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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period ended September 30, 2006

Commission file number 1-11607

DTE ENERGY COMPANY

(Exact name of registrant as specified in its charter)


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

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

313-235-4000
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act).

Large accelerated filer þ Accelerated filer o Non-accelerated filer o

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

Yes o No þ

At September 30, 2006, 177,964,872 shares of DTE Energy’s Common Stock, substantially all held by non-affiliates, were outstanding.

Definitions


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

Company		DTE Energy Company and any subsidiary companies

Customer Choice		Statewide initiatives giving customers in Michigan the option to choose alternative suppliers for electricity and gas.

Detroit Edison		The Detroit Edison Company (a direct wholly owned subsidiary of DTE Energy) and any subsidiary companies

DTE Energy		DTE Energy Company, directly or indirectly the parent of Detroit Edison, MichCon and numerous non-utility subsidiaries

EPA		United States Environmental Protection Agency

FERC		Federal Energy Regulatory Commission

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

MDEQ		Michigan Department of Environmental Quality

MichCon		Michigan Consolidated Gas Company (an indirect wholly owned subsidiary of DTE Energy) and any subsidiary companies

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.

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 production tax credits 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. The power supply cost recovery mechanism was suspended under Michigan’s restructuring legislation (signed into law June 5, 2000), which lowered and froze electric customer rates, and was reinstated by the MPSC effective January 1, 2004.

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.

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, the ability to utilize such credits, or the potential requirement to refund proceeds received from synfuel partners;

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

	•		the effects of weather and other natural phenomena on operations and sales to customers, and purchases from suppliers;

	•		economic climate and population growth or decline in the geographic areas where we do business;

	•		environmental issues, laws, regulations, and the cost of remediation and compliance;

	•		nuclear regulations and operations associated with nuclear facilities;

	•		implementation of electric and gas Customer Choice programs;

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

	•		employee relations and the impact of collective bargaining agreements;

	•		unplanned outages;

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

	•		the timing and extent of changes in interest rates;

	•		the level of borrowings;

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

	•		effects of competition;

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

	•		contributions to earnings by non-utility subsidiaries;

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

	•		the ability to recover costs through rate increases;

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

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

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

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

	•		uncollectible accounts receivable;

	•		litigation and related appeals;

	•		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; and

	•		timing and proceeds from any asset sale or monetization.

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 growing and diversified energy company with 2005 revenues in excess of $9 billion and approximately $23 billion in assets. We are the parent company of Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales, distribution and storage services throughout southeastern Michigan. We operate four energy-related non-utility segments with operations throughout the United States.

The following table summarizes our financial results:

(in millions, except Earnings per Share)


	Three Months Ended				Nine Months Ended
	September 30				September 30
	2006		2005		2006		2005
Net Income	$	188	$	4	$	291	$	155
Earnings per Diluted Share	$	1.06	$	.02	$	1.64	$	.89
Excluding Discontinued Operations and Accounting Changes
Income from Continuing Operations	$	189	$	29	$	293	$	188
Earnings per Diluted Share	$	1.07	$	.17	$	1.65	$	1.07

The increases in net income for the three and nine months ended September 30, 2006 are attributable to energy trading mark-to-market losses in our Fuel Transportation and Marketing segment in 2005 which did not recur in 2006, and higher earnings at our electric utility, Detroit Edison. Both periods were adversely impacted by the temporary idling of synfuel plants along with the associated impairments and reserves, and higher levels of deferrals of potential gains from selling interests in the synfuel plants, and impairments within our Power and Industrial Project segment.

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;

•		Synfuel-related earnings and the impact of temporarily idling synfuel facilities earlier in 2006;

•		Investments in our Unconventional Gas Production business;

•		Gains in our Fuel Transportation and Marketing business; and

•		Cost reduction efforts and required capital investment.

UTILITY OPERATIONS

Weather - Earnings from our utility operations are seasonal and very sensitive to weather. Electric utility earnings are primarily dependent on hot summer weather, while the gas utility’s results are primarily dependent on cold winter weather. During the nine months ended September 30, 2006, we experienced warmer than normal weather conditions. The following table shows the dollar impact of weather relative to 30-year historical normal weather temperatures for each utility.

(in Millions)


		Estimated effect of weather on Gross Margin
Nine Months		Electric		Gas
Ending September 30		Utility		Utility			Total
	2006	$	18	$	(25	)	$	(7	)
	2005	$	91	$	(2	)	$	89

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

We continue action to reduce the level of past-due receivables, including increased customer disconnections, contracting with collection agencies and working with the State of Michigan and others to increase the share of low-income funding allocated to our customers. Our actions and lower commodity prices have resulted in a decrease in our allowance for doubtful accounts expense for the two utilities to $21 million in the third quarter of 2006 from $28 million in the third quarter of 2005.

The April 2005 MPSC gas rate order provided for an uncollectible true-up mechanism for MichCon. We filed the 2005 annual reconciliation during the first quarter of 2006, comparing our actual uncollectible expense to our designated revenue recovery of approximately $37 million on an annual basis. Ninety percent of the difference between the actual uncollectible expense and $37 million for the year will be refunded or surcharged after the conclusion of the annual reconciliation proceeding before the MPSC. For the nine months ended September 30, 2006, we have accrued an underrecovery of $26 million under the uncollectible true-up mechanism.

Regulatory activity - In accordance with the MPSC’s directive in Detroit Edison’s November 2004 rate order, in March 2005, Detroit Edison filed a joint application and testimony in its 2004 PSCR Reconciliation Case and its 2004 Net Stranded Cost Recovery Case. In September 2006, the MPSC issued an order recognizing $19 million of 2004 net stranded costs that required Detroit Edison to write off $112 million of 2004 net stranded costs. The MPSC order resulted in a $39 million reduction in the 2004 PSCR over-collection by allowing Detroit Edison to retain the benefit of third party wholesale sales required to support the electric Customer Choice program and to offset the recognition of the $19 million of 2004 stranded costs. The MPSC order also resulted in adjustments to accrued interest on the 2004 and 2005 PSCR amounts of $15 million. The MPSC directed Detroit Edison to include the remaining 2004 PSCR over-collection amount and related interest in the 2005 PSCR Reconciliation which is in an under-collected position. The order resulted in a reduction of pre-tax income of approximately $58 million.

