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

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.

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). (Check one):

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).

At March 31, 2007, 176,064,812 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, 2007

TABLE OF CONTENTS

						Page
Definitions							1
Forward-Looking Statements							3
Part I — Financial Information
Item 1.				Financial Statements
				Consolidated Statement of Operations			31
				Consolidated Statement of Financial Position			32
				Consolidated Statement of Cash Flows			34
				Consolidated Statement of Changes in Shareholders’ Equity and Comprehensive Income			35
				Notes to Consolidated Financial Statements			36
Item 2.				Management’s Discussion and Analysis of Financial Condition and Results of Operations			4
Item 3.				Quantitative and Qualitative Disclosures About Market Risk			27
Item 4.				Controls and Procedures			30
Part II — Other Information
Item 1A.				Risk Factors			56
Item 2.				Unregistered Sales of Equity Securities and Use of Proceeds			57
Item 6.				Exhibits			57
Signature							58
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
CTA		Costs to achieve, consisting of project management, consultant support and employee severance, related to the Performance Excellence Process
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)
MDEQ		Michigan Department of Environmental Quality
MichCon		Michigan Consolidated Gas Company (an indirect wholly owned subsidiary of DTE Energy) and subsidiary companies
MISO		Midwest Independent System Operator, a Regional Transmission Organization
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
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.
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.

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.
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.
Subsidiaries		The direct and indirect subsidiaries of DTE Energy Company
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

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 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, including potential new federal and state requirements that could include carbon and more stringent mercury emission controls, a renewable portfolio standard and energy efficiency mandates;
	•		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 negotiation and impacts 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, including any associated impact on rate structures;
	•		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;
	•		binding arbitration, litigation and related appeals;
	•		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;
	•		timing, terms and proceeds from any asset sale or monetization; and
	•		implementation of new processes and new core information systems.

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

DTE ENERGY COMPANY
Management’s Discussion and Analysis
of Financial Condition and Results of Operations

OVERVIEW

DTE Energy is a diversified energy company with 2006 revenues in excess of $9 billion and approximately $24 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, distribution and storage services throughout southeastern Michigan. We operate five energy-related non-utility segments with operations throughout the United States.

Net income in the first quarter of 2007 was $134 million, or $.76 per diluted share, compared to net income of $136 million, or $.76 per diluted share, in the first quarter of 2006. The decrease in net income is primarily due to lower earnings at the Electric Utility, Energy Trading and Corporate & Other segments, offset by higher earnings at the Gas Utility, Power and Industrial Projects and Synthetic Fuel segments.

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;
•		Impact of regulatory decisions on our utility operations;
•		Investments in our Unconventional Gas Production business;
•		Results in our Power and Industrial Projects business;
•		Results in our Energy Trading business;
•		Synfuel-related earnings;
•		Outcome of monetization efforts in our non-utility businesses; and
•		Cost reduction efforts and required capital investment.

UTILITY OPERATIONS

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.

Our Gas Utility segment consists of MichCon and Citizens Fuel Gas Company (Citizens). 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. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.

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. During the first quarter of 2007, we experienced colder weather than in the first quarter of 2006.

Additionally, we frequently experience various types of storms that damage our electric distribution infrastructure resulting in power outages. Restoration and other costs associated with storm-related power outages lowered pretax earnings by approximately $15 million in the first quarter of 2007 as compared to 2006.

Receivables - Both utilities continue to experience high levels of past due receivables, especially within our Gas Utility operations, primarily attributable to economic conditions and a lack of adequate levels of

assistance for low-income customers.

We have taken aggressive actions to reduce the level of past due receivables, including increasing 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. During the three months ended March 31, 2007, we did not sell any previously written-off accounts, while in the first quarter of 2006, we sold previously written-off accounts of $44 million, resulting in a gain and net proceeds of $2 million. The gain was recorded as a recovery through bad debt expense, which is included within Operation and maintenance expense. While our levels of past due receivables remain high, we experienced a decrease in our allowance for doubtful accounts expense for the two utilities to approximately $29 million for the three months ended March 31, 2007, compared to $40 million for the corresponding period of 2006.

The April 2005 MPSC gas rate order provided for an uncollectible true-up mechanism for MichCon. The uncollectible true-up mechanism enables MichCon to recover ninety percent of the difference between the actual uncollectible expense for each year and $37 million after an annual reconciliation proceeding before the MPSC. The MPSC approved the 2005 annual reconciliation on December 21, 2006 allowing MichCon to surcharge $11 million beginning in January 2007. We filed the 2006 annual reconciliation with the MPSC in the first quarter of 2007 requesting recovery of $34 million. The following table provides the current amount outstanding and status of each respective year:

(in
Millions)
		Balance at				Balance at
Year		March 31, 2007				December 31, 2006				Current Regulatory Filing Status
2005 (1)		$	8			$	11			Approved in December 2006; actively billing customers
2006 (2)			34				34			Reconciliation filed with the MPSC in March 2007
2007 (2)			13				—			Accruing; reconciliation filing scheduled for first quarter 2008
Total		$	55			$	45

Regulatory activity — Pursuant to the February 2006 MPSC order in Detroit Edison’s rate restructuring case and the August 2006 MPSC order in the settlement of the show cause case, Detroit Edison filed a general rate case on April 13, 2007 based on a 2006 historical test year. The filing with the MPSC requests a $123 million, or 2.9%, average increase in Detroit Edison’s annual revenue requirement for 2008. See Note 6 of the Notes to Consolidated Financial Statements.

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 issued an order approving a settlement agreement in this proceeding on August 31, 2006. The order provided for an annualized rate reduction of $53 million for 2006, effective September 5, 2006. Beginning January 1, 2007, and continuing until April 13, 2008, one year from the filing of the general rate case on April 13, 2007, rates were reduced by an additional $26 million, for a total reduction of $79 million annually. Detroit Edison experienced a rate reduction of approximately $18 million in the three months ended March 31, 2007 as a result of this order. The revenue reduction is net of the recovery of the amortization of the costs associated with the implementation of the Performance Excellence Process. The settlement agreement provides for some level of realignment of the existing rate structure by allocating a larger percentage of the rate reduction to the commercial and industrial customer classes than to the residential customer classes.

NON-UTILITY OPERATIONS

We have made significant investments in non-utility asset-intensive businesses. We employ disciplined investment criteria when assessing opportunities that leverage our assets, skills and expertise. Specifically, we invest in targeted energy markets with attractive competitive dynamics where meaningful

scale is in alignment with our risk profile. A number of factors have impacted our non-utility businesses including the effect of oil prices on the synthetic fuel business, losses and impairments from certain power generation assets and waste coal recovery and landfill gas recovery businesses, and earnings volatility in our energy trading business. As part of a strategic review of our non-utility operations, we are considering various actions including the sale, restructuring or recapitalization of various non-utility businesses which we expect may generate at least $800 million in cash proceeds in 2007. In estimating the expected cash proceeds, we have considered the potential cost to resolve certain inter-company and third party arrangements. These arrangements are currently at below market prices.

