, purchased power and gas increased $8 million in the first quarter of 2006. During the first quarter of 2005, our earnings were negatively impacted by the economically favorable decision to delay previously planned withdrawals from gas storage due to a decrease in the current price for natural gas and an increase in the forward price for natural gas. In addition, we entered into forward power contracts to economically hedge certain physical and capacity power contracts. The financial impacts of these timing differences have begun to reverse and have favorably impacted results in the first quarter of 2006.

Operation and maintenance expenses increased $7 million in the first quarter of 2006 primarily as a result of increased coal purchases due to increased sales at Coal Transportation and Marketing.

Income tax provision increased $28 million in the first quarter of 2006 due to higher pre-tax income.

Outlook – We expect to continue to grow our Coal Transportation and Marketing and DTE Energy Trading businesses in a manner consistent with, and complementary to, the growth of our other business segments. However, a portion of our Coal Transportation and Marketing revenues and net income are dependent upon our synfuel operations and would be adversely impacted by reductions in synfuel production. Gas storage and transportation capacity enhances our ability to provide reliable and custom-tailored bundled services to large-volume end users and utilities. This capacity, coupled with the synergies from DTE Energy’s other businesses, positions the segment to add value and mitigate risks.

We expect to continue to grow our Pipeline, Processing and Storage business by expanding existing assets and developing new assets. Pipelines, Processing and Storage 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 with commercial in-service starting April 2006. Vector Pipeline has secured long-term market commitments to support an expansion project, for approximately 200 MMcf per day, with a projected in-service date of November 2007. Vector Pipeline expects to receive FERC approval in the second quarter of 2006. The Millennium Pipeline filed an application for FERC approval in August 2005. We increased our interest in the Millennium Pipeline from 10.5% to 26.5%, effective March 31, 2006.

Significant portions of the Fuel Transportation and Marketing portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as capacity positions of natural gas storage and pipelines and power transmission contracts. The financial instruments are deemed derivatives, whereas the gas inventory, pipelines and storage assets are not derivatives. As a result, we 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 does not coincide with the calendar and fiscal year, but runs annually from April of one year to March of the next year. Our strategy is to economically hedge the price risk of storage with over-the-counter forwards and futures. Current accounting rules require the marking to market of forward

18

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 generally 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.

CORPORATE & OTHER

Corporate & Other includes various corporate support functions such as accounting, legal and information technology services. As 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, assets held for sale, and energy related investments.

Factors impacting income: Corporate & Other’s losses increased $12 million in the 2006 first quarter due primarily to favorable adjustments due to settlements related to income tax audits recorded in the 2005 first quarter. Additionally results in both years reflect adjustments to normalize the effective income tax rate. A favorable adjustment of $3 million was recorded in the first quarter of 2006 as compared to a $6 million favorable adjustment in the 2005 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.

DISCONTINUED OPERATIONS

DTE Energy Technologies (Dtech) - We own Dtech, which assembled, marketed, distributed and serviced distributed generation products, provided application engineering, and monitored and managed 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. We recognized a net of tax restructuring loss of $23 million during the third quarter of 2005, primarily 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 of Dtech assets and exit costs. We anticipate completing the restructuring plan by mid-2006. See Note 3.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES

In the first quarter of 2006, we adopted new accounting rules for stock-based compensation. The cumulative effect of adopting these new accounting rules increased 2006 first quarter net income by $1 million. See Note 2.

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CAPITAL RESOURCES AND LIQUIDITY

	Three Months Ended
	March 31
(in Millions)	2006			2005
Cash and Cash Equivalents
Cash Flow From (Used For):
Operating activities:
Net income	$	136		$	122
Depreciation, depletion and amortization		225			208
Deferred income taxes		64			51
Gain on sale of synfuel and other assets, net		(21	)		(78	)
Working capital and other		209			110
		613			413
Investing activities:
Plant and equipment expenditures – utility		(264	)		(172	)
Plant and equipment expenditures – non-utility		(71	)		(26	)
Acquisitions, net of cash acquired		(23	)		—
Proceeds from sale of synfuel and other assets		101			65
Restricted cash and other investments		(3	)		21
		(260	)		(112	)
Financing activities:
Issuance of long-term debt and common stock		—			395
Redemption of long-term debt		(70	)		(628	)
Short-term borrowings, net		(193	)		36
Repurchase of common stock		(8	)		(9	)
Dividends on common stock and other		(95	)		(91	)
		(366	)		(297	)
Net Increase (Decrease) in Cash and Cash Equivalents	$	(13	)	$	4

Operating Activities

A majority of the Company’s operating cash flow is provided by our electric and gas utilities, which are significantly influenced by factors such as weather, electric Customer Choice, 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. The profiles vary from our synthetic fuels business, which we believe, subject to considerations discussed below, will provide up to approximately $1.2 billion of cash during 2006-2008 (assuming that there is no phase-out of synfuel tax credits or that legislation is passed), to new startups which, if successful, could require significant investment.

Cash from operations totaling $613 million in the 2006 first quarter was up $200 million from the comparable 2005 period. The operating cash flow comparison reflects an increase of $101 million in net income, after adjusting for non-cash items (depreciation, depletion, amortization, deferred taxes and gains) and a $99 million decrease in working capital and other requirements. Most of the decrease in working capital and other requirements was driven by the seasonal gas inventory reduction cycle in 2006 in our Energy Trading business, partially offset by increased working capital requirements at our utilities primarily due to Voluntary Employees Beneficiary Association (VEBA) contributions during the first quarter of 2006.

Outlook - We expect cash flow from operations to increase over the long-term primarily due to improvements from higher earnings at our utilities and sales of interests in our synfuel projects, partially offset by higher cash requirements on environmental and other utility capital as well as growth

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investments in our non-utility portfolio. We are likely to incur costs associated with implementation of our Performance Excellence Process, but we expect to realize long term net cost savings. We also may be impacted by the delayed collection of underrecoveries of our PSCR and GCR costs and electric and gas accounts receivable as a result of MPSC orders. Gas prices are likely to be a source of volatility with regard to working capital requirements for the foreseeable future. We are continuing our efforts to identify opportunities to improve cash flow through working capital initiatives.

Synfuel cash flow consists of variable and fixed payments from partners, proceeds from option hedges 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. Assuming that there is no production tax credit phase-out or that legislation is passed, cash flows from our synfuel business are expected to be approximately $1.2 billion in 2006 to 2008, including $300 million tax credit carryforward utilization by DTE Energy. The redeployment of this cash, to the extent received, represents a unique opportunity to increase shareholder value and strengthen our balance sheet. We expect to use any such cash to reduce 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 rating and outlook, and to replace the value of synfuel operations currently inherent in our share price. Unless oil prices drop significantly for the remainder of 2006 and 2007 or legislation is passed, the expected cash flow from the synfuel business will be less and will adversely impact this cash redeployment strategy, unless the Company identifies alternative sources of cash. If oil prices result in a phase-out of the synfuel tax credits, and assuming the previously discussed current level of economic hedges and an early cessation of synfuel production to minimize operating losses, there is a potential negative impact to cash flow of up to approximately $600 million in 2006 to 2008. Since 2004, we have spent approximately $105 million hedging our future synfuel cash flow.