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 the 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 the later of March 31, 2008 or 12 months from the filing date of Detroit Edison’s next main rate case, rates will be reduced by an additional $26 million, for a total reduction of $79 million. 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 share 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 a portfolio of non-utility asset-intensive businesses. We employ disciplined investment criteria when assessing opportunities that leverage our assets, skill and expertise. Specifically, we invest in targeted energy markets with attractive competitive dynamics where meaningful scale is in alignment with our risk profile. A number of factors have impacted our non-utility businesses

including the effect of oil prices on the synthetic fuel business, losses from certain power generation assets, losses from our waste coal recovery and landfill gas recovery businesses, and earnings volatility in our energy trading business. In addition, we are reassessing our investment in our unconventional gas production 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 businesses within our non-utility portfolio. We plan to continue to invest in focused areas that have the strongest opportunities.

The primary source of investment capital has been cash flow from the synfuel business. We have hedged the risk of an oil price-related phase-out of production tax credits in the synfuel business. We now anticipate approximately $1.2 billion to $1.4 billion of synfuel-related cash impacts from 2006 through 2009, which consists of cash from operations and proceeds from option hedges, and approximately $600 million of tax credit carryforward utilization and other tax benefits that are expected to reduce future tax payments. Tax credit carryforward utilization in part could be extended past 2009, if taxable income is reduced from current forecasts.

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 four gas-fired peaking electric generating plants and a biomass-fired electric generating plant and operate one additional gas-fired power plant under contract. We develop, own and operate landfill gas recovery systems throughout the United States. We produce coke from two coke batteries. The production of coke from our coke batteries generates production tax credits (assuming no phase-out). As part of a strategic review of our non-utility operations, we are exploring the sale of approximately a 50 percent equity interest in selected assets and a recapitalization with an appropriate level of debt. These changes in structure could result in proceeds of approximately $400 million to $600 million. In addition, we are planning to sell, exit or redeploy our four gas-fired peaking electric generating plants that could generate potential proceeds of approximately of $50 million to $150 million. We are also planning to restructure, sell or close the landfill gas recovery business.

Synthetic Fuel

Synthetic Fuel Operations

We are the operator of nine synthetic fuel production facilities throughout the United States. On May 12, 2006, we idled production at all nine of the synthetic fuel facilities. The decision to idle synfuel production was driven by the level and volatility of oil prices at that time. During the idle period, we renegotiated a significant number of commercial agreements which will result in lower operating costs at all the synthetic fuel facilities in the event of sustained high oil prices. Beginning September 5, 2006 through October 4, 2006, we resumed production at each of the nine synfuel facilities due to these amended commercial agreements and declines in the level of oil prices.

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) and 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 September 30, 2006. 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 and collectibility is reasonably assured. In substance, we received 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 comprised of fixed and variable components. The fixed component represents note payments of principal and interest, is not subject to refund, and is recognized as a gain when earned and collectibility is assured. The variable component is based on an estimate of tax credits allocated to our partners 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. Additionally, based on estimates of tax credits allocated, our partners reimburse us (through the project entity) for the operating losses of the synfuel facilities, referred to as capital contributions. In the event that the tax credit is phased out, we are contractually obligated to refund 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. Due to changes in the agreements with certain of our synfuel partners and the exercise of existing rights by other synfuels partners, a higher percentage of the expected payments in 2006 may be variable payments. As a result, a larger portion of the 2006 synfuel payments may be subject to refund should a phase-out occur as expected; and therefore delay recognition of the gain associated with the payments until the probability of refund becomes remote.

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 2006, the annual average wellhead price is projected to be approximately $7 lower than the New York Mercantile Exchange (NYMEX) price for light, sweet crude oil. The actual or estimated Reference Price and beginning and ending phase-out prices per barrel of oil for 2005 through 2007 are as follows:


			Beginning Phase-Out		Ending Phase-Out
	Reference Price		Price		Price
2005 (actual)	$	50.26	$	53.20	$	66.79
2006 (estimated)	Not Available		$	55	$	69
2007 (estimated)	Not Available		$	56	$	70

Through September 30, 2006, the NYMEX daily closing price of a barrel of oil for 2006 averaged approximately $68, which is approximately equal to a Reference Price of $61 per barrel. As of October 31, 2006, the realized and unrealized NYMEX daily closing price of a barrel of oil was approximately $66 for 2006, equating to an estimated Reference Price of $59, which we estimate to be within the phase-out range. The average NYMEX daily closing price of a barrel of oil would have to average less than approximately $38 for the remainder of 2006 for no phase-out of production tax credits to occur. The actual tax credit phase-out for 2006 will not be certain until the Reference Price is published by the IRS in April 2007. We expect at least a partial phase-out of the production tax credits in 2006, which could adversely impact our results of operations, cash flow, and financial condition. However, we cannot predict with any certainty the Reference Price for the remainder of 2006 or beyond.

Hedging of Synfuel Cash Flows

As discussed in Note 2, we have entered into derivative and other contracts to economically hedge a portion of our 2006 and 2007 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. We recorded a pretax mark-to-market loss of $24 million during the third quarter of 2006 and a $83 million gain in the nine months ended September 30, 2006, as compared to a gain of $46 million in the third quarter of 2005 and a $89 million gain in the nine months ended September 30, 2005. Recently we entered into additional hedges which will provide protection for a significant portion of our cash flows related to the synfuel production during the remainder of 2006 and 2007. As part of our synfuel-related risk management strategy, we continue to evaluate alternatives available to mitigate unhedged exposure to oil price volatility. As our risk management position changes due to market volatility, we may adjust our hedging strategy in response to changing conditions.

Risks and Exposures

Since there is a likelihood that the Reference Price for a barrel of oil will reach the threshold at which synfuel-related production tax credits begin to phase-out, we will defer gain recognition associated with variable and certain indemnified fixed note payments in 2006 until the probability of refund is remote and collectibility is assured. We did not recognize any pretax synfuel-related gains in the third quarter of 2006 and recognized gains of $39 million in the nine months ended September 30, 2006, compared to gains of $34 million in the third quarter of 2005 and $91 million in the nine months ended September 30, 2005. In the nine months ended September 30, 2006, we recorded reserves and impairments of $125 million, primarily consisting of an impairment of $77 million for synfuel-related fixed assets and $44 million for a reserve for notes receivable related to the sale of interests in synfuel facilities. The impairment was partially offset by $70 million, representing our partners’ share of the asset write down, included in Minority Interest. Due to the decrease in oil prices in the third quarter of 2006, we reduced our accrual for contractual partners’ obligations by $76 million pre-tax reflecting the possible refund of amounts equal to our partners’ capital contributions or for operating losses that would normally be funded by our partners. All or a portion of the deferred gains will be recognized when and if the gain recognition criteria is met. We expect that additional potential gains will be deferred this year unless there is persuasive evidence that no tax credit phase-out will occur. Additionally, we expect to continue establishing reserves for potential refunds of amounts related to partners’ capital contributions associated with operating losses allocated to their account. As previously discussed, 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.