The primary source of recent investment capital in our non-utility operations has been cash flow from the synfuel business. See the “Outlook” section for information on sources of cash flows from the synfuel business.

Coal and Gas Midstream

Coal and Gas Midstream consists of Coal Transportation and Marketing and the Pipelines, Processing and Storage businesses.

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 marketing and coal-to-power tolling transactions, as well as the purchase and sale of emissions credits. We perform 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.

We are continuing to build our capacity to transport greater amounts of western coal and to expand into coal terminals to allow for increased coal storage and blending. We are currently involved in a contract dispute with BNSF Railway Company that has been referred to arbitration. Under this contract, BNSF transports western coal east for Detroit Edison and the Coal Transportation and Marketing business. We have filed a breach of contract claim against BNSF for the failure to provide certain services that we believe are required by the contract. An arbitration hearing in this matter ended in April 2007. A decision which is subject to an appeal process is expected in June 2007. While we believe we will prevail on the merits in this matter, a negative decision could have an adverse effect on our ability to grow the Coal Transportation and Marketing business as currently contemplated.

Pipelines, Processing and Storage owns a partnership interest in an interstate transmission pipeline, six carbon dioxide processing facilities and two natural gas storage fields. The pipeline and storage assets are primarily supported by stable, long-term fixed price revenue contracts. The assets of these businesses are well integrated with other DTE Energy operations. Pursuant to an operating agreement, MichCon provides physical operations, maintenance and technical support for the Washington 28 and Washington 10 storage facilities.

Pipelines, Processing and Storage is continuing its steady growth plan of expansion of storage capacity in Michigan, with two new expansions and expanding and building new pipeline capacity to serve markets in the Midwest and northeast United States.

Unconventional Gas Production

Our Unconventional Gas Production business is engaged in natural gas exploration, development and production primarily within the Antrim shale in the northern lower peninsula of Michigan and the Barnett shale in north Texas. We are an experienced operator in the Antrim shale where we manage one of the industry’s largest inventories of proved gas shale reserves. We continue to expand our operations in the Barnett shale basin in north Texas, where recent leasehold acquisitions have increased our total leasehold acreage to 89,808 acres (80,530 net of interest of others.) Current natural gas prices provide attractive opportunities for our Unconventional Gas Production business segment. We continue to develop properties in both areas as we explore monetization alternatives. We are exploring the sale of a portion of our Unconventional Gas Production assets which will allow us to monetize value from our more mature holdings, while retaining the ability to benefit from the upside of our earlier stage holdings.

Antrim shale — We intend to develop existing acreage using the latest vertical and horizontal drilling and fracture stimulation techniques. Our long-term fixed-price obligations for production of Antrim continue to expire in 2007. This will create opportunities to remarket Antrim production at significantly higher current market rates. As of March 31, 2007, we have a series of cash flow hedges for 84.3 Bcf of anticipated Antrim gas production through October 2013 at an average price of $3.92 per Mcf.

Barnett shale - We anticipate significant opportunities in our existing Barnett shale acreage and expect continued extension of producing areas within the basin. We are currently in the test and development phase for unproven and recently acquired Barnett shale acreage.

Current natural gas prices and successes within the Barnett shale are resulting in more capital 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 provide an advantage in addressing potential cost increases. We invested approximately $27 million in the first quarter of 2007 and expect to invest a combined amount of approximately $150 million to $170 million in our unconventional gas business in 2007.

As a component of our risk management strategy for our Barnett shale reserves, we hedged a portion of our proved developed producing reserves to secure an attractive investment return. As of March 31, 2007, we have a series of cash flow hedges for 7.7 Bcf of anticipated Barnett gas production through 2010 at an average price of $7.61 per Mcf.

Power and Industrial Projects

Power and Industrial Projects is comprised primarily of projects that deliver utility-type services to industrial, commercial and institutional customers, and biomass energy projects. We provide utility-type services using project assets usually located on the customers’ premises in the steel, automotive, pulp and paper, airport and other industries. These services include pulverized coal and petroleum coke supply, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. We own and operate three gas-fired peaking electric generating plants and a biomass-fired electric generating plant and operate one additional gas-fired power plant under contract. Additionally, we own a gas-fired peaking electric generating plant that was taken out of service in September 2006. We develop, own and operate landfill gas recovery systems throughout the United States. We produce metallurgical coke from two coke batteries. The production of coke from our coke batteries generates production tax credits.

We are exploring the combination of a sale of an equity interest in, and recapitalization of, some of the assets of the Power and Industrial Projects business, including the sale or restructuring of the power generation assets. In February 2007, we entered into an agreement to sell our Georgetown peaking electric generating facility. The sale is subject to receipt of regulatory approval and is expected to close in the second half of 2007.

Energy Trading

Energy Trading focuses on physical power and gas marketing and trading, 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, 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. Energy Trading provides commodity risk management services to the other businesses within DTE Energy.

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 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 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 may incur mark-to-market accounting gains or losses in one period that will reverse in subsequent periods when transactions are settled. We are exploring strategic options for the energy trading business.

Synthetic Fuel

Synthetic Fuel Operations

We are the operator of nine synthetic fuel production facilities throughout the United States. Synfuel plants chemically change coal and waste 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 and are available through December 31, 2007. The synthetic fuel plants generate operating losses which we expect to be offset by production tax credits. The value of a production tax credit is adjusted annually by an inflation factor and published annually by the Internal Revenue Service (IRS). The value is reduced if the Reference Price of a barrel of oil exceeds certain thresholds.

Recognition of Synfuel Gains

To optimize income and cash flow from the synfuel operations, we sold interests in all nine of the facilities, representing 91% of the total production capacity as of March 31, 2007. Proceeds from the sales are contingent upon production levels and the value of credits generated. Gains from the sale of an interest in a synfuel project are recognized when there is persuasive evidence that the sales proceeds have become fixed or determinable, the probability of refund is considered remote and collectibility is assured. In substance, we receive synfuel gains and reduced operating losses in exchange for tax credits associated with the projects sold.

The gain from the sale of synfuel facilities is generally comprised of fixed and variable components. The fixed component represents note payments, 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 and is subject to refund based on the annual oil price phase-out. The variable component is recognized as a gain only when the probability of refund is considered remote and collectibility is assured.

Contractual Partners’ Obligations

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 an amount equal to 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 the Reference Price of oil for the year being within or exceeding the phase-out range. Since we expect to be in a production tax credit phase out position in 2007, we have recorded a reserve of $16 million for partners’ capital contributions in the first quarter of 2007 as compared to a reserve of $40 million in the first quarter of 2006. In the 2007 first quarter, we recorded a reduction in the reserve of $22 million for a prior year true up.