Investing Activities

Net cash outflows relating to investing activities increased $148 million in the 2006 first quarter as compared to the 2005 first quarter. The 2006 change was primarily due to increased capital expenditures, partially offset by higher synfuel proceeds (a portion of which is subject to refund based on oil prices) and asset sales. The increase in capital expenditures was driven by environmental, nuclear fuel and other projects at Detroit Edison in addition to growth oriented projects across our non-utility segments.

Longer term, with the expected improvement at our utilities and assuming continued cash generation from the synfuel business, cash flows are expected to improve. We will continue to pursue opportunities to grow our businesses in a disciplined fashion if we can find opportunities that meet our strategic, financial and risk criteria.

Financing Activities

Net cash used for financing activities increased $69 million during the 2006 first quarter, compared to the same 2005 period, due mostly to a reduction in debt issuances.

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

21

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. Based on our 2005 goodwill impairment test, we determined that the fair value of our operating reporting units exceed their carrying value and no impairment existed.

As of March 31, 2006, our goodwill totaled $2.1 billion. The majority of our goodwill is allocated to our utility reporting units, with $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 have made certain assumptions for MichCon that incorporate earnings multiples used in the cash flow valuations. These assumptions may change as regulatory and market conditions change.

We also have $41 million of goodwill allocated to the Power and Industrial Projects reporting unit. The value of the Power and Industrial Projects reporting unit may be significantly impacted by any phase-out of tax credits related to our synfuel business. As of March 31, 2006, we have evaluated the impact of a partial phase-out of synfuel tax credits on our valuation assumptions. We have determined that the fair value of the Power and Industrial Projects reporting unit exceeds the carrying value and no impairment of goodwill exists. These assumptions may change as the value of synfuel tax credits change.

We will continue to monitor our estimates and assumptions regarding future cash flows. While we believe our assumptions are reasonable, actual results may differ from our projections.

NEW ACCOUNTING PRONOUNCEMENTS

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

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 activities,” 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 thereby not impacting income.

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

22

• “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 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 activities”, 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 2006:

													Other
	Trading Activities												Non-
	Proprietary			Structured			Economic						Trading
(in Millions)	Trading			Contracts			Hedges			Total			Activities			Total
MTM at December 31, 2005	$	(108	)	$	(136	)	$	(110	)	$	(354	)	$	(140	)	$	(494	)
Reclassed to realized upon settlement		(50	)		18			108			76			33			109
Changes in fair value recorded to income		75			40			(32	)		83			47			130
Amortization of option premiums		84			(1	)		—			83			—			83
Amounts recorded to unrealized income		109			57			76			242			80			322
Amounts recorded in OCI		—			15			—			15			57			72
Option premiums paid and other		24			3			—			27			—			27
MTM at March 31, 2006	$	25		$	(61	)	$	(34	)	$	(70	)	$	(3	)	$	(73	)

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, 2006. Amounts that relate to contracts that become due within twelve months are classified as current and all remaining amounts are classified as noncurrent.

23

																Other
	Trading Activities															Non-			Total
	Proprietary			Structured			Economic									Trading			Assets
(in Millions)	Trading			Contracts			Hedges			Eliminations			Totals			Activities			(Liabilities)
Current assets	$	168		$	102		$	111		$	(2	)	$	379		$	194		$	573
Noncurrent assets		7			36			121			—			164			89			253
Total MTM assets		175			138			232			(2	)		543			283			826
Current liabilities		(146	)		(129	)		(140	)		2			(413	)		(156	)		(569	)
Noncurrent liabilities		(4	)		(70	)		(126	)		—			(200	)		(130	)		(330	)
Total MTM liabilities		(150	)		(199	)		(266	)		2			(613	)		(286	)		(899	)
Total MTM net assets (liabilities)	$	25		$	(61	)	$	(34	)	$	—		$	(70	)	$	(3	)	$	(73	)

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 positions for which broker quotes are available. Although the NYMEX has currently quoted prices for the next 72 months, 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.

As a result of adherence to generally accepted accounting principles, the tables above do not include the expected favorable earnings impacts of certain non-derivative gas storage and power contracts. We entered into economically favorable transactions 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. As anticipated, the financial impact of this timing difference has reversed as 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 be fully realized by the end of 2007.

The table below shows the maturity of our MTM positions:

										Total
(in Millions)							2008 and			Fair
Source of Fair Value	2006			2007			Beyond			Value
Proprietary Trading	$	32		$	(8	)	$	1		$	25
Structured Contracts		(12	)		(46	)		(3	)		(61	)
Economic Hedges		21			(41	)		(14	)		(34	)
Total Energy Marketing & Trading		41			(95	)		(16	)		(70	)
Other Non-Trading Activities		61			(42	)		(22	)		(3	)
Total	$	102		$	(137	)	$	(38	)	$	(73	)

24

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 purchases of coal, uranium, and 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 Power and Industrial Project segment businesses are also subject to crude oil price risk. As previously discussed, production tax credits generated by DTE Energy’s synfuel, coke battery and landfill gas recovery operations are subject to phase-out if domestic crude oil prices reach certain levels. We have entered into a series of derivative contracts for 2006 through 2007 to economically hedge the impact of oil prices on a portion of our synfuel cash flow. See Note 7.

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 loss. 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. We utilize both external and internally generated credit assessments when determining the credit quality of our trading counterparties.

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 March 31, 2006, the Company had a floating rate debt to total debt ratio of approximately 12% (excluding securitized debt).

Foreign Currency Risk

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

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, 2006 by a hypothetical 10% and calculating the resulting change in

25

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	$	(6	)	$	6		Commodity contracts and options
Power Contracts	$	(16	)	$	16		Commodity contracts
Oil Contracts	$	41		$	(54	)	Commodity options
Interest Rate Risk	$	(275	)	$	298		Long-term debt
Foreign Currency Risk	$	2		$	(2	)	Forward contracts

CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures

Management of the Company carried out an evaluation, under the supervision and with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the 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 March 31, 2006, 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

There has been no change in the Company’s internal control over financial reporting during the quarter ended March 31, 2006 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

26

DTE Energy Company

Consolidated Statement of Operations (Unaudited)