Assuming that there is a significant synfuel tax credit phase-out, we expect approximately $1.2 billion to $1.4 billion of synfuel-related cash impacts from 2006 through 2009, which consists of cash from operations and proceeds from option hedges, and approximately $600 million of tax credit carryforward utilization and other tax benefits that are expected to reduce future tax payments. If the Reference Price results in a partial phase-out of the synfuel tax credits for 2006, assuming the previously discussed current level of economic hedges, there is a potential decrease of as much as approximately $200 million to 2006 net income from 2005 levels. In addition, a potential goodwill write-off of up to $4 million may be required due to the synfuel tax credit phase-out. We also have fixed notes receivable associated with the sales of interests in the synfuel facilities. A partial or full phase-out of production tax credits could adversely affect the collectibility of our receivables. The cash flow impact would reduce our ability to execute our investment and growth strategy, unless we find alternate sources of cash.

Unconventional Gas Production

Long term, natural gas prices may continue to provide attractive opportunities for our Unconventional Gas Production business segment. We are an experienced operator with more than 15 years of experience in the Antrim shale in northern Michigan, and have expanded our operations in the Barnett shale basin in north Texas. We realize that increasing this business to an appropriate scale would provide challenges. As part of a strategic review of our non-utility operations, we are exploring the sale of some or most of unconventional gas assets. These assets include acreage positions in both the Antrim and Barnett shale formations of a combined 382,000 acres and 552 Bcf of proved and probable reserves. A partial sale could allow us to monetize value from certain more mature holdings, while retaining the ability to benefit from increased value from earlier stage holdings. We estimate that the sale of these assets could produce proceeds of approximately $250 million to $1 billion.

Antrim shale – We may develop existing acreage using the latest horizontal drilling techniques. Approximately one-third of our long-term, below-market fixed-price obligations for production of Antrim gas expire from 2006 through 2008. This will create opportunities to remarket Antrim production at higher current market rates.

Barnett shale - We have increased production in certain areas and are currently in the test and development phase for both unproved and proved Barnett shale acreage.

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 September 30, 2006, we entered into a series of cash flow hedges for 5.1 Bcf of gas production through 2010 at an average price of $8.02 per Mcf.

Due to favorable natural gas prices and the potential for successes within the Barnett shale, more capital is being invested into the region. The competition for opportunities and goods and services may result in increased operating costs. However, our experience in the Antrim shale and our experienced Barnett shale personnel allow us to effectively manage the challenge. We expect to invest a combined amount of approximately $170 million to $190 million in our Unconventional Gas Production business in 2006.

Fuel Transportation and Marketing

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

Our Coal Transportation and Marketing business will seek to build our capacity to transport greater amounts of western coal and to expand into coal terminals. The Coal Transportation and Marketing business is 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. The arbitration hearing is scheduled for mid-2007. While we believe we will prevail on the merits in this matter, a negative decision with respect to the significant issues being heard in the arbitration could have an adverse effect on our ability to grow the Coal Transportation and Marketing business segment as currently contemplated.

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 we expect to be subsequently reversed when transactions are settled.

During 2005, our DTE Energy Trading earnings were negatively impacted by the economically favorable decision to delay previously planned withdrawals from gas storage due to a decrease in the current price for natural gas and an increase in the forward price for natural gas. In addition, we entered into forward power contracts to economically hedge certain physical and capacity power contracts. The financial impacts of these timing differences have begun to reverse and have favorably impacted results during 2006. As part of a strategic review of our non-utility operations, we will explore alternative structures and strategic options for the energy trading business and plan to separate this business into a new segment at year end 2006.

OPERATING SYSTEM AND PERFORMANCE EXCELLENCE PROCESS

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

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. We estimate savings of $50 million to $100 million will be realized in 2006. Through the third quarter of 2006, we recorded implementation costs, also called costs to achieve (CTA), of approximately $97 million for project management, consultant support and employee severance. CTA in 2006 may exceed our projected savings this year, 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 recorded the deferred CTA as a regulatory asset and will begin 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. MichCon will not 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 in total approximately $4.5 billion, including increased environmental requirements and reliability enhancement projects through 2010. 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 plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment.

During 2005, we began the first wave of implementation of DTE2, an enterprise resource planning system initiative to improve existing processes and to implement new core information systems. Through September 2006, we have spent approximately $300 million on this project and we anticipate spending an additional $75 million to $100 million over the next year as the remaining system elements are developed and business segments fully adopt DTE2.

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

OUTLOOK

The next few years will be a period of rapid change for DTE Energy and for the energy industry. Our strong utility base, combined with our integrated non-utility operations, position us well for long-term growth. Due to the enactment of the Energy Policy Act of 2005 and the repeal of the Public Utility Holding Company Act of 1935, there are fewer barriers to mergers and acquisitions of utility companies 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 $1.2 billion to $1.4 billion of synfuel-related cash impacts from 2006 through 2009, which consists of cash from operations and proceeds from option hedges, and approximately $600 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 any 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. We plan to repurchase approximately 1 million shares of common stock beginning in November 2006. 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

Our net income in the 2006 third quarter was $188 million, or $1.06 per diluted share, compared to net income of $4 million, or $.02 per diluted share, in the 2005 third quarter. For the 2006 nine-month period, our net income was $291 million, or $1.64 per diluted share, compared to net income of $155 million, or $.89 per diluted share, for the same 2005 period. The following sections provide a detailed discussion of our segments’ operating performance and future outlook.

Gas Utility, Unconventional Gas Production, Fuel Transportation and Marketing, and Corporate and Other were unaffected by this realignment. Based on this structure, we set strategic goals, allocate resources and evaluate performance. Our segment information is based on the following alignment:

	•		Electric Utility, consisting of Detroit Edison;

	•		Gas Utility, primarily consisting of MichCon;

	•		Non-utility Operations

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

	•		Synthetic Fuel, consisting of the operations of the nine synfuel plants we operate;

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

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

•

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

(in Millions, except per share data)


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2006			2005			2006			2005
Electric Utility	$	141		$	114		$	257		$	212
Gas Utility		(20	)		161			16			123
Non-utility Operations:
Power and Industrial Projects		(50	)		(1	)		(74	)		2
Synthetic Fuel		43			69			30			165
Unconventional Gas Production		2			2			5			3
Fuel Transportation and Marketing		75			(129	)		103			(139	)

Corporate & Other		(2	)		(187	)		(44	)		(178	)

Income (Loss) from Continuing Operations
Utility		121			275			273			335
Non-utility		70			(59	)		64			31
Corporate & Other		(2	)		(187	)		(44	)		(178	)