Crude Oil Prices

The Reference Price of a barrel of oil is an estimate by the IRS of the annual average wellhead price per barrel for domestic crude oil. The value of the production tax credit in a given year is reduced if the Reference Price of oil over the year exceeds a threshold price and is eliminated entirely if that same Reference Price exceeds a phase-out price. During 2007, the annual average wellhead price is projected to

be approximately $6 less 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 2006 and 2007 are as follows:

				Beginning Phase-Out		Ending Phase-Out
		Reference Price		Price		Price
2006 (actual)		$59.68		$55.06		$69.12
2007 (estimated)		Not Available		$56		$70

The NYMEX daily closing price of a barrel of oil for the three months ended March 31, 2007 averaged approximately $66, which is approximately equal to a Reference Price of $60 per barrel, which we estimate to be within the phase-out range. The actual tax credit phase-out for 2007 will not be certain until the Reference Price is published by the IRS in April 2008. There is a risk of at least a partial phase-out of the production tax credits in 2007, which could adversely impact our results of operations, cash flow, and financial condition.

Hedging of Synfuel Cash Flows

As discussed in Note 2 of the Notes to Consolidated Financial Statements, we have entered into derivative and other contracts to economically hedge a portion of our synfuel cash flow exposure 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. To manage our exposure in 2007 to the risk of an increase in oil prices that could substantially 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 2007 calendar year average 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 2007 are less than approximately $60 per barrel, the derivatives will yield no payment. If the average NYMEX prices of oil exceed approximately $60 per barrel, 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 $76 per barrel. These contracts are based on various terms to take advantage of increases in oil prices. We recorded pretax mark-to-market gains of $4 million during the three months ended March 31, 2007 and gains of $47 million during the three months ended March 31, 2006. The fair value changes are recorded as adjustments to the gain from selling interests in synfuel facilities and are included in the Asset gains and losses, reserves and impairments, net line item in the Consolidated Statement of Operations. We paid approximately $50 million for 2006 hedges, for which we received payments of approximately $156 million upon settlement of these hedges in January 2007. Through March 31, 2007, we paid approximately $113 million for 2007 hedges which will provide protection for a significant portion of our cash flows related to synfuel production during 2007.

Risks and Exposures

Since there is the likelihood that the Reference Price for a barrel of oil will reach the threshold at which synfuel-related production tax credits began to phase-out, we defer gain recognition associated with variable and certain fixed note payments until the probability of refund is remote and collectibility is assured. All or a portion of the deferred gains will be recognized when and if the gain recognition criteria is met. During the three months ended March 31, 2007 and 2006, fixed gains recognized totaled $33 million and $22 million, respectively. During the three months ended March 31, 2007 variable gains recognized totaled $6 million, whereas we recognized variable losses totaling $8 million for the comparable 2006 three month period. Gains and losses recognized in both three month periods were impacted by prior year true ups.

Additionally, we may establish reserves for potential refunds of amounts related to partners’ capital contributions associated with operating losses allocated to their account. In the event of a tax credit phase-out, we are contractually obligated to refund to our partners all or a portion of the operating losses funded by our partners. During the three months ended March 31, 2007, we refunded approximately $8 million to our partners, representing $5 million of capital contributions and $3 million related to variable gains.

Cash from synfuel activity is at risk of a phase-out of the production tax credits. We expect approximately $900 million of synfuel-related cash impacts from 2007 through 2009, which consists of cash from operations, asset sales and proceeds from option hedges, and approximately $500 million of tax credit carryforward utilization and other tax benefits that are expected to reduce future tax payments. The expected cash flow of approximately $900 million is economically hedged against the movement in oil prices. In addition, a goodwill write-off of up to $4 million will likely be required in 2007 due to the inability to generate new production tax credits after 2007 and the resulting discontinuance of synfuel production. We have fixed notes receivable associated with the sales of interests in the synfuel facilities. A partial or full phase-out of production tax credits could adversely affect the collectibility of our receivables and likely reduce our ability to execute our investment and growth strategy.

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.

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 is 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. In order to fully realize the benefits from the Performance Excellence Process, it is necessary to make significant up-front investments in our infrastructure and business processes. The costs to achieve (CTA) in 2006 exceeded our savings, but we expect to realize sustained net cost savings beginning in 2007.

In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison and MichCon, commencing in 2006, to defer the incremental CTA. Further, the order provides for Detroit Edison and MichCon to amortize the CTA deferrals over a ten-year period beginning with the year subsequent to the year the CTA was deferred. Detroit Edison deferred approximately $102 million of CTA in 2006 as a regulatory asset and began amortizing deferred 2006 costs in 2007 as the recovery of these costs was provided for by the MPSC in the order approving the settlement in the show cause proceeding. Amortization of prior year deferred CTA costs amounted to $2.5 million during the three months ended March 31, 2007. During the three months ended March 31, 2007, CTA costs of $13 million were deferred. MichCon cannot defer CTA costs at this time because a recovery mechanism has not been established.

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 approximately $4.3 billion, including increased environmental requirements and reliability enhancement projects during the period of 2007 through 2011. Our gas utility currently expects to invest approximately $1.0 billion on system expansion, pipeline safety and reliability enhancement projects through the same period. We recently launched a six-year, approximately $330 million, advanced metering infrastructure project that involves the replacement and/or modification of some 4 million electric and gas customer meters. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment.

ENTERPRISE BUSINESS SYSTEMS

In 2003, we began the development of our Enterprise Business Systems (EBS) project, an enterprise resource planning system initiative to improve existing processes and to implement new core information systems, relating to finance, human resources, supply chain and work management. As part of this initiative, we are implementing EBS software including, among others, products developed by SAP AG and MRO Software, Inc. The first phase of implementation occurred in 2005 in the regulated electric fossil generation unit. The second phase of implementation began in April 2007. The conversion of data and the implementation and operation of EBS will be continuously monitored and reviewed and should ultimately strengthen our internal control structure and lead to increased cost efficiencies. Although our implementation plan includes detailed testing and contingency arrangements to ensure a smooth and successful transition, we can provide no assurance that complications will not arise that could interrupt our operations.

Through March 2007, we spent approximately $375 million on this project and we anticipate spending an additional approximately $10 million in 2007 as the remaining system elements are developed and implemented. We expect the benefits of lower costs, faster business cycles, repeatable and optimized processes, enhanced internal controls, improvements in inventory management and reductions in system support costs to outweigh the expense of our investment in this initiative.

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 at the federal level. However, the expected industry consolidation, resulting in the creation of large regional utility providers, has been recently impacted by actions of regulators in certain states affected by the proposed transactions.