	Three Months Ended
	March 31
(in Millions, Except per Share Amounts)	2006			2005
Operating Revenues	$	2,635		$	2,309
Operating Expenses
Fuel, purchased power and gas		1,060			969
Operation and maintenance		1,021			893
Depreciation, depletion and amortization		225			208
Taxes other than income		92			91
Asset (gains) and losses, net		(5	)		(76	)
		2,393			2,085
Operating Income		242			224
Other (Income) and Deductions
Interest expense		133			128
Interest income		(12	)		(14	)
Other income		(12	)		(12	)
Other expenses		10			11
		119			113
Income Before Income Taxes and Minority Interest		123			111
Income Tax Provision		58			38
Minority Interest		(71	)		(53	)
Income from Continuing Operations		136			126
Loss from Discontinued Operations, net of tax (Note 3)		(1	)		(4	)
Cumulative Effect of Accounting Change, net of tax (Note 2)		1			—
Net Income	$	136		$	122
Basic Earnings per Common Share (Note 5)
Income from continuing operations	$	.76		$	.72
Discontinued operations		—			(.02	)
Cumulative effect of accounting change		.01			—
Total	$	.77		$	.70
Diluted Earnings per Common Share (Note 5)
Income from continuing operations	$	.76		$	.72
Discontinued operations		—			(.02	)
Cumulative effect of accounting change		—			—
Total	$	.76		$	.70
Average Common Shares
Basic		177			174
Diluted		178			175
Dividends Declared per Common Share	$	.515		$	.515

See Notes to Consolidated Financial Statements (Unaudited)

27

DTE Energy Company

Consolidated Statement of Financial Position

	(Unaudited)
	March 31			December 31
	2006			2005
(in Millions)
ASSETS
Current Assets
Cash and cash equivalents	$	75		$	88
Restricted cash		99			122
Accounts receivable
Customer (less allowance for doubtful accounts of $159 and $136, respectively)		1,284			1,288
Accrued unbilled revenues		297			458
Collateral held by others		29			286
Other		570			549
Inventories
Fuel and gas		318			522
Materials and supplies		139			146
Deferred income taxes		203			257
Assets from risk management and trading activities		573			806
Other		193			160
		3,780			4,682
Investments
Nuclear decommissioning trust funds		678			646
Other		543			530
		1,221			1,176
Property
Property, plant and equipment		18,762			18,660
Less accumulated depreciation and depletion		(7,845	)		(7,830	)
		10,917			10,830
Other Assets
Goodwill		2,057			2,057
Regulatory assets		2,037			2,074
Securitized regulatory assets		1,314			1,340
Notes receivable		360			409
Assets from risk management and trading activities		253			316
Prepaid pension assets		186			186
Other		252			265
		6,459			6,647
Total Assets	$	22,377		$	23,335

See Notes to Consolidated Financial Statements (Unaudited)

28

DTE Energy Company
Consolidated Statement of Financial Position

	(Unaudited)
	March 31			December 31
	2006			2005
(in Millions, Except Shares)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	1,090		$	1,187
Accrued interest		121			115
Dividends payable		92			92
Accrued payroll		39			34
Short-term borrowings		647			943
Gas inventory equalization (Note 1)		158			—
Current portion of long-term debt, including capital leases		693			691
Liabilities from risk management and trading activities		569			1,089
Other		774			769
		4,183			4,920
Other Liabilities
Deferred income taxes		1,444			1,396
Regulatory liabilities		728			715
Asset retirement obligations (Note 1)		1,111			1,091
Unamortized investment tax credit		128			131
Liabilities from risk management and trading activities		330			527
Liabilities from transportation and storage contracts		307			317
Accrued pension liability		305			284
Deferred gains from asset sales		173			188
Minority interest		17			92
Nuclear decommissioning		90			85
Other		699			740
		5,332			5,566
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other		5,218			5,234
Securitization bonds		1,238			1,295
Equity-linked securities		175			175
Trust preferred-linked securities		289			289
Capital lease obligations		84			87
		7,004			7,080
Commitments and Contingencies (Notes 4, 7 and 8)
Shareholders’ Equity
Common stock, without par value, 400,000,000 shares authorized, 177,769,890 and 177,814,429 shares issued and outstanding, respectively		3,466			3,483
Retained earnings		2,602			2,557
Accumulated other comprehensive loss		(210	)		(271	)
		5,858			5,769
Total Liabilities and Shareholders’ Equity	$	22,377		$	23,335

See Notes to Consolidated Financial Statements (Unaudited)

29

DTE Energy Company

Consolidated Statement of Cash Flows (Unaudited)

	Three Months Ended
	March 31
	2006			2005
(in Millions)
Operating Activities
Net Income	$	136		$	122
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		225			208
Deferred income taxes		64			51
Gain on sale of interests in synfuel projects		(21	)		(82	)
Loss on sale of other assets, net		—			4
Partners’ share of synfuel project losses		(71	)		(71	)
Contributions from synfuel partners		70			47
Change in assets and liabilities, exclusive of changes shown separately (Note 1)		210			134
Net cash from operating activities		613			413
Investing Activities
Plant and equipment expenditures – utility		(264	)		(172	)
Plant and equipment expenditures – non-utility		(71	)		(26	)
Acquisitions, net of cash acquired		(23	)		—
Proceeds from sale of interests in synfuel projects		72			63
Proceeds from sale of other assets		29			2
Restricted cash for debt redemptions		23			52
Proceeds from sale of nuclear decommissioning trust fund assets		37			63
Investment in nuclear decommissioning trust funds		(47	)		(73	)
Other investments		(16	)		(21	)
Net cash used for investing activities		(260	)		(112	)
Financing Activities
Issuance of long-term debt		—			395
Redemption of long-term debt		(70	)		(628	)
Short-term borrowings, net		(193	)		36
Repurchase of common stock		(8	)		(9	)
Dividends on common stock		(91	)		(90	)
Other		(4	)		(1	)
Net cash used for financing activities		(366	)		(297	)
Net Increase (Decrease) in Cash and Cash Equivalents		(13	)		4
Cash and Cash Equivalents at Beginning of the Period		88			56
Cash and Cash Equivalents at End of the Period	$	75		$	60

See Notes to Consolidated Financial Statements (Unaudited)

30

DTE Energy Company

Consolidated Statement of Changes in Shareholders’ Equity and

Comprehensive Income (Unaudited)

										Accumulated
										Other
	Common Stock						Retained			Comprehensive
	Shares			Amount			Earnings			Loss			Total
(Dollars in Millions, Shares in Thousands)
Balance, December 31, 2005		177,814		$	3,483		$	2,557		$	(271	)	$	5,769
Net income		—			—			136			—			136
Dividends declared on common stock		—			—			(91	)		—			(91	)
Repurchase and retirement of common stock		(44	)		(8	)		—			—			(8	)
Net change in unrealized gains on derivatives, net of tax		—			—			—			62			62
Net change in unrealized losses on investments, net of tax		—			—			—			(1	)		(1	)
Unearned stock compensation and other					(9	)		—			—			(9	)
Balance, March 31, 2006		177,770			3,466			2,602			(210	)		5,858

The following table displays other comprehensive income (loss) for the three-month period ended March 31:

	2006			2005
(in Millions)
Net income	$	136		$	122
Other comprehensive income (loss), net of tax:
Net unrealized income (losses) on derivatives:
Gain (losses) arising during the period, net of taxes of $(25) and $27, respectively		46			(50	)
Amounts reclassified to earnings, net of taxes of $(9) and $(5), respectively		16			10
		62			(40	)
Net change in unrealized gain (loss) on investments, net of taxes of $1 and $(2)		(1	)		3
		61			(37	)
Comprehensive income	$	197		$	85

See Notes to Consolidated Financial Statements (Unaudited)

31

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited)

NOTE 1 — GENERAL

These consolidated financial statements should be read in conjunction with the notes to consolidated financial statements included in the 2005 Annual Report on Form 10-K.