		189			29			293			188
Discontinued Operations		(1	)		(25	)		(3	)		(33	)
Cumulative Effect of Accounting Change		—			—			1			—

Net Income	$	188		$	4		$	291		$	155


Diluted Earnings (Loss) Per Share
Total Utility	$	.68		$	1.57		$	1.54		$	1.91
Non-utility Operations		.40			(.33	)		.36			.18
Corporate & Other		(.01	)		(1.07	)		(.25	)		(1.02	)

Income from Continuing Operations		1.07			.17			1.65			1.07
Discontinued Operations		(.01	)		(.15	)		(.02	)		(.18	)
Cumulative Effect of Accounting Change		—			—			.01			—

Net Income	$	1.06		$	.02		$	1.64		$	.89

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

ELECTRIC UTILITY

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

Factors impacting income: Net income increased $27 million during the 2006 third quarter and $45 million in the 2006 nine-month period. These results primarily reflect higher gross margins, partially offset by increased depreciation and amortization expenses. The 2006 third quarter benefited from the deferral of CTA associated with our Performance Excellence Process.

(in Millions)


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2006			2005			2006			2005
Operating Revenues	$	1,460		$	1,409		$	3,685		$	3,434
Fuel and Purchased Power		539			604			1,257			1,248

Gross Margin		921			805			2,428			2,186
Operation and Maintenance		277			325			990			976
Depreciation and Amortization		308			174			643			484
Taxes Other Than Income		64			68			198			200
Asset (Gains) and Losses, Net		(1	)		(26	)		(1	)		(26	)

Operating Income		273			264			598			552
Other (Income) and Deductions		59			70			213			214
Income Tax Provision		73			80			128			126

Net Income	$	141		$	114		$	257		$	212


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

Gross margins increased $116 million during the 2006 third quarter and $242 million in the 2006 nine-month period. The quarterly and year-to-date improvements were primarily due to increased rates due to the expiration of the residential rate cap on January 1, 2006 and returning sales from electric Customer Choice, partially offset by milder weather in 2006.

(in Millions)


	Three			Nine
	Months			Months
Increase (Decrease) in Gross Margin Components Compared to Prior Year
Weather-related margin impacts	$	(38	)	$	(71	)
Removal of residential rate caps effective January 1, 2006		106			160
Return of customers from electric Customer Choice		55			106
Service territory economic performance		(34	)		(13	)
Impact of MPSC 2004 PSCR order		39			39
Other, net		(12	)		21

Increase in gross margin performance	$	116		$	242

(in Thousands of MWh)


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2006			2005			2006			2005
Power Generated and Purchased
Power Plant Generation
Fossil		10,867			11,578			29,382			30,887
Nuclear		1,873			1,979			4,991			6,304

		12,740			13,557			34,373			37,191
Purchased Power		3,085			2,347			7,917			5,156

System Output		15,825			15,904			42,290			42,347
Less Line Loss and Internal Use		(483	)		(888	)		(2,165	)		(2,237	)

Net System Output		15,342			15,016			40,125			40,110


Average Unit Cost ($/MWh)
Generation (1)	$	17.78		$	17.69		$	16.33		$	15.68

Purchased Power	$	68.28		$	123.36		$	58.89		$	92.39

Overall Average Unit Cost	$	27.62		$	33.29		$	24.30		$	25.02


(1)		Represents fuel costs associated with power plants.

(in Thousands of MWh)

Three Months Ended

Nine Months Ended

September 30

2006

2005

2006

2005

Electric Sales

Residential

4,883

5,554

12,233

13,371

Commercial

4,927

4,462

13,440

11,646

Industrial

3,695

3,197

10,058

9,118

Wholesale

719

599

2,096

1,719

Other

291

285

14,319

13,905

38,118

36,139

Interconnections sales (1)

1,023

1,111

2,007

3,971

Total Electric Sales

15,342

15,016

40,125

40,110

Electric Deliveries

Retail and Wholesale

14,319

13,905

38,118

36,139

Electric Customer Choice

319

1,635

2,188

5,178

Electric Customer Choice – Self Generators (2)

215

693

429

Total Electric Sales and Deliveries

14,853

15,602

40,999

41,746


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

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

Operation and maintenance expense decreased $48 million in the third quarter of 2006 and increased $14 million in the 2006 nine-month period. Pursuant to MPSC authorization, in the third quarter of 2006, Detroit Edison deferred approximately $74 million of CTA, including all amounts incurred in the third quarter and approximately $49 million of costs that were previously expensed through June 30, 2006. In the third quarter of 2006, we had $16 million in lower storm expenses, which were offset by $13 million of increased distribution system maintenance and a $9 million increase in plant outages. The year-to-date increase of $14 million in operation and maintenance expense was primarily due to increased plant outages of $12 million, increased distribution system maintenance of $24 million, offset by $21 million in lower storm expenses.

Depreciation and amortization expense increased $134 million in the third quarter of 2006 and $159 million in the 2006 nine-month period due to a $112 million net stranded cost write-off related to the September 2006 MPSC order regarding stranded costs and a $15 million increase in our asset retirement obligation at our Fermi 1 nuclear facility. We also had increased amortization of regulatory assets of $14 million related to electric Customer Choice and $7 million related to our securitized assets.

Asset (gains) and losses, net decreased by $25 million as a result of our 2005 sale of land near our headquarters in Detroit, Michigan.

Outlook – We continue to improve the operating performance of Detroit Edison. During the past year, we have resolved a portion of our regulatory issues and continue to pursue additional regulatory 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, uranium and 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. Should we be able to recover these costs in future rate cases, we may experience a growth in earnings. Additionally, our service territory may require additional generation capacity. A new base-load generating plant has not been built within the State of Michigan in the last 20 years. Should our regulatory environment be conducive to such a significant capital expenditure, we may build or expand a new base- load coal or nuclear facility, with an estimated cost of $1 billion to $2 billion for a new coal plant.

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; and

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

We expect cash flows and operating performance will continue to be at risk due to the electric Customer Choice program until the issues associated with this program are adequately addressed. We will accrue as regulatory assets any future unrecovered generation-related fixed costs (stranded costs) due to electric Customer Choice that we believe are recoverable under Michigan legislation and MPSC orders. We cannot predict the outcome of these matters. See Note 6.

GAS UTILITY

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

Factors impacting income: Gas Utility incurred a net loss of $20 million in the 2006 third quarter as compared to net income of $161 million in 2005. Net income in the 2006 nine-month period was lower by

$107 million. The variances were primarily attributable to effective tax rate adjustments in 2005, increased rates and the impacts in 2005 of the MPSC’s April 2005 gas cost recovery and final gas rate orders, and the effects of milder weather in 2006.