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

Along with pursuing a leaner organization, we anticipate approximately $900 million of synfuel-related cash impacts from 2007 through 2009, which consists of cash from operations and proceeds from option hedges, and approximately $500 million of tax credit carryforward utilization and other tax benefits that are expected to reduce future tax payments. The redeployment of this cash represents a unique opportunity to increase shareholder value and strengthen our balance sheet. We expect to use such cash and the potential cash from monetization of certain of our non-utility assets and operations to reduce debt and repurchase common stock, and to continue to pursue growth investments that meet our strict risk-return and value creation criteria. Our objectives for cash redeployment are to strengthen the balance sheet and coverage ratios to improve our current credit rating and outlook, and to have any monetizations be accretive to earnings per share.

RESULTS OF OPERATIONS

Net income in the first quarter of 2007 was $134 million, or $.76 per diluted share, compared to net income of $136 million, or $.76 per diluted share, in the first quarter of 2006. The following sections provide a detailed discussion of the operating performance and future outlook of our segments.

Segments realigned — In the third quarter of 2006, we realigned the non-utility segment Power and Industrial Projects business unit to separately present the Synthetic Fuel business. In the fourth quarter of 2006, we separated the Fuel Transportation and Marketing segment into Coal and Gas Midstream and Energy Trading. See Note 9 of the Notes to Consolidated Financial Statements for further information on this realignment.

(in Millions, except per share data)		2007				2006
Net Income by Segment:
Electric Utility		$	40			$	59
Gas Utility			67				50
Non-utility Operations:
Coal and Gas Midstream			12				13
Unconventional Gas Production			2				1
Power and Industrial Projects			4				(23	)
Energy Trading			1				28
Synthetic Fuel			38				21
Corporate & Other			(30	)			(13	)
Income (Loss) from Continuing Operations:
Utility			107				109
Non-utility			57				40
Corporate & Other			(30	)			(13	)
			134				136
Discontinued Operations			—				(1	)
Cumulative Effect of Accounting Change			—				1
Net Income		$	134			$	136

ELECTRIC UTILITY

Our Electric Utility segment consists of Detroit Edison.

Factors impacting income: Net income decreased $19 million in the first quarter of 2007 primarily due to increased depreciation and amortization expenses, higher operation and maintenance expenses, and an increase in reserves.

		Three Months Ended
		March 31
		2007				2006
(in Millions)
Operating Revenues		$	1,094			$	1,050
Fuel and Purchased Power			354				309
Gross Margin			740				741
Operation and Maintenance			348				344
Depreciation and Amortization			182				167
Taxes Other Than Income			72				69
Asset (Gains), Losses and Reserves, Net			7				—
Operating Income			131				161
Other (Income) and Deductions			71				75
Income Tax Provision			20				27
Net Income		$	40			$	59
Operating Income as a Percent of Operating Revenues			12	%			15	%

Gross margin declined $1 million in the first quarter of 2007 due to lower rates resulting primarily from the August 2006 settlement in the MPSC show cause proceeding that provided for an annualized rate reduction of $53 million effective in September 2006 and an additional annualized rate reduction of $26 million effective in January 2007. Gross margins were also lower due to poor economic conditions, partially offset by higher margins due to returning sales from electric Customer Choice and the impacts of colder weather in the first quarter of 2007. Revenues include a component for the cost of power sold that is recoverable through the PSCR mechanism.

The following table displays changes in various gross margin components relative to the comparable prior period:

Increase (Decrease) in Gross Margin Components Compared to Prior Year		Three Months
(in Millions)
Weather related margin impacts		$	8
Return of customers from electric Customer Choice			17
Service territory economic performance			(14	)
Impact of MPSC rate orders			(18	)
Other, net			6
Decrease in gross margin		$	(1	)

		Three Months Ended
		March 31
Power Generated and Purchased		2007				2006
(in Thousands of MWh)
Power Plant Generation
Fossil			10,557				9,308
Nuclear			2,428				2,197
			12,985				11,505
Purchased Power			1,233				1,513
System Output			14,218				13,018
Less Line Loss and Internal Use			(784	)			(825	)
Net System Output			13,434				12,193
Average Unit Cost ($/MWh)
Generation (1)		$	15.41			$	14.66
Purchased Power		$	63.88			$	50.42
Overall Average Unit Cost		$	19.62			$	18.82

		Three Months Ended
(in Thousands of MWh)		March 31
		2007				2006
Electric Sales
Residential			3,786				3,836
Commercial			4,309				4,008
Industrial			3,374				3,154
Wholesale			735				675
Other			110				106
			12,314				11,779
Interconnections sales (1)			1,120				414
Total Electric Sales			13,434				12,193
Electric Deliveries
Retail and Wholesale			12,314				11,779
Electric Customer Choice			451				1,139
Electric Customer Choice — Self Generators (2)			67				224
Total Electric Sales and Deliveries			12,832				13,142

Operation and maintenance expense increased $4 million in the first quarter of 2007 due primarily to higher storm expense of $15 million, partially offset by lower generation expenses of $5 million and lower corporate support allocation charges of $6 million.

Depreciation and amortization expense was higher by $15 million in the first quarter of 2007 due primarily to increased amortization of regulatory assets of $10 million consisting of $4 million for the amortization of regulatory assets, $3 million related to the electric Customer Choice Incentive mechanism and $3 million for the amortization of CTA, and higher depreciation of $1 million due to higher levels of depreciable plant.

Asset (gains), losses and reserves, net were $7 million in the first quarter of 2007 representing a reserve for a loan guaranty related to the prior sale of Detroit Edison’s steam heating business to Thermal Ventures II, LP.

Outlook — We continue to improve the operating performance of Detroit Edison. We have resolved a portion of our regulatory issues and continue to pursue additional regulatory and/or legislative solutions for structural problems within the Michigan market structure, primarily electric Customer Choice and the need to adjust rates for each customer class to reflect the full cost of service.

Concurrently, we will move forward in our efforts to continue to improve performance. Looking forward, additional issues, such as rising prices for coal, health care and higher levels of 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 Energy Operating System and the Performance Excellence Process to seek opportunities to improve productivity, remove waste and 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. We intend to seek recovery of these costs in future rate cases.

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 coal or nuclear facility. While we have not decided on construction of a new base-load nuclear facility, in February 2007, we announced that we will prepare a license application for construction and operation of a new nuclear power plant on the site of Fermi 2. By completing the license application before the end of 2008, we may qualify for financial incentives under the federal Energy Policy Act of 2005. We are also studying the possible transfer of a gas-fired peaking electric generating plant from our non-utility operations to our electric utility to support future power generation requirements.

The following variables, either in combination or acting alone, could 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 and maximize plant performance;
	•		variations in market prices of power, coal and gas;
	•		economic conditions within the State of Michigan;
	•		weather, including the severity and frequency of storms;
	•		levels of customer participation in the electric Customer Choice program; and
	•		potential new federal and state environmental requirements.

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 6 of the Notes to Consolidated Financial Statements.