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

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

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

Gains from Sale of Interests in Synthetic Fuel Facilities

Through March 2006, 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 production tax credits, and the value of such credits. Production tax credits are subject to phase-out if domestic crude oil prices reach certain levels. See Note 8 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. Until the gain recognition criteria are met, gains from selling interests in synfuel facilities are deferred. It is possible that gains will be deferred in the first, second and/or third quarters of each year until there is persuasive evidence that no tax credit phase-out will occur for the applicable calendar year. This could result in shifting earnings from earlier quarters to later quarters of a calendar year. We have recorded pre-tax gains from the sale of interests in synthetic fuel facilities totaling $21 million in the first quarter of 2006, compared to $82 million in the first quarter of 2005.

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. Additionally, based on estimates of tax credits allocated, our partners reimburse us (through the project entity) for the operating losses of the synfuel facilities, referred to as capital contributions. 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 and estimate the amount 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. See Note 8.

32

Asset Retirement Obligations

We have recorded asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and FASB Interpretation FIN No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. 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 legal retirement obligations for our synthetic fuel operations, gas production facilities, asphalt plant, gas gathering facilities and various other operations. We identified conditional retirement obligations for gas pipeline retirement costs and disposal of asbestos at certain of our power plants. To a lesser extent, we have conditional retirement obligations at certain service centers, compressor and gate stations, and PCB disposal costs within transformers and circuit breakers.

As to regulated operations, we believe that adoptions of SFAS No. 143 and FIN 47 result 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 first quarter of 2006 follows:

(in Millions)
Asset retirement obligations at December 31, 2005	$	1,091
Accretion		18
Liabilities incurred		2
Asset retirement obligations at March 31, 2006	$	1,111

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 March 31	2006			2005			2006			2005
Service Cost	$	16		$	16		$	15		$	14
Interest Cost		44			43			29			26
Expected Return on Plan Assets		(55	)		(54	)		(15	)		(17	)
Amortization of
Net loss		15			17			18			15
Prior service cost		2			2			(1	)		(1	)
Net transition liability		—			—			2			2
Net Periodic Benefit Cost	$	22		$	24		$	48		$	39

During the first quarter of 2006, we made cash contributions of $60 million to our postretirement health care and life insurance plans.

33

Gas in Inventory

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

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:

	Three Months Ended
	March 31
	2006			2005
(in Millions)
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	163		$	(267	)
Accrued unbilled receivable		161			84
Accrued GCR revenue		52			(25	)
Inventories		210			154
Accrued/Prepaid pensions		21			23
Accounts payable		(97	)		(29	)
Accrued PSCR refund		(22	)		(8	)
Exchange gas payable		(62	)		(62	)
Income taxes payable		(7	)		(20	)
General taxes		1			12
Risk management and trading activities		(373	)		64
Gas inventory equalization		158			278
Postretirement obligation		(36	)		19
Other assets		(23	)		(29	)
Other liabilities		64			(60	)
	$	210		$	134

Supplementary cash and non-cash information follows:

	Three Months Ended
	March 31
	2006		2005
(in Millions)
Cash Paid for
Interest (excluding interest capitalized)	$	127	$	123
Income taxes	$	1	$	1

We have entered into a Margin Loan Facility (Facility) with an affiliate of the clearing agent of a commodity exchange in lieu of posting additional cash collateral (a non-cash transaction). The loan outstanding under the Facility was $103 million as of March 31, 2006 and December 31, 2005, and the related margin deposit is included in “collateral held by others” on the consolidated statement of financial position at December 31, 2005. See Note 6.

34

NOTE 2 – NEW ACCOUNTING PRONOUNCEMENTS

Stock-Based Compensation

The DTE Energy Stock Incentive Plan permits the grant of incentive stock options, non-qualifying stock options, stock awards, performance shares and performance units. Participants in the plan include our employees and members of our Board of Directors. In the second quarter of 2006, we adopted a new Long-Term Incentive Program (LTIP). The following are the key points of the newly adopted LTIP:

• Authorized limit is 9,000,000 shares of common stock;

• Prohibits the grant of a stock option with an exercise price that is less than the fair market value of the Company’s stock on the date of the grant; and

• Imposes the following award limits to a single participant in a single calendar year, (1) options for more than 500,000 shares of common stock; (2) stock awards for more than 150,000 shares of common stock; (3) performance share awards for more than 300,000 shares of common stock (based on the maximum payout under the award); or (4) more than 1,000,000 performance units, which have a face amount of $1.00 each.

As of March 31, 2006, no performance units have been granted under either the LTIP or the previous stock incentive plan.

Effective January 1, 2006, we adopted SFAS No. 123(R), Share-Based Payment, using the modified prospective transition method. Under this method, we record compensation expense at fair value over the vesting period for all awards we grant after the date we adopted the standard. In addition, we are required to record compensation expense at fair value (as previous awards continue to vest) for the unvested portion of previously granted stock option awards that were outstanding as of the date of adoption. Pre-adoption awards of stock awards and performance shares will continue to be expensed. The adoption of SFAS 123(R) during the first quarter of 2006 resulted in the following:

• Income from continuing operations was reduced by $2 million;

• Net income was reduced by $1 million;

• Operating and financing cash flows were not materially impacted; and

• Had no material effect on basic or diluted earnings per share.

We recorded stock-based compensation expense of $7 million with an associated tax benefit of $2 million for the three months ended March 31, 2006. During the first quarter of 2005 we recorded stock-based compensation expense of $4 million with an associated tax benefit of $1 million. The cumulative effect of the adoption of SFAS 123(R) was an increase in net income of $1 million as a result of estimating forfeitures for previously granted stock awards and performance shares. We have not restated any prior periods as a result of the adoption of SFAS 123(R). We generally purchase shares on the open market for options that are exercised or we may settle in cash other stock based compensation.

Options

Options are exercisable according to the terms of the individual stock option award agreements and expire 10 years after the date of the grant. The option exercise price equals the fair value of the stock on the date that the option was granted. Stock option activity was as follows:

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						(In Millions)
				Weighted		Aggregate
	Number of			Average		Intrinsic
	Options			Exercise Price		Value
Outstanding at December 31, 2005		6,236,343		$	41.31
Granted		613,020			43.42
Exercised		(48,217	)		37.81
Forfeited or Expired		(46,072	)		43.09
Outstanding at March 31, 2006		6,755,074			41.51	$	12
Exercisable at March 31, 2006		5,115,643	(1)		41.05	$	11

(1)	As of March 31, 2006 and 2005, the weighted average remaining contractual life for the exercisable shares is 5.97 years and 6.33 years respectively.
(2)	During the first quarter of 2006 and 2005 1,086,474 and 843,604 options, respectively, vested during the period.