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

(in Millions)


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2006			2005			2006			2005
Operating Revenues	$	172		$	210		$	1,283		$	1,329
Cost of Gas		58			102			786			883

Gross Margin		114			108			497			446
Operation and Maintenance		93			97			327			318
Depreciation and Amortization		24			22			70			72
Taxes other than Income		13			11			42			38
Asset (Gains) and Losses, Net		(3	)		—			—			4

Operating Income (Loss)		(13	)		(22	)		58			14
Other (Income) and Deductions		14			12			39			35
Income Tax Provision (Benefit)		(7	)		(195	)		3			(144	)

Net Income (Loss)	$	(20	)	$	161		$	16		$	123


Operating Income (Loss) as a Percent of Operating Revenues		(8)	%		(10)	%		5	%		1	%

Gross margins increased $6 million during the 2006 third quarter and $51 million in the 2006 nine-month period. Compared to the third quarter of 2005, gross margins were favorably impacted by $3 million due to the effects of weather and an increase of $4 million in midstream services, including storage and transportation.

The year-to-date gross margins were favorably affected by $15 million in higher base rate revenue and an increase of $22 million in revenue associated with the uncollectible expense tracking mechanism authorized by the MPSC in the April 2005 final gas rate order, a $17 million favorable impact in lost gas and gas in kind recovery and an increase of $16 million in midstream services including storage and transportation. Partially offsetting these increases were a $24 million decline due to warmer than normal weather and an estimated $13 million decline as a result of customer conservation efforts. Additionally, the comparability of the nine-month periods is affected by an adjustment we recorded in the first quarter of 2005 related to an April 2005 MPSC order in our 2002 GCR reconciliation case that disallowed $26 million representing unbilled revenues at December 2001.


	Three Months Ended				Nine Months Ended
	September 30				September 30
	2006		2005		2006		2005
Gas Markets (in Millions)
Gas sales	$	106	$	151	$	1,069	$	1,130
End user transportation		24		24		96		97

		130		175		1,165		1,227
Intermediate transportation		16		14		45		42
Other		26		21		73		60

	$	172	$	210	$	1,283	$	1,329


Gas Markets (in Bcf)
Gas sales		11		10		95		116
End user transportation		27		34		98		117

		38		44		193		233
Intermediate transportation		77		95		284		313

		115		139		477		546

Operation and maintenance expense decreased $4 million in the 2006 third quarter and increased $9 million for the nine-month period. Compared to the third quarter of 2005, the decrease is due to a $7 million decline in uncollectible accounts receivable expense and $7 million lower corporate support allocations, partially offset by $12 million in costs associated with our Performance Excellence Process.

The year-to-date period increases are due to an $11 million increase in uncollectible accounts receivable expense, reflecting higher past due amounts attributable to an increase in gas prices, continued weak economic conditions, and inadequate government-sponsored assistance for low-income customers. We also recorded $18 million in implementation costs associated with our Performance Excellence Process. Increases were offset by the DTE Energy parent company no longer allocating $9 million of merger-related interest to MichCon effective in April 2005. Additionally, the comparability of the nine-month periods is affected by an adjustment we recorded in second quarter of 2005 for the disallowance of $11 million in environmental costs due to the April 2005 final gas rate order and the requirement to defer negative pension expense as a regulatory liability.

Asset (gains) and losses, net increased $3 million in the 2006 third quarter and decreased $4 million for the nine-month period. The third quarter increase was due to the sale of investment rights related to storage field construction. The change in the nine-month period was due to a reduction to MichCon’s 2004 GCR underrecovery related to the accounting treatment of the injected base gas remaining in the New Haven storage field when it was sold in early 2004.

Income tax benefit decreased $188 million and income tax expense increased $147 million for the third quarter and nine-month period of 2006, respectively, primarily due to a lower effective tax rate in 2006.

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 GCR mechanism. In the April 2005 final gas rate order, the MPSC adopted MichCon’s proposed tracking mechanism for uncollectible accounts receivable. Each year, MichCon will file an application comparing its actual uncollectible expense for the prior calendar year to its designated revenue recovery of approximately $37 million. Ninety percent of the difference will be refunded or surcharged after an annual reconciliation proceeding before the MPSC.

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

Power and Industrial Projects

Factors impacting income: Power and Industrial Projects net loss increased $49 million during the 2006 third quarter and increased $76 million in the 2006 nine-month period due primarily to impairments.

(in Millions)


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2006			2005			2006			2005
Operating Revenues	$	105		$	112		$	312		$	320
Operation and Maintenance		92			98			275			234
Depreciation and Amortization		13			11			37			37
Taxes other than Income		3			3			10			11
Asset (Gains) and Losses, Reserves and Impairments, Net		48			1			64			—

Operating Income (Loss)		(51	)		(1	)		(74	)		38
Other (Income) and Deductions		30			(4	)		40			4
Minority Interest		1			5			1			33
Income Taxes
Provision (Benefit)		(29	)		2			(36	)		6
Production Tax Credits		(3	)		(3	)		(5	)		(7	)

		(32	)		(1	)		(41	)		(1	)

Net Income (Loss)	$	(50	)	$	(1	)	$	(74	)	$	2

Operating revenues decreased $7 million in the 2006 third quarter and decreased $8 million in the 2006 nine-month period due primarily to lower coke prices and lower pulverized coal sales.

Operation and maintenance expense decreased $6 million in the 2006 third quarter and increased $41 million in the 2006 nine-month period. Our year-to-date expenses are higher as a result of the acquisition of new energy projects.

Asset (gains) and losses, reserves and impairments, net increased $47 million in the 2006 third quarter and increased $64 million in the 2006 nine-month period. During the third quarter of 2006, we recorded a $41 million impairment for one of our 100% owned natural gas-fired generating plants and a $3 million impairment at our landfill gas recovery unit relating to the write-down at several landfill sites. Additionally, during 2006, we recorded a pre-tax impairment loss of $20 million ($16 million in the first quarter of 2006 and $4 million in the third quarter of 2006) for the write down of fixed assets and patents at our waste coal recovery business.

Other (income) and deductions decreased $34 million in the 2006 third quarter and decreased $36 million in the 2006 nine-month period primarily due to the $31 million impairment of a 50% equity interest in a natural gas-fired generating plant.

Income taxes declined $31 million in the 2006 third quarter and $40 million in the 2006 nine-month period, reflecting changes in pre-tax income.