In January 2007, the MPSC submitted the State of Michigan’s 21^st Century Energy Plan to the Governor of Michigan. The plan recommends that Michigan’s future energy needs be met through a combination of renewable resources and cleanest generating technology, with significant energy savings achieved by increased energy efficiency. The plan also recommends:

	•		a requirement that all retail electric suppliers obtain at least 10 percent of their energy supplies from renewable resources by 2015;
	•		an opportunity for utility-built generation, contingent upon the granting of a certificate of need and competitive bidding of engineering, procurement and construction services;
	•		investigating the cost of a requirement to bury certain power lines; and
	•		creation of a Michigan Energy Efficiency Program, administered by a third party under the direction of the MPSC with initial funding estimated at $68 million.

We continue to review the energy plan and are unable to predict the impact on the Company of the implementation of the plan.

GAS UTILITY

Our Gas Utility segment consists of MichCon and Citizens.

Factors impacting income: Net income increased $17 million in the first quarter of 2007 due primarily to higher gross margin and lower operation and maintenance expenses.

		Three Months Ended
		March 31
		2007				2006
(in Millions)
Operating Revenues		$	874			$	877
Cost of Gas			623				635
Gross Margin			251				242
Operation and Maintenance			111				121
Depreciation and Amortization			21				24
Taxes Other Than Income			14				15
Asset (Gains), Losses and Reserves, Net			3				—
Operating Income			102				82
Other (Income) and Deductions			12				15
Income Tax Provision			23				17
Net Income		$	67			$	50
Operating Income as a Percent of Operating Revenues			12	%			9	%

Gross margin increased $9 million in the first quarter of 2007. The increase is due to $17 million representing the impacts of colder weather in 2007, $11 million related to an increase in midstream services including storage and transportation, partially offset by a $16 million unfavorable impact in lost gas recognized and $3 million related to customer conservation. Revenues include a component for the cost of gas sold that is recoverable through the GCR mechanism.

		Three Months Ended
		March 31
		2007				2006
Gas Markets (in Millions)
Gas sales		$	773			$	795
End user transportation			52				45
			825				840
Intermediate transportation			19				16
Other			30				21
		$	874			$	877
Gas Markets (in Bcf)
Gas sales			70				66
End user transportation			49				44
			119				110
Intermediate transportation			128				164
			247				274

Operation and maintenance expense was lower by $10 million due to lower uncollectible accounts receivable expense primarily due to improved customer payment trends resulting from increased collection efforts.

Depreciation and amortization expenses were lower by $3 million due to an adjustment resulting from an MPSC order related to pipeline assets.

Asset (gains), losses and reserves, net increased $3 million attributable to an MPSC disallowance of certain costs related to the acquisition of pipeline assets.

Outlook — Operating results are expected to vary due to regulatory proceedings, weather, changes in economic conditions, customer conservation and process improvements. Higher gas prices and economic conditions have resulted in continued pressure on receivables and working capital requirements that are partially mitigated by the MPSC’s uncollectible true-up mechanism and GCR mechanism.

We will utilize the DTE Energy Operating System and the Performance Excellence Process to seek opportunities to improve productivity, remove waste and decrease our costs while improving customer satisfaction.

NON-UTILITY OPERATIONS

Coal and Gas Midstream

Our Coal and Gas Midstream segment consists of Coal Transportation and Marketing and the Pipelines, Processing and Storage businesses.

Factors impacting income: Net income was $1 million lower in the first quarter of 2007 principally due to increased interest expense related to the debt assumed in October 2006 from the acquisition of the Washington 10 gas storage field. The changes in operating revenues and operation and maintenance expenses were both higher reflecting increased coal marketing activities.

		Three Months Ended
		March 31
(in Millions)		2007				2006
Operating Revenues		$	227			$	168
Operation and Maintenance			206				147
Depreciation and Amortization			2				2
Taxes other than Income			1				2
Operating Income			18				17
Other (Income) and Deductions			(1	)			(3	)
Income Tax Provision			7				7
Net Income		$	12			$	13

Outlook — We expect to continue to grow our Coal Transportation and Marketing business in a manner consistent with, and complementary to, the growth of our other business segments. A portion of our Coal Transportation and Marketing revenues and net income are dependent upon our Synfuel operations. Coal Transportation and Marketing is involved in a contract dispute with BNSF Railway Company that has been referred to arbitration. See Note 8 of the Notes to Consolidated Financial Statements.

Our Pipeline, Processing and Storage business will continue its steady growth plan. In April 2007, Washington 28 received MPSC approval to increase working gas storage capacity by over 6 Bcf to a total of 16 Bcf. In February 2007, Washington 10 filed an application with the MPSC to develop a storage field which would increase working gas storage capacity by 8 Bcf to a total of 74 Bcf. Vector Pipeline has secured long-term market commitments to support its first phase of an expansion project, for approximately 200 MMcf per day, with a projected in-service date of November 2007. Vector Pipeline received FERC approval for this expansion in October 2006. Pipeline, Processing and Storage has a 26% ownership interest in Millennium Pipeline which received FERC approval for construction and operation in December 2006. Millennium Pipeline is scheduled to be in service in late 2008. We plan to expand existing assets and develop new assets which are typically supported with long-term customer commitments.

Unconventional Gas Production

Our Unconventional Gas Production segment is primarily engaged in natural gas exploration, development and production in the Antrim and Barnett shales and sells most of the gas to the Energy Trading segment.

Factors impacting income: Net income increased $1 million in the first quarter of 2007 due primarily to higher Barnett shale production. Barnett production in the first quarter of 2007 was 1.5 Bcfe of natural gas compared to .5 Bcfe in the first quarter of 2006.

		Three Months Ended
		March 31
		2007				2006
(in Millions)
Operating Revenues		$	28			$	22
Operation and Maintenance			11				9
Depreciation, Depletion and Amortization			7				6
Taxes Other Than Income			3				3
Operating Income			7				4
Other (Income) and Deductions			4				3
Income Tax Provision			1				—
Net Income		$	2			$	1

Outlook — We expect to continue to develop our proved areas and test unproved areas in Michigan and Texas. Evaluation of Barnett shale test wells in up to three new areas is ongoing. During 2007, we expect Barnett Shale production of over 8 Bcfe of natural gas compared with approximately 4 Bcfe in 2006 and Antrim Shale production roughly equivalent to the 22 Bcfe produced in 2006. We expect to invest a combined amount of approximately $150 million to $170 million in our Unconventional Gas Production business in 2007. We are exploring the sale of a portion of our Unconventional Gas Production assets which will allow us to monetize value from our more mature holdings, while retaining the ability to benefit from the upside of our earlier stage holdings.

Power and Industrial Projects

Our Power and Industrial Projects segment is comprised primarily of projects that deliver utility-type services to industrial, commercial and institutional customers, and biomass energy projects.