The weighted average grant date fair value of options granted during the first quarter of 2006 and 2005 was $6.13 and $5.87, respectively. The intrinsic value of options exercised for both the periods ending March 31, 2006 and 2005 were less than $1 million and $3 million, respectively. Total option expense recognized during the first quarter of 2006 was $3 million.

The number, weighted average exercise price and weighted average remaining contractual life of options outstanding were as follows:

			Weighted
		Weighted	Average
Range of	Number of	Average	Remaining
Exercise Prices	Options	Exercise Price	Contractual Life
$27.62 — $38.04	406,473	$31.30	3.65 years
$38.60 — $42.44	3,682,673	$40.64	6.50 years
$42.60 — $44.54	1,089,105	$43.08	7.82 years
$44.56 — $48.00	1,576,823	$45.09	7.21 years
	6,775,074	$41.51	6.71 years

We determine the fair value for these options at the date of grant using a Black-Scholes based option pricing model and the following assumptions:

	March 31			December 31
	2006			2005
Risk-free interest rate		4.58	%		3.93	%
Dividend yield		4.74	%		4.60	%
Expected volatility		19.79	%		19.56	%
Expected life	6 years			6 years
Fair value per option		$6.13			$5.89

In connection with the adoption of SFAS 123(R) we reviewed and updated our forfeiture, expected term and volatility assumptions. We modified option volatility to include both historical and implied share-price volatility. Implied volatility is derived from exchange traded options on DTE Energy common stock. Volatility for 2005 was estimated based solely upon historical share-price volatility. Our expected term is based on industry standards.

Pro forma information for the three months ended March 31, 2005 is provided to show what our net income and earnings per share would have been if compensation costs had been determined as prescribed by SFAS 123(R):

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	Three Months
	Ended
	March 31
(in Millions, except per share amounts)	2005
Net Income as reported	$	122
Less: Total stock-based expense		(2	)
Pro Forma Net Income	$	120
Earnings Per Share
Basic – as reported	$	.70
Basic – pro forma	$	.69
Diluted – as reported	$	.70
Diluted – pro forma	$	.69

Stock Awards

Stock awards granted under the plan are restricted for varying periods, which are generally for three years. Participants have all rights of a shareholder with respect to a stock award, including the right to receive dividends and vote the shares. Prior to vesting in stock awards, the participant: (i) may not sell, transfer, pledge, exchange or otherwise dispose of shares; (ii) shall not retain custody of the share certificates; and (iii) will deliver to us a stock power with respect to each stock award.

The stock awards are recorded at cost that approximates fair value on the date of grant. We account for stock awards as unearned compensation, which is recorded as a reduction to common stock. The cost is amortized to compensation expense over the vesting period. During the first quarter of 2006 and 2005 the fair value of awards vested was $4 million and $3 million respectively. Stock award activity for the periods ended March 31 was:

	2006		2005
Restricted common shares awarded		237,080		206,940
Weighted average market price of shares awarded	$	43.42	$	44.68
Compensation cost charged against income (in thousands)	$	2,070	$	1,750

The following table summarizes our stock awards activity for the three months ended March 31, 2006:

				Weighted Average
				Grant Date
	Restricted Stock			Fair Value
Balance at December 31, 2005		544,087		$	42.68
Grants		237,080		$	43.42
Forfeitures		(10,769	)	$	42.93
Vested		(88,186	)	$	41.60
Balance at March 31, 2006		682,212		$	43.71

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Performance Share Awards

Performance shares awarded under the plan are for a specified number of shares of common stock that entitles the holder to receive a cash payment, shares of common stock or a combination thereof. The final value of the award is determined by the achievement of certain performance objectives. The awards vest at the end of a specified period, usually three years. We account for performance share awards by accruing compensation expense over the vesting period based on: (i) the number of shares expected to be paid which is based on the probable achievement of performance objectives; and (ii) the fair value of the shares. For the periods ending March 31, 2006 and 2005, we recorded compensation expense totaling $2 million and $2 million respectively. In the first quarter of 2006 and 2005, we settled $4 million and $5 million (respectively) in performance share awards in cash which approximates the intrinsic value of the liability.

During the vesting period, the recipient of a performance share award has no shareholder rights. However, recipients will be paid an amount equal to the dividend equivalent on such shares. Performance share awards are nontransferable and are subject to risk of forfeiture. As of March 31, 2006, there were 1,133,854 performance share awards outstanding.

The following table summarizes our performance share activity for the three months ended March 31, 2006:

	Performance Shares
Balance at December 31, 2005		803,071
Grants		517,010
Forfeitures		(31,002	)
Payouts		(155,225	)
Balance at March 31, 2006		1,133,854

As of March 31, 2006, there was $37 million of total unrecognized compensation cost related to non-vested stock incentive plan arrangements. That cost is expected to be recognized over a weighted-average period of 1.87 years.

	(In millions)
	Unrecognized		Weighted Average to
Type	Compensation cost		be recognized
Stock Awards	$	17	1.92 years
Performance Shares		13	1.92 years
Options		7	1.68 years
	$	37	1.87 years

The tax benefit realized for tax deductions related to our stock incentive plan totaled less than $3 million for the three months ended March 31, 2006. No compensation cost was capitalized as a part of inventory and fixed assets during the 2006 first quarter period.

NOTE 3 — DISCONTINUED OPERATIONS AND IMPAIRMENT

Discontinued Operations — DTE Energy Technologies (Dtech)

We own Dtech, which assembled, marketed, distributed and serviced distributed generation products, provided application engineering, and monitored and managed 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.

During the third quarter of 2005, the restructuring plan met criteria to classify the assets as “held for sale.” Accordingly, we recognized a net of tax restructuring loss of $23 million during the third quarter of 2005 primarily representing the write down to fair value of the assets of Dtech, less costs to sell, and the write-off

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of goodwill of $16 million. As of March 31, 2006, Dtech assets are $5 million, consisting primarily of receivables and inventory, and liabilities are $6 million.

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

	Three Months Ended
(in millions)	March 31
	2006			2005
Revenues (1)	$	—		$	6
Expenses		(1	)		(11	)
Loss before taxes		(1	)		(5	)
Income tax benefit		—			1
(Loss) from Discontinued Operations	$	(1	)	$	(4	)

(1) Includes intercompany revenues of $1 million for 2005.

Impairment

During the first quarter of 2006, our Power and Industrial Projects segment impaired its investment in proprietary technology used to refine waste coal. The fixed assets at our development operation were impaired due to continued operating losses and negative cash flow. In addition, we impaired all our patents related to waste coal technology. We recorded a pre-tax impairment loss of $16 million within the Asset (gains) and losses, net, line in the consolidated statement of operations. We based this decision utilizing expected undiscounted cash flows from the use and eventual disposition of the assets and determined that the carrying amount of the investment exceeded the expected fair value.