Outlook – Power and Industrial Projects will continue leveraging its extensive energy-related operating experience and project management capability to develop and grow the on-site energy business. The coke battery and landfill gas recovery businesses generate production tax credits that are subject to an oil price-related phase-out. We continue to evaluate the impact of an oil price-related phase-out on these businesses. Due to the relatively low level of production tax credits generated by our coke battery and landfill gas recovery businesses, a partial or full phase-out of production tax credits in these two businesses is not expected to have a material adverse impact on DTE’s consolidated results of operations, cash flow and financial condition. As part of a strategic review of our non-utility operations, we are exploring the sale of approximately a 50 percent equity interest in selected assets and a recapitalization with an appropriate level of debt. In addition, we are planning to sell, exit or redeploy our four gas-fired peaking electric generating plants. We are also planning to restructure the landfill gas recovery business.

Synthetic Fuel

Synthetic Fuel 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 (assuming no phase-out).

Factors impacting income: Synthetic Fuel net income decreased $26 million during the 2006 third quarter and decreased $135 million in the 2006 nine-month period. The declines in both the 2006 periods are due to the temporary idling of synfuel plants along with the associated impairments and reserves, and higher levels of deferrals of potential gains from selling interests in the synfuel plants.

(in Millions)


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2006			2005			2006			2005
Operating Revenues	$	142		$	237		$	605		$	688
Operation and Maintenance		152			304			705			866
Depreciation and Amortization		1			22			23			48
Taxes other than Income		1			7			8			14
Asset (Gains) and Losses, Reserves and Impairments, Net		(50	)		(80	)		52			(180	)

Operating Income (Loss)		38			(16	)		(183	)		(60	)
Other (Income) and Deductions		(2	)		(8	)		(15	)		(26	)
Minority Interest		(11	)		(92	)		(191	)		(241	)
Income Taxes
Provision		18			29			8			72
Production Tax Credits		(10	)		(14	)		(15	)		(30	)

		8			15			(7	)		42

Net Income	$	43		$	69		$	30		$	165

Operating revenues decreased $95 million in the 2006 third quarter and decreased $83 million in the 2006 nine-month period. Revenues were down in 2006 due to our decision to temporarily idle production at all nine of the synfuel facilities.

Operation and maintenance expense decreased $152 million in the 2006 third quarter and decreased $161 million in the 2006 nine-month period. Operations and maintenance expenses were down in 2006 due to our decision to temporarily idle production at all nine of the synfuel facilities.

Asset (gains) and losses, reserves and impairments, net decreased $30 million in the 2006 third quarter and decreased $232 million in the 2006 nine-month period. In both the 2006 and 2005 periods, we deferred gains from the sale of the synfuel facilities, including in 2006, a portion of gains related to fixed payments. Due to the decrease in oil prices in the third quarter of 2006, we reduced our accrual for

contractual partners’ obligations by $76 million pre-tax reflecting the possible refund of amounts equal to our partners’ capital contributions or for operating losses that would normally be funded by our partners. We also recorded other synfuel-related reserves and impairments in the second quarter of 2006. These amounts were partially offset by gains and losses on hedges for our synfuel cash flow.

(in Millions)


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2006			2005			2006			2005
Components of Synfuel (Gains) Losses, Reserves and Impairments, Net
Gains recognized associated with fixed payments	$	—		$	(34	)	$	(30	)	$	(91	)
Gains recognized associated with variable payments		—			—			(9	)		—
Reserves recorded (reversed) for contractual partners’ obligations		(76	)		—			49			—
Other reserves and impairments, including partners’ share (1)		2			—			125
Unrealized hedge (gains) losses (mark-to-market)
Hedges for 2005 exposure		—			(14	)		—			(37	)
Hedges for 2006 exposure		13			(32	)		(73	)		(52	)
Hedges for 2007 exposure		11			—			(10	)		—

	$	(50	)	$	(80	)	$	52		$	(180	)


(1)		Includes $70 million in the nine months ended September 30, 2006, representing our partners’ share of the asset write down, included in Minority Interest.

Minority interest decreased $81 million in the third quarter of 2006 and $50 million in the nine-month period of 2006. The amounts reflect our partners’ share of operating losses associated with synfuel operations as well as our partners’ share of the asset write down of $70 million in the nine-month period. The sale of interests in the synfuel facilities during prior periods resulted in allocating a larger percentage of such losses to our partners.

Income taxes declined $7 million in the 2006 third quarter and $49 million in the 2006 nine-month period reflecting changes in pre-tax income due to synfuel related loss reserves and the write-down of fixed assets, compared to pre-tax income in the first nine months of 2005.

Outlook – At current oil prices, we expect to continue to operate the synfuel plants through December 31, 2007, when synfuel-related production tax credits expire. Future increases in the level or volatility of oil prices could cause us to adjust synfuel production in an effort to maximize cash flow from this business.

Unconventional Gas Production

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

Factors impacting income: Net income was unchanged in the third quarter 2006 compared to the same period in 2005. For the nine-month period in 2006, net income increased $2 million compared to the same periods in 2005. The results in both periods were primarily impacted by a significant increase in Barnett shale production and an increase of net gas prices for Antrim shale. Partially offsetting these revenue increases were commensurate increases in operating and depletion expenses associated with higher production and the operation of new wells.

(in Millions)


	Three Months Ended				Nine Months Ended
	September 30				September 30
	2006		2005		2006		2005
Operating Revenues	$	26	$	20	$	72	$	53
Operation and Maintenance		9		7		27		21
Depreciation and Amortization		7		5		19		14
Taxes Other Than Income		2		3		8		7
Asset (Gains) and Losses, Net		1		—		1		—

Operating Income		7		5		17		11
Other (Income) and Deductions		3		2		9		6
Income Tax Provision		2		1		3		2

Net Income	$	2	$	2	$	5	$	3

Outlook - We expect to continue to develop our proved areas, test unproved areas and prudently add new acreage in Michigan and Texas. Evaluation of Barnett shale test wells in up to six new areas is ongoing. We expect to invest a combined amount of approximately $170 million to $190 million in our Unconventional Gas Production business in 2006. We recognize that we may face challenges in building this business to an appropriate scale. As part of a strategic review of our non-utility operations, we are exploring the sale of some or most of our unconventional gas assets. These assets include acreage positions in both the Antrim and Barnett shale formations of a combined 382,000 acres and 552 Bcf of proved and probable reserves. A partial sale could allow us to monetize value from certain more mature holdings, while retaining the ability to benefit from increased value from earlier stage holdings.