Factors impacting income: Net income was $4 million in the first quarter of 2007 as compared to a loss of $23 million in the first quarter of 2006. The 2006 period included an impairment loss of $16 million for the write down of fixed assets and patents at our waste coal recovery business.

		Three Months Ended
		March 31
(in Millions)		2007				2006
Operating Revenues		$	110			$	107
Operation and Maintenance			90				95
Depreciation and Amortization			11				13
Taxes other than Income			4				3
Asset (Gains) and Losses, Reserves and Impairments, Net			—				16
Operating Income (Loss)			5				(20	)
Other (Income) and Deductions			3				5
Minority Interest			1				—
Income Taxes
Provision (Benefit)			1				(1	)
Production Tax Credits			(4	)			(1	)
			(3	)			(2	)
Net Income (Loss)		$	4			$	(23	)

Operating revenues increased $3 million due primarily to a one-time success fee for the sale of an asset in the first quarter of 2007, partially offset by lower revenue due to reduced volumes at several projects.

Operation and maintenance expense decreased $5 million resulting from lower costs due to reduced volumes at several projects.

Asset (gains) and losses, reserves and impairments, net decreased in the first quarter of 2007 due to the impairment loss of $16 million for the write down of fixed assets and patents at our waste coal recovery business in the first quarter of 2006.

Outlook — Power and Industrial Projects will continue leveraging its extensive energy-related operating experience and project management capability to develop and grow the on-site energy business. The coke battery and landfill gas recovery businesses generate production tax credits that are subject to an oil price-related phase-out. Due to the relatively low level of production tax credits generated by our coke battery and landfill gas recovery business, 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 Consolidated Statements of Operations, Cash Flow and Financial Position. We are exploring the combination of a sale of an equity interest in, and recapitalization of, some of the assets of the Power and Industrial Projects business, including the sale or restructuring of the power generation assets. In February 2007, we entered into an agreement to sell our Georgetown peaking electric generating facility. The sale is subject to receipt of regulatory approval and is expected to close in the second half of 2007.

Energy Trading

Our Energy Trading segment 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.

Factors impacting income: Net income was lower by $27 million due to lower gross margins on realized sales in the first quarter of 2007.

		Three Months Ended
		March 31
		2007				2006
(in Millions)
Operating Revenues		$	212			$	245
Fuel, Purchased Power and Gas			193				185
Gross Margin			19				60
Operation and Maintenance			13				13
Depreciation and Amortization			1				1
Operating Income			5				46
Other (Income) and Deductions			3				2
Income Tax Provision			1				16
Net Income		$	1			$	28

Gross margin declined $41 million in the first quarter of 2007. Declining natural gas prices at the end of 2006 contributed to positive mark-to-market timing differences in the fourth quarter of 2006 and resulted in lower margins on realized sales in the first quarter of 2007. Earnings in the first quarter of 2006 were favorably impacted by realized margins from storage withdrawals and mark-to-market gains from trades to economically hedge certain physical and capacity power contracts.

Outlook - Significant portions of the Energy Trading 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 and full requirements contracts. The financial instruments are deemed derivatives, whereas the owned gas inventory, pipelines, transmission contracts, certain full requirements contracts 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 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 manage the price risk of storage with over-the-counter forwards and futures. This results in gains and losses that are recognized in different interim and annual accounting periods. We are exploring strategic options for the Energy Trading business.

See “Fair Value of Contracts” section that follows.

Synthetic Fuel

Our Synthetic Fuel segment is comprised of the nine synfuel plants that we operate and that produce synthetic fuel. The production of synthetic fuel from the synfuel plants generates production tax credits.

Factors impacting income: Net income was higher by $17 million in the 2007 first quarter primarily due to adjustments to reserves and lower depreciation and amortization expense, partially offset by lower gains associated with variable payments and hedges.

		Three Months Ended
		March 31
(in Millions)		2007				2006
Operating Revenues		$	267			$	274
Operation and Maintenance			324				330
Depreciation and Amortization			1				13
Taxes other than Income			4				5
Asset (Gains), Losses and Reserves, Net			(36	)			(21	)
Operating Loss			(26	)			(53	)
Other (Income) and Deductions			(4	)			(6	)
Minority Interest			(59	)			(71	)
Income Taxes
Provision			13				8
Production Tax Credits			(14	)			(5	)
			(1	)			3
Net Income		$	38			$	21

Operating revenues decreased $7 million in the first quarter of 2007 reflecting lower synfuel prices, partially offset by increased sales volumes.

Operation and maintenance expense decreased $6 million in the first quarter of 2007 reflecting lower coal feedstock costs, partially offset by increased levels of production. Certain supplier agreements provide a mechanism to reduce certain operating costs to offset increases in oil prices.

Depreciation and amortization decreased $12 million in the first quarter of 2007 due to the impairment of fixed assets recorded in 2006.

Asset (gains) losses and reserves, net increased $15 million primarily due to adjustments to reserves for contractual partners’ obligations related to a prior year true up. The following table displays the various pre-tax components that comprise the determination of gains recorded in the first quarters of 2007 and 2006 related to synfuels.

(in Millions)		Three Months Ended
		March 31
Components of Synfuel (Gains), Losses and Reserves, Net		2007				2006
(Gains) recognized associated with fixed payments		$	(33	)		$	(22	)
(Gains) losses recognized associated with variable payments			(6	)			8
Reserves (reversed) recorded for contractual partners’ obligations			(6	)			40
Other reserves			13				—
Hedge (gains) (mark-to-market)
Hedges for 2006 exposure			—				(38	)
Hedges for 2007 exposure			(4	)			(9	)
		$	(36	)		$	(21	)

Minority interest decreased $12 million due to lower depreciation expense in 2007 resulting from impairment of fixed assets in 2006.

Outlook — Due to the implementation of our hedging strategy, we expect to continue to operate the synfuel plants through December 31, 2007 when synfuel-related production tax credits expire.

CORPORATE & OTHER

Corporate & Other includes various corporate staff functions. As these functions 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 results declined $17 million due to adjustments in 2007 to normalize the effective income tax rate. The income tax provisions of the segments are determined on a stand-alone basis. Corporate & Other records necessary adjustments so that the consolidated income tax expense during the quarter reflects the estimated calendar year effective rate.

DISCONTINUED OPERATIONS

DTE Georgetown (Georgetown) — We own Georgetown, an 80 MW natural gas-fired peaking electric generating plant. In the fourth quarter of 2006, management approved the marketing of Georgetown for sale. In December 2006, Georgetown met the SFAS No. 144 criteria of an asset “held for sale” and we reported its operating results as a discontinued operation. In February 2007, we entered into an agreement to sell our Georgetown peaking electric generating facility. The sale is subject to receipt of regulatory approval and is expected to close in the second half of 2007. Georgetown did not have significant business activity for the three months ended March 31, 2007 and 2006.