NOTE 4 — 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. In December 2005, the MPSC issued an order that did not provide for the comprehensive realignment of the existing rate structure that Detroit Edison requested in its rate restructuring proposal. The MPSC order did take some initial steps to improve the current competitive imbalance in Michigan’s electric Customer Choice program. The December 2005 order establishes cost-based power supply rates for Detroit Edison’s full service customers. Electric Customer Choice participants will pay cost-based distribution rates, while Detroit Edison’s full service commercial and industrial customers will pay cost-based distribution rates that reflect the cost of the residential rate subsidy. Residential customers continue to pay a subsidized below cost rate for distribution service. These revenue neutral revised rates were effective February 1, 2006. Detroit Edison was also ordered to file a general rate case by July 1, 2007, based on 2006 actual results.

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

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before the MPSC. In February 2006, the MPSC denied Detroit Edison’s request and ordered that this issue be addressed in the next general rate case.

2004 PSCR Reconciliation and 2004 Net Stranded Cost Case

In accordance with the MPSC’s direction in Detroit Edison’s November 2004 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 prior authorized methodology from the last rate order, Detroit Edison incurred approximately $112 million in stranded costs for 2004. Detroit Edison also made approximately $218 million in third party wholesale sales.

In the filing, Detroit Edison proposed the following distribution of the $218 million of third party wholesale sale revenues: $91 million to offset associated 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. In April 2006, an MPSC Administrative Law Judge issued a Proposal for Decision indicating that Detroit Edison’s position in the combined cases is overstated. If this proposal is adopted by the MPSC, net income would be reduced by approximately $17 million. A final order is expected mid-year 2006.

MPSC Show-Cause Order

In March 2006, the MPSC issued an order directing Detroit Edison to show cause by June 1, 2006 why its retail electric rates should not be reduced in 2007. The MPSC cited certain changes that have occurred since the November 2004 order in Detroit Edison’s last general rate case or are expected to occur. These changes include: declines in electric Customer Choice program participation, expiration of the residential rate caps, and projected reductions in Detroit Edison operating costs. The show-cause filing is to reflect sales, costs and financial conditions that are expected to occur by 2007. A final order is expected by the end 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 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. In September 2005, the MPSC approved Detroit Edison’s 2005 PSCR plan case. At December 31, 2005, Detroit Edison has recorded an under-recovery of approximately $144 million related to the 2005 plan year. In March 2006, Detroit Edison filed its 2005 PSCR reconciliation. The filing seeks approval for recovery of approximately $144 million from its commercial and industrial customers. The filing included a motion for entry of an order to implement immediately a reconciliation surcharge of 4.96 mills per kWh on the bills of its commercial and industrial customers. The under-collected PSCR expense allocated to residential customers could not be recovered due to the PA 141 rate cap for residential customers, which expired January 1, 2006. In addition to the 2005 PSCR Plan Year Reconciliation, the filing included a reconciliation

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for the Pension Equalization Mechanism (PEM) for the periods from November 24, 2004 through December 31, 2004 and from January 1, 2005 through December 31, 2005. The PEM reconciliation seeks to allocate and refund approximately $12 million to customers based upon their contributions to pension expense during the subject periods.

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. The Company’s PSCR Plan includes a matrix which provides for different maximum PSCR factors contingent on varying electric Customer 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 a fuel additive. In conjunction with DTE Energy’s sale of the transmission assets of ITC in February 2003, the FERC froze ITC’s transmission rates through December 2004. In approving the sale, FERC authorized ITC recovery of the difference between the revenue it would have collected and the actual revenue ITC did collect during the rate freeze period. At December 31, 2005 this amount is estimated to be $66 million which is to be included in ITC’s rates over a five-year period beginning June 1, 2006. It is expected that this amortization will increase Detroit Edison’s transmission expense in 2006 by $7 million. The MPSC authorized Detroit Edison in 2004 to recover transmission expenses through the PSCR mechanism.

In December 2005, the MPSC issued a temporary order authorizing the Company to begin implementation of maximum quarterly PSCR factors on January 1, 2006. The quarterly factors reflect a downward adjustment in the Company’s total power supply costs of approximately 2% to reflect the potential variability in cost projections. The quarterly factors will allow the Company to more closely track the costs of providing electric service to our customers and, because the non-summer factors are well below those ordered for the summer months, effectively delay the higher power supply costs to the summer months at which time our customers will not be experiencing large expenditures for home heating. The MPSC did not adopt the Company’s request to recover its projected 2005 PSCR under-collection associated with commercial and industrial customers nor did it adopt the Company’s request to implement contingency factors based upon the Company’s increased costs associated with providing electric service to returning electric Customer Choice customers. The MPSC deferred both of those Company proposals to the final order on the Company’s entire 2006 PSCR Plan.

Administrative and General Expenses Report to the MPSC

In October 2005, the MPSC ordered Detroit Edison to file a report on why its administrative and general expenses appear to be higher than levels incurred by Consumers Energy, Michigan’s other major electric utility. On February 1, 2006, a report was filed that explained Detroit Edison’s administrative and general expense differences, as well as its overall cost and rate competitiveness.

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:

• lengthen the period of time before a bill is due once it is transmitted to the customer;

• prohibit shut off or late payment fees unless an actual meter read is made;

• limit the required monthly payment on a settlement agreement;

• increase the income level qualifying for shut-off protection and lower the payment required to remain on shut-off protection; and

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• lessen or eliminate certain deposit requirements.

Uncollectible Expense Tracker Mechanism and Report of Safety and Training-Related Expenditures

In March 2006, MichCon filed an application with the MPSC for approval of its uncollectible expense tracking mechanism for 2005 and review of 2005 annual safety and training-related expenditures. This is the first filing MichCon has made under the uncollectible tracking mechanism, which was approved by the MPSC in April 2005 as part of MichCon’s last general rate case. MichCon’s 2005 base rates included $37 million for anticipated uncollectible expenses. Actual 2005 uncollectible expenses for Michcon totaled $60 million. The tracker mechanism allows MichCon to recover 90 percent of uncollectibles that exceeded that $37 million base. Under the formula prescribed by the MPSC, MichCon has asked to recover approximately $11 million in uncollectible expenses for 2005 pro-rated from May 2005 (when the mechanism took effect) through the end of 2005. If approved by the MPSC, the underrecovery will be recovered from customers through a monthly surcharge. MichCon reported that actual safety and training-related expenditures for the initial period exceeded the pro-rated expenditures in base rates and recommended no refund at this time.

Gas Cost Recovery Proceedings

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 under-recovery with interest MichCon had accrued for the period ending March 31, 2005. In March 2006, MPSC Staff filed testimony recommending an adjustment to the accounting treatment of the injected base gas remaining in the New Haven storage field when it was sold in early 2004 that would result in a $3 million reduction to MichCon’s accrued underrecovery. 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 gas 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.

In response to market price increases in the fall of 2005, MichCon filed a petition to reopen the record in the case during September 2005. 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.