Fuel Transportation and Marketing

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

DTE Energy Trading focuses on physical power and gas marketing, structured transactions, enhancement of returns from DTE Energy’s power plants and the optimization of contracted natural gas pipelines and storage capacity positions. Our customer base is predominantly utilities, local distribution companies, large industrials, and other marketing and trading companies. We enter into derivative financial instruments as part of our marketing and hedging activities. Most of the derivative financial instruments are accounted for under the mark-to-market method, which results in earnings recognition of unrealized gains and losses from changes in the fair value of the derivatives. We utilize forwards, futures, swaps and option contracts to mitigate risk associated with our marketing and trading activity as well as for proprietary trading within defined risk guidelines. DTE Energy Trading provides commodity risk management services to the other unregulated businesses within DTE Energy.

Coal Transportation and Marketing provides fuel, transportation and rail equipment management services. We specialize in minimizing fuel costs and maximizing reliability of supply for energy-intensive customers. Additionally, we participate in coal trading and coal-to-power tolling transactions, as well as the purchase and sale of emissions credits. We recently initiated a new business line, coal mine methane extraction, in which we recover methane gas from mine voids for processing and delivery to natural gas pipelines, industrial users, or for small power generation projects. We are expanding our capacity to transport western coal and are constructing a coal terminal.

Pipelines, Processing and Storage has a partnership interest in an interstate transmission pipeline, seven carbon dioxide processing facilities and a natural gas storage field, as well as lease rights to another natural gas storage field. The pipeline and storage assets are primarily supported by stable, long-term fixed price revenue contracts.

Factors impacting income: Fuel Transportation and Marketing results increased $204 million during the 2006 third quarter and increased $242 million in the nine-month period. The increase in 2006 is primarily a result of significant 2005 mark-to-market losses on derivative contracts used to economically hedge gas in storage and forward power contracts.

(in Millions)


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2006			2005			2006			2005
Operating Revenues	$	418		$	277		$	1,110		$	1,024
Fuel, Purchased Power and Gas		112			279			440			727
Operation and Maintenance		191			201			507			511
Depreciation and Amortization		3			2			7			5
Taxes Other Than Income		2			—			5			3

Operating Income (Loss)		110			(205	)		151			(222	)
Other (Income) and Deductions		(2	)		(5	)		(4	)		(6	)
Income Tax Provision (Benefit)		37			(71	)		52			(77	)

Net Income (Loss)	$	75		$	(129	)	$	103		$	(139	)

Operating revenues increased $141 million in the third quarter of 2006 and $86 million in the nine months ended September 2006. Compared to the third quarter 2005 period, the increase is due to $159 million in mark-to-market losses that occurred in the third quarter of 2005 which did not recur in 2006. Additionally, we had an $8 million decrease in realized revenues at DTE Energy Trading, along with a $4 million increase in storage revenues, partially offset by a $16 million decrease at Coal Transportation due to lower synfuel related volumes.

The year-to-date period increase of $86 million in operating revenues are due to $95 million in higher trading unit revenues driven by an increase of $243 million due to mark-to-market losses in 2005 that did not recur in 2006 and a decrease in realized revenues of $148 million largely driven by decreased wholesale gas revenues at DTE Energy Trading, along with a $12 million increase in storage revenues, partially offset by a $17 million decrease at Coal Transportation due to lower synfuel related volumes.

During the first nine months of 2005, DTE Energy Trading’s earnings were negatively impacted by the economically favorable decision to delay previously planned withdrawals from gas storage due to a decrease in the current price for natural gas and an increase in the forward price for natural gas. In addition, we entered into forward power contracts to economically hedge certain physical and capacity power contracts. The financial impacts of these timing differences have largely reversed in 2006 and are favorably impacting 2006 results.

Fuel, purchased power and gas decreased $167 million in the third quarter of 2006 and $287 million in the nine-month period of 2006 reflecting decreased power and gas trading volumes at DTE Energy Trading.

Operations and maintenance expenses decreased $10 million in the 2006 third quarter and $4 million in the 2006 nine-month period. The decreases were due to lower synfuel related volumes and decreased trading expenses at our Coal Transportation and Marketing unit due to decreased trading volume.

Income tax provision increased by $108 million in the 2006 third quarter and increased $129 million in the 2006 nine-month period reflecting variations in pre-tax income.

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. However, a portion of our Coal Transportation and Marketing revenues and net income are dependent upon our synfuel operations and have been adversely impacted by the temporary idling of the synfuel facilities. Gas storage and transportation capacity enhances our ability to provide reliable and custom-tailored bundled services

to large-volume end users and utilities. This capacity, coupled with the synergies from DTE Energy’s other businesses, positions the segment to add value and mitigate risks.

Pipeline, Processing and Storage business will continue its steady growth plan. We plan to expand existing assets and develop new assets which are typically supported with long-term customer commitments. In April 2006, Pipelines, Processing and Storage placed into service over 14 Bcf of storage capacity at an existing Michigan storage field. In addition, we intend to file two applications with the MPSC in the fourth quarter of 2006 for additional storage capacity expansion projects. Vector Pipeline has secured long-term market commitments to support an expansion project, for approximately 200 MMcf per day, with a projected in-service date of November 2007. Vector Pipeline received FERC approval in October 2006. Pipeline, Processing and Storage has a 26.25% ownership interest in Millennium Pipeline, which we expect to receive FERC approval in the fourth quarter of 2006. Millennium Pipeline is scheduled to be in service in November 2008. In October 2006, we purchased the lessor interest in the 66 Bcf Washington 10 gas storage field. Prior to the purchase, we leased the storage rights and lease obligations were recorded as operating leases. The acquisition resulted in a cash payment of approximately $13 million and the assumption of approximately $135 million of project related debt that will be recorded on our statement of financial position.

Significant portions of the Fuel Transportation and Marketing portfolio are economically hedged, with the exception of the Pipelines, Processing and Storage business which is primarily supported with long-term fixed price contracts. The portfolio includes financial instruments and gas inventory, as well as capacity positions of natural gas storage and pipelines and power transmission contracts. The financial instruments are deemed derivatives, whereas the gas inventory, pipelines and storage assets are not derivatives. As a result, we will experience earnings volatility as derivatives are marked to market without revaluing the underlying non-derivative contracts and assets. The majority of such earnings volatility is associated with the natural gas storage cycle, which does not coincide with the calendar and fiscal year, but runs annually from April of one year to March of the next year. Our strategy is to economically manage the price risk of storage with over-the-counter forwards and futures. Current accounting rules require the marking to market of forward sales and futures, but do not allow for the marking to market of the related gas inventory. This results in gains and losses that are recognized in different interim and annual accounting periods. We generally anticipate the financial impact of this timing difference will reverse by the end of each storage cycle. As part of a strategic review of our non-utility operations, we will explore alternative structures and strategic options for the energy trading business.