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 generation sales and service. Dtech did not have significant business activity for the three months ended March 31, 2007.

See Note 4 of the Notes to Consolidated Financial Statements.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES

Effective January 1, 2007, we adopted FIN 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109. The cumulative effect of the adoption of FIN 48 represented a $5 million reduction to the January 1, 2007 balance of retained earnings.

Effective January 1, 2006, we adopted SFAS No. 123(R), Share-Based Payment, using the modified prospective transition method. 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.

See Note 1 of the Notes to Consolidated Financial Statements.

CAPITAL RESOURCES AND LIQUIDITY

Cash Requirements

During the first three months of 2007, our cash requirements were met primarily through operations and short-term borrowings. We believe that we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements.

		Three Months Ended
		March 31
(in Millions)		2007				2006
Cash and Cash Equivalents
Cash Flow From (Used For):
Operating activities:
Net income		$	134			$	136
Depreciation, depletion and amortization			225				225
Deferred income taxes			(6	)			64
Gain on sale of synfuel and other assets, net			(25	)			(21	)
Working capital and other			304				209
			632				613
Investing activities:
Plant and equipment expenditures — utility			(306	)			(264	)
Plant and equipment expenditures — non-utility			(69	)			(71	)
Acquisitions, net of cash acquired			—				(23	)
Proceeds from sale of synfuel and other assets, net			110				101
Restricted cash and other investments			41				(3	)
			(224	)			(260	)
Financing activities:
Redemption of long-term debt			(77	)			(70	)
Short-term borrowings, net			(185	)			(193	)
Repurchase of common stock			(55	)			(8	)
Dividends on common stock and other			(94	)			(95	)
			(411	)			(366	)
Net Decrease in Cash and Cash Equivalents		$	(3	)		$	(13	)

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, primarily from the synthetic fuels business, which we believe, subject to considerations discussed below, will provide approximately $900 million of cash during 2007-2009.

Cash from operations totaling $632 million in the 2007 first quarter was up $19 million from the comparable 2006 period. The operating cash flow comparison reflects a decrease of $76 million in net income, after adjusting for non-cash items (depreciation, depletion, amortization, deferred taxes and gains) and a $95 million increase in working capital and other requirements. Most of the decrease in working capital and other requirements was driven by recovery of electric power supply costs and other working capital improvements at Detroit Edison, partially offset by increased requirements at MichCon and non-utility businesses.

Outlook — We expect cash flow from operations to increase over the long-term primarily due to improvements from higher earnings at our utilities. We are incurring costs associated with implementation of our Performance Excellence Process, but we expect to realize sustained net cost savings beginning in 2007. 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.

We anticipate approximately $900 million of synfuel-related cash impacts from 2007 through 2009, which consists of cash from operations and proceeds from option hedges, and approximately $500 million of tax credit carryforward utilization and other tax benefits that are expected to reduce future tax payments. The redeployment of this cash represents a unique opportunity to increase shareholder value and strengthen our balance sheet.

Investing Activities

Net cash outflows relating to investing activities decreased $36 million in the 2007 first quarter as compared to the 2006 first quarter. The 2007 change was driven by higher synfuel proceeds and lower restricted cash balances, partially offset by increased investments at our utilities, especially environmental spending at Detroit Edison.

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 when we find opportunities that meet our strategic, financial and risk criteria.

Financing Activities

Net cash used for financing activities increased $45 million during the 2007 first quarter, compared to the same 2006 period, principally due to the repurchase of approximately one million shares of common stock in the first quarter of 2007.

Cash Utilization

We expect to use cash generated from our synfuels operations and the potential cash from monetization of certain of our non-utility assets and operations to reduce debt and repurchase common stock, and to continue to pursue growth investments that meet our strict risk-return and value creation criteria. Our objectives for cash redeployment are to strengthen the balance sheet and coverage ratios to improve our current credit rating and outlook, and to have any monetization be accretive to earnings per share.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 3 of the Notes to Consolidated Financial Statements.

FAIR VALUE OF CONTRACTS

The following disclosures provide enhanced transparency of the derivative activities and position of our trading businesses and our other businesses.

The accounting standards 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, in the Consolidated Statement of Operations, 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.

•		“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 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 table provides details on changes in our MTM net asset or (liability) position during the three months ended March 31, 2007:

																		Other
		Trading Activities																Non-
		Proprietary				Structured				Economic								Trading
(in Millions)		Trading				Contracts				Hedges				Total				Activities				Total
MTM at December 31, 2006		$	(9	)		$	(2	)		$	(36	)		$	(47	)		$	(24	)		$	(71	)
Reclassed to realized upon settlement			(6	)			(7	)			32				19				9				28
Changes in fair value recorded to income			15				(4	)			(30	)			(19	)			3				(16	)
Amortization of option premiums			(7	)			—				—				(7	)			—				(7	)
Amounts recorded to unrealized income			2				(11	)			2				(7	)			12				5
Amounts recorded in OCI			—				(4	)			—				(4	)			(29	)			(33	)
Option premiums paid and other			16				—				—				16				5				21
MTM at March 31, 2007		$	9			$	(17	)		$	(34	)		$	(42	)		$	(36	)		$	(78	)

     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, 2007. Amounts that relate to contracts that become due within twelve months are classified as current and all remaining amounts are classified as noncurrent.

																						Other
		Trading Activities																				Non-				Total
		Proprietary				Structured				Economic												Trading				Assets
(in Millions)		Trading				Contracts				Hedges				Eliminations				Totals				Activities				(Liabilities)
Current assets		$	71			$	88			$	113			$	(20	)		$	252			$	143			$	395
Noncurrent assets			2				27				90				—				119				—				119
Total MTM assets			73				115				203				(20	)			371				143				514
Current liabilities			(62	)			(101	)			(140	)			20				(283	)			(109	)			(392	)
Noncurrent liabilities			(2	)			(31	)			(97	)			—				(130	)			(70	)			(200	)
Total MTM liabilities			(64	)			(132	)			(237	)			20				(413	)			(179	)			(592	)
Total MTM net assets (liabilities)		$	9			$	(17	)		$	(34	)		$	—			$	(42	)		$	(36	)		$	(78	)

Maturity of Fair Value of MTM Energy Contract Net Assets

     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, therefore these unrealized gains and losses 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 the first quarter of 2007 to delay previously planned first quarter 2007 withdrawals from gas storage due to a decrease in the current price for natural gas and an increase in the forward price for natural gas. We anticipate the financial impact of this timing difference will reverse when the gas is withdrawn from storage in the 2007-2008 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 realized over the remainder of 2007.