2006-2007 Plan Year – In December 2005, MichCon filed its 2006-2007 GCR plan case proposing a maximum GCR Factor of $12.15 per Mcf. The plan includes quarterly contingent GCR factors. These contingent factors, if approved by the MPSC, will allow MichCon to increase the maximum GCR factor to compensate for increases in market prices, thereby reducing the possibility of a GCR under-recovery.

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Other

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

NOTE 5 — EARNINGS PER SHARE

We report both basic and diluted earnings per share. Basic earnings per share is computed by dividing income from continuing operations by the weighted average number of common shares outstanding during the period. Diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period and the repurchase of common shares that would have occurred with proceeds from the assumed issuance. Diluted earnings per share assume the exercise of stock options, vesting of non-vested stock awards, and in 2005, the issuance of performance share awards. A reconciliation of both calculations is presented in the following table:

	Three Months Ended
	March 31
(in Millions, except per share amounts)	2006		2005
Basic Earnings Per Share
Income from continuing operations	$	136	$	126
Average number of common shares outstanding		177.2		173.7
Income per share of common stock based on weighted average number of shares outstanding	$	.76	$	.72
Diluted Earnings Per Share
Income from continuing operations	$	136	$	126
Average number of common shares outstanding		177.2		173.7
Incremental shares from stock based awards		.5		.9
Average number of dilutive shares outstanding		177.7		174.6
Income per share of common stock assuming issuance of incremental shares	$	.76	$	.72

Options to purchase approximately 2.2 million shares of common stock in 2006 and 100,000 shares of common stock in 2005, 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 6 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

In conjunction with maintaining certain exchange traded risk management positions, we may be required to post cash collateral with our clearing agent. We have entered into a Margin Loan Facility (Facility) with an affiliate of the clearing agent of up to $103 million as of March 31, 2006. We entered into this facility in lieu of posting cash. This facility was backed by a letter of credit issued by DTE Energy in the amount of $100 million. Any margin requirement in excess of the Facility is funded in cash by DTE Energy. The amount outstanding under the Facility is subject to an interest rate at a per annum rate of interest equal to the LIBOR rate, plus 0.75%, calculated daily. The amount outstanding under the Facility was $103 million as of March 31, 2006 and December 31, 2005. The amounts were shown as “Collateral held by others” and “Short-term borrowings” in the consolidated statement of financial position at December 31, 2005. Effective March 31,

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2006, the facility agreement was amended to provide for the netting of all positions and payments under the Facility.

NOTE 7 — DERIVATIVE INSTRUMENTS

Commodity Price Risk

Certain Power and Industrial Projects segment businesses generate production tax credits. We have sold interests in all nine of our synthetic fuel production plants. Proceeds from the sales are contingent upon production levels, the production qualifying for production tax credits, and the value of such credits. Production tax credits are subject to phase out if domestic crude oil prices reach certain levels. See Note 8.

To manage our exposure in 2006 and 2007 to the risk of an increase in oil prices that could reduce or eliminate 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’ 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 2006 and 2007 are less than approximately $58, and $60, per barrel, respectively, the derivatives will yield no payment. If the average NYMEX prices of oil exceed approximately $58, and $60, per barrel, respectively, the derivatives will yield a payment equal to the excess of the average NYMEX price over these initial strike prices, multiplied by the number of barrels covered, up to a maximum price of approximately $73, and $71 per barrel, respectively. The agreements do not qualify for hedge accounting. Consequently, changes in the fair value of the options are recorded currently in earnings. 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. We recorded a mark to market pre-tax gain of $47 million in the 2006 first quarter, compared to a mark to market pre-tax gain of $54 million in the 2005 first quarter.

NOTE 8 — 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. Production tax credits are provided for the production and sale of solid synthetic fuels produced from coal. To qualify for the production 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 production tax credits.

To reduce U.S. dependence on imported oil, the Internal Revenue Code provides production 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. During 2005, the monthly average wellhead price per barrel of oil for the year was 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 2006, we estimate the threshold price at which the tax credit would begin to be reduced is $53 per barrel and would be completely phased out if the Reference Price reached $67 per barrel. As of May 1, 2006, the realized and unrealized NYMEX daily closing price of a barrel of oil was approximately $72, equating to an estimated Reference Price of $66, which is within the

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phase-out range. The average NYMEX daily closing price of a barrel of oil would have to average less than approximately $56 for the remainder of 2006 in order that no phase-out of production tax credits occurs. Unless oil prices drop significantly for the remainder of 2006 or legislation is passed, we would experience a partial or full phase-out of the production tax credits resulting in a reduction in the net income and cash flow from our synfuel business. A phase-out could have an impact on our synthetic fuel production plans which, in turn, may have a material adverse impact on our results of operations, cash flow, and financial condition and investment strategy. However, we cannot predict with any certainty the Reference Price for the remainder of 2006 or beyond.

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 2006 and 2007, we entered into oil-related derivative contracts for a portion of our exposure. See Note 7.

Through March 31, 2006, we have generated and recorded approximately $562 million in synfuel tax credits.

Environmental

Electric Utility

Air - Detroit Edison is subject to 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 $644 million through 2005. We estimate Detroit Edison future capital expenditures at up to $218 million in 2006 and up to $2.2 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 December 31, 2005, the expiration of the rate cap period.

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 four to six years in additional capital expenditures for Detroit Edison.

Contaminated Sites - 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 estimated cost to remediate these sites is approximately $13 million which was accrued in 2005 and is expected to be incurred over the next several years.

Gas Utility

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. Gas Utility owns, or previously owned, 15 such former manufactured gas plant (MGP) sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, we are also in the process of cleaning up other contaminated sites. Cleanup activities associated with these sites will be conducted over the next several years.

In 1993, a cost deferral and rate recovery mechanism was approved by the MPSC for investigation and remediation costs incurred at former MGP sites in excess of this reserve. Gas Utility employed outside consultants to evaluate remediation alternatives for these sites, to assist in estimating its potential liabilities

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and to review its archived insurance policies. As a result of these studies, Gas Utility accrued an additional liability and a corresponding regulatory asset of $35 million during 1995. During 2005, we spent approximately $4 million investigating and remediating these former MGP sites. In December 2005, we retained multiple environmental consultants to estimate the projected cost to remediate each MGP site. We accrued an additional $9 million in remediation liabilities associated with two of our MGP sites, to increase the reserve balance to $35 million at December 31, 2005.

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 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.

Other

Our non-utility affiliates are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants. We are in the process of installing new environmental equipment at our coke battery facilities in Michigan. We expect the projects to be completed within two years at a cost of approximately $25 million. Our other non-utility affiliates are substantially in compliance with all environmental requirements.

Guarantees

In certain limited 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 $35 million at March 31, 2006.

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, oil price 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 March 31, 2006 is $2.0 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 $413 million at March 31, 2006. 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

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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 a 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 and the Michigan Department of Treasury that is expected to lead to settlement of all outstanding property tax disputes on a global basis.