     The table below shows the maturity of our MTM positions:

(in Millions)
														2010
														and				Total Fair
Source of Fair Value		2007				2008				2009				Beyond				Value
Proprietary Trading		$	5			$	4			$	—			$	—			$	9
Structured Contracts			(9	)			(7	)			(4	)			3				(17	)
Economic Hedges			(18	)			(11	)			(5	)			—				(34	)
Total Energy Trading Activities			(22	)			(14	)			(9	)			3				(42	)
Other Non-Trading Activities			56				(75	)			(17	)			—				(36	)
Total		$	34			$	(89	)		$	(26	)		$	3			$	(78	)

Quantitative and Qualitative Disclosures About Market Risk

     Commodity Price Risk

     DTE Energy has commodity price risk in both utility and non-utility businesses arising from market price fluctuations.

     The Electric and Gas Utility businesses have risks in conjunction with the anticipated purchases of coal, natural gas, uranium, electricity, and base metals to meet their service obligations. Further, changes in the price of electricity can impact the level of exposure of Customer Choice programs and uncollectible expenses at the Electric Utility. In addition, changes in the price of natural gas can impact the valuation of lost gas, storage sales revenue and uncollectible expenses at the Gas Utility.

     To limit our exposure to commodity price fluctuations, the Utility businesses have applied various approaches to manage this risk. The approaches include forward energy, capacity, storage and futures contracts, as well as regulatory rate-recovery mechanisms. Regulatory rate-recovery occurs in the form of PSCR and GCR mechanisms and a tracking mechanism to mitigate some losses from customer migration due to electric Customer Choice programs. See Note 6 of the Notes to Consolidated Financial Statements.

     The non-utility businesses have risk in conjunction with electricity, natural gas, crude oil and coal.

     Our Power and Industrial Projects and Synthetic Fuel segments are subject to crude oil, electricity, natural gas and coal based product 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. The benefits associated with production tax credits may be subject to changes in federal tax law. We have entered into a series of derivative contracts for 2007 to economically hedge the impact of oil prices on a portion of our synfuel cash flow. To limit our exposure to the other commodities we may use forward energy, capacity and futures contracts.

     Our Unconventional Gas Production business segment has exposure to natural gas and, to a lesser extent, crude oil price fluctuations. These commodity price fluctuations can impact both current year earnings and reserve valuations. To manage this exposure we use forward energy and futures contracts.

     Our Energy Trading business segment has exposure to electricity, natural gas and crude oil price fluctuations. These risks are managed through its energy marketing and trading operations through the use of forward energy, capacity, storage and futures contracts, within pre-determined risk parameters.

     Our Coal and Gas Midstream business segment has exposure to natural gas and coal price fluctuations. These coal price risks are managed primarily through its coal transportation and marketing operations through the use of forward coal and futures contracts. The Gas Midstream business unit manages its exposure through the sale of long-term storage and transportation contracts.

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.

Energy Trading

     We are exposed to credit risk through trading activities. Credit risk is the potential loss that may result if our trading counterparties fail to meet their contractual obligations. We utilize both external and internally generated credit assessments when determining the credit quality of our trading counterparties. The following table displays the credit quality of our trading counterparties as of March 31, 2007:

		Credit Exposure
		before Cash				Cash				Net Credit
(in Millions)		Collateral				Collateral				Exposure
Investment Grade (1)
A- and Greater		$	411			$	(56	)		$	355
BBB+ and BBB			162				—				162
BBB-			67				—				67
Total Investment Grade			640				(56	)			584
Non-investment grade (2)			62				(1	)			61
Internally Rated — investment grade (3)			83				—				83
Internally Rated — non-investment grade (4)			9				(8	)			1
Total		$	794			$	(65	)		$	729

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 may 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, 2007, the Company had a floating rate debt to total debt ratio of approximately 16% (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 January 2012. 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, 2007 by a hypothetical 10% and calculating the resulting change in the fair values.

     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		$	(18	)		$	18			Commodity contracts
Power Contracts		$	(18	)		$	18			Commodity contracts
Oil Contracts		$	115			$	(89	)		Commodity options
Interest Rate Risk		$	(307	)		$	331			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 the Securities Exchange Act of 1934 (Exchange Act) Rules 13a-15(e) and 15d-15(e)) as of March 31, 2007, 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, 2007 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

     In April 2007, we began implementing the second phase of our Enterprise Business Systems (EBS) project. EBS is an enterprise resource planning system initiative to improve existing processes and to implement new core information systems, relating to finance, human resources, supply chain and work management.

DTE Energy Company

		Three Months Ended
		March 31
(in Millions, Except per Share Amounts)		2007				2006
Operating Revenues		$	2,730			$	2,635
Operating Expenses
Fuel, purchased power and gas			1,135				1,060
Operation and maintenance			1,058				1,021
Depreciation, depletion and amortization			225				225
Taxes other than income			94				92
Asset (gains) and losses, reserves and impairments, net			(26	)			(5	)
			2,486				2,393
Operating Income			244				242
Other (Income) and Deductions
Interest expense			137				133
Interest income			(10	)			(12	)
Other income			(18	)			(12	)
Other expenses			9				10
			118				119
Income Before Income Taxes and Minority Interest			126				123
Income Tax Provision			50				58
Minority Interest			(58	)			(71	)
Income from Continuing Operations			134				136
Loss from Discontinued Operations, net of tax			—				(1	)
Cumulative Effect of Accounting Change, net of tax			—				1
Net Income		$	134			$	136
Basic Earnings per Common Share
Income from continuing operations		$	.76			$	.76
Discontinued operations			—				—
Cumulative effect of accounting change			—				.01
Total		$	.76			$	.77
Diluted Earnings per Common Share
Income from continuing operations		$	.76			$	.76
Discontinued operations			—				—
Cumulative effect of accounting change			—				—
Total		$	.76			$	.76
Average Common Shares
Basic			176				177
Diluted			177				178
Dividends Declared per Common Share		$	.53			$	.515

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

		March 31				December 31
		2007				2006
(in Millions)
ASSETS
Current Assets
Cash and cash equivalents		$	144			$	147
Restricted cash			90				146
Accounts receivable (less allowance for doubtful accounts of $178 and $170, respectively
Customer			1,517				1,427
Collateral held by others			65				68
Other			255				442
Accrued power and gas supply cost recovery revenue			92				117
Inventories
Fuel and gas			410				562
Materials and supplies			159				153
Deferred income taxes			236				245
Assets from risk management and trading activities			395				461
Other			177				193
			3,540				3,961
Investments
Nuclear decommissioning trust funds			759				740
Other			503				505
			1,262				1,245
Property
Property, plant and equipment			19,490				19,224
Less accumulated depreciation and depletion			(7,869	)			(7,773	)
			11,621				11,451
Other Assets
Goodwill			2,057				2,057
Regulatory assets			3,194				3,226
Securitized regulatory assets			1,208				1,235
Intangible assets			89				72
Notes receivable			143				164
Assets from risk management and trading activities			119				164
Prepaid pension assets			72				71
Other			131				139
			7,013				7,128
Total Assets		$	23,436			$	23,785