On December 8, 2005 executed Stipulations for Consent Judgment, Consent Judgments, and Schedules to Consent Judgment were filed with the MTT on behalf of Detroit Edison, MichCon and a significant number of the largest jurisdictions, in terms of tax dollars, involved in the litigation. The filing of these documents fulfilled the requirements of the global settlement agreement and resolves a number of claims by the litigants against each other including both property and non-property issues. The global settlement agreement resulted in a pre-tax economic benefit to DTE Energy of $43 million in 2005 that included the release of a litigation reserve.

Income Taxes

The Internal Revenue Service is currently conducting audits of our federal income tax returns for the years 2002 and 2003. The Company accrues tax and interest related to tax uncertainties that arise due to actual or potential disagreements with governmental agencies about the tax treatment of specific items. At March 31, 2006, the Company had accrued approximately $38 million for such uncertainties. We believe that our accrued tax liabilities are adequate for all years.

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. We purchased $42 million of steam and electricity in 2005 and 2004 and $39 million in 2003. We estimate steam and electric purchase commitments through 2024 will not exceed $427 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.

As of December 31, 2005, we were party to 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 $6.7 billion through 2051. We also estimate that 2006 base level capital expenditures will be $1.2 billion. We have made certain commitments in connection with expected capital expenditures.

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

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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 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 4 for a discussion of contingencies related to Regulatory Matters.

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NOTE 9 — SEGMENT INFORMATION

We operate our businesses through three strategic business units, Electric Utility, Gas Utility and Non-utility operations (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 billing for goods and services exchanged between segments is based upon tariffed or market-based prices of the provider and primarily consists of power sales, gas sales and coal transportation services in the Electric Utility, Unconventional Gas Production and Fuel Transportation and Marketing segments.

	Three Months Ended
(in Millions)	March 31
	2006			2005
Operating Revenues
Electric Utility	$	1,050		$	990
Gas Utility		877			852
Non-utility Operations:
Power and Industrial Projects		381			311
Unconventional Gas Production		22			16
Fuel Transportation and Marketing		413			316
		816			643
Corporate & Other		2			4
Reconciliation & Eliminations		(110	)		(180	)
Total	$	2,635		$	2,309
Income (Loss)
Electric Utility	$	59		$	55
Gas Utility		50			13
Non-utility Operations:
Power and Industrial Projects		(2	)		68
Unconventional Gas Production		1			1
Fuel Transportation and Marketing		41			(10	)
Corporate & Other		(13	)		(1	)
Income from Continuing Operations
Utility		109			68
Non-utility		40			59
Corporate & Other		(13	)		(1	)
		136			126
Discontinued Operations (Note 3)		(1	)		(4	)
Cumulative Effect of Accounting Change (Note 2)		1			—
Net Income	$	136		$	122

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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. 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 were seeking damages (in Canadian dollars) of approximately $49 billion for alleged negligence, approximately $4 billion per year until the defendants cease emitting pollutants, punitive and exemplary damages of $1 billion, and such other relief as the court deemed appropriate. Detroit Edison was never served with the complaint as required by Canadian rules of civil procedure. As a result, this action has lapsed procedurally.

Risk Factors

Our ability to utilize production tax credits may be limited. We have generated production tax credits from our synfuel, coke battery, landfill gas recovery and gas production operations. We have received favorable private letter rulings on all of our synfuel facilities. All production tax credits taken after 2001 are subject to audit by the Internal Revenue Service (IRS). If our production tax credits were disallowed in whole or in part as a result of an IRS audit, there could be additional tax liabilities owed for previously recognized tax credits that could significantly impact our earnings and cash flows. The value of future credits generated may be affected by proposed legislation. Moreover, production tax credits related to generation of synfuels expire at the end of 2007. The combination of IRS audits of production tax credits, supply and demand for investment in credit producing activities and proposed legislation could have an impact on our earnings and cash flows. We have also provided certain guarantees and indemnities in conjunction with the sales of interests in our synfuel facilities.

The value of a production 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 production 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 2005, the monthly average wellhead prices were approximately $6 lower than the New York Mercantile Exchange (NYMEX) price for light, sweet crude oil. As of May 1, 2006, the realized and unrealized NYMEX daily closing price of a barrel of oil was approximately $72 for 2006, equating to an estimated Reference Price of $66, which is estimated to be within the phase-out range. The average NYMEX daily closing price of a barrel of oil would have to average less than approximately $56 for the remainder of 2006 in order that no phase-out of production tax credits occur. Unless oil prices drop significantly for the remainder of 2006 and/or legislation passes that as proposed would result in no phase-out for 2006, we would experience a partial or full phase-out of the production tax credits, resulting in a reduction in the net income and cash flow from our synfuel business. A phase-out could have an adverse impact on our synthetic fuel production plans which, in turn, may have a material adverse impact on our results of operations, cash flow, and financial condition. However, we cannot predict with any certainty the Reference Price for the remainder of 2006 or beyond.

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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 quarter ended March 31, 2006:

					Total Number of		Maximum Dollar
					Shares Purchased		Value that May Yet
	Total Number		Average		as Part of Publicly		Be Purchased Under
	of Shares		Price Paid		Announced Plans		the Plans or
Period	Purchased (1)		Per Share		or Programs		Programs (2)
01/01/06 - 01/31/06		—		—		—	$	700,000,000
02/01/06 - 02/28/06		—		—		—	$	700,000,000
03/01/06 - 03/31/06		199,555		42.77		—	$	700,000,000
Total		199,555		42.77		—

(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.
(2)	The DTE Energy Board authorized the repurchase of up to $700 million in common stock through 2008. The authorization provides Company management with flexibility to pursue share repurchase from time to time, and will depend on future cash flows and investment opportunities.

Exhibits

Exhibit
Number	Description
Filed:
12-37	Computation of Ratio of Earnings to Fixed Charges
31-23	Chief Executive Officer Section 302 Form 10-Q Certification
31-24	Chief Financial Officer Section 302 Form 10-Q Certification
Incorporated by reference:
10-63	DTE Energy Company 2006 Long-Term Incentive Plan (incorporated herein by reference to Annex A to DTE Energy’s Definitive Proxy Statement dated March 24, 2006).
Furnished:
32-23	Chief Executive Officer Section 906 Form 10-Q Certification
32-24	Chief Financial Officer Section 906 Form 10-Q Certification

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	DTE ENERGY COMPANY
Date: May 10, 2006	/s/ PETER B. OLEKSIAK Peter B. Oleksiak
	Controller and
	Chief Accounting Officer

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EXHIBIT INDEX

EXHIBIT NO.	DESCRIPTION
12-37	Computation of Ratio of Earnings to Fixed Charges
31-23	Chief Executive Officer Section 302 Form 10-Q Certification
31-24	Chief Financial Officer Section 302 Form 10-Q Certification
32-23	Chief Executive Officer Section 906 Form 10-Q Certification
32-24	Chief Financial Officer Section 906 Form 10-Q Certification