See “Fair Value of Contracts” section that follows.

CORPORATE & OTHER

Corporate & Other includes various corporate support functions such as accounting, legal and information technology services. As these functions essentially support the entire Company, their costs are fully allocated to the various segments based on services utilized. Therefore, the effect of the allocation on each segment can vary from year to year. Additionally, Corporate & Other holds certain non-utility debt, assets held for sale, and energy-related investments.

Factors impacting income: Corporate & Other’s results improved by $185 million in the 2006 third quarter and $134 million in the 2006 nine-month period. Results primarily reflect adjustments in 2005 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 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. We recognized a net of tax restructuring loss of $23 million during the third quarter of 2005, primarily representing the write down to fair value of the assets of Dtech, less costs to sell, and the write-off of goodwill. As we execute the restructuring plan, there may be adjustments to amounts recorded related to the impairment of Dtech assets and exit costs. We anticipate substantially completing the restructuring plan by the end of 2006. See Note 4.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES

In the first quarter of 2006, we adopted new accounting rules for stock-based compensation. The cumulative effect of adopting these new accounting rules increased 2006 year-to-date net income by $1 million. See Note 3.

CAPITAL RESOURCES AND LIQUIDITY

(in Millions)


	Nine Months Ended
	September 30
	2006			2005
Cash and Cash Equivalents
Cash Flow From (Used For):
Operating activities:
Net income	$	291		$	155
Depreciation, depletion and amortization		801			663
Deferred income taxes		24			121
Gain on sale of synfuel and other assets, net		(73	)		(211	)
Working capital and other		140			(135	)

		1,183			593


Investing activities:
Plant and equipment expenditures – utility		(830	)		(564	)
Plant and equipment expenditures – non-utility		(214	)		(145	)
Acquisitions, net of cash acquired		(27	)		—
Proceeds from sale of synfuel and other assets		247			307
Restricted cash and other investments		(16	)		(79	)

		(840	)		(481	)


Financing activities:
Issuance of long-term debt and common stock		554			795
Redemption of long-term debt		(672	)		(1,059	)
Short-term borrowings, net		44			472
Repurchase of common stock		(10	)		(12	)
Dividends on common stock and other		(282	)		(273	)

		(366	)		(77	)

Net Increase (Decrease) in Cash and Cash Equivalents	$	(23	)	$	35

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 up to approximately $1.2 billion to $1.4 billion of cash during 2006-2009.

Cash from operations totaling $1.2 billion in the 2006 nine-month period was up $590 million from the comparable 2005 period. The operating cash flow comparison reflects an increase of $315 million in net income, after adjusting for non-cash items (depreciation, depletion, amortization, deferred taxes and gains) and a $275 million decrease in working capital and other requirements. The working capital improvement was driven by MichCon and our non-utility segments. MichCon’s working capital improvement resulted primarily from declining GCR factors which had the effect of lowering customer accounts receivable balances. Lower cash margin deposit requirements at the energy trading business and lower hedging costs related to the synfuel business were significant factors in the improvement in the non-utility segments.

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.

Assuming that there is a significant synfuel tax credit phase-out, we anticipate approximately $1.2 billion to $1.4 billion of synfuel-related cash impacts from 2006 through 2009, which consists of cash from operations and proceeds from option hedges, and approximately $600 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 any 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. We plan to repurchase approximately 1 million shares of common stock beginning in November 2006. 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.

Investing Activities

Net cash outflows relating to investing activities increased $359 million in the 2006 nine-month period as compared to the same 2005 period. The 2006 change was primarily due to increased capital expenditures. The increase in capital expenditures was driven by environmental, nuclear fuel, DTE2 and other projects at Detroit Edison, in addition to growth-oriented projects across our non-utility segments.

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

Financing Activities

Net cash used for financing activities increased $289 million during the 2006 nine-month period, compared to the same 2005 period, due mostly to a decrease in short-term borrowings and issuance of common stock and long-term debt, partially offset by a decrease in debt redemptions.

CRITICAL ACCOUNTING POLICIES

Goodwill

Certain of our business units have goodwill resulting from purchase business combinations. In accordance with SFAS No. 142, Goodwill and Other Intangible Assets, each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value

of goodwill may be impaired. In order to perform these impairment tests, we must determine the reporting unit’s fair value using valuation techniques, which use estimates of discounted future cash flows to be generated by the reporting unit. These cash flow valuations involve a number of estimates that require broad assumptions and significant judgment by management regarding future performance. To the extent estimated cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill, which would adversely impact our earnings. Based on our 2005 goodwill impairment test, we determined that the fair value of our operating reporting units exceed their carrying value and no impairment existed.

As of September 30, 2006, our goodwill totaled $2.1 billion. The majority of our goodwill is allocated to our utility reporting units, with $772 million allocated to the Gas Utility reporting unit. The value of the utility reporting units may be significantly impacted by rate orders and the regulatory environment. The Gas Utility reporting unit is comprised primarily of MichCon. We have made certain assumptions for MichCon that incorporate earnings multiples used in the cash flow valuations. These assumptions may change as regulatory and market conditions change.

We also have $4 million of goodwill allocated to the Synthetic Fuel reporting unit. The value of the Synthetic Fuel reporting unit has been impacted by the anticipated phase-out of tax credits related to our synfuel business. As of September 30, 2006, we have evaluated the impact of a phase-out of synfuel tax credits on our valuation assumptions. We have determined that the fair value of the Synthetic Fuel reporting unit exceeds the carrying value and no impairment of goodwill exists. These assumptions may change as the value of the synfuel tax credits change.

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

NEW ACCOUNTING PRONOUNCEMENTS

See Note 3 – New Accounting Pronouncements for discussion of new pronouncements.

FAIR VALUE OF CONTRACTS

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

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

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

Contracts we typically classify as derivative instruments are power, gas and oil forwards, futures, options and swaps, as well as foreign currency contracts. Items we do not generally account for as derivatives (and which are therefore excluded from the following tables) include gas inventory, gas storage and transportation arrangements, full-requirements power contracts and gas and oil reserves. As subsequently

discussed, we have fully reserved the value of derivative contracts beyond the liquid trading timeframe thereby not impacting income.

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

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

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

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

•		“Other Non-Trading Activities” primarily represent derivative activity associated with our Michigan gas reserves and synfuel operations. A substantial portion of the price risk associated with the gas reserves has been mitigated through 2013. Changes in the value of the hedges are recorded as Assets or liabilities from risk management and trading activities, with an offset in other comprehensive income to the extent that the hedges are deemed effective. Oil-related derivative contracts have been executed to economically hedge cash flow risks related to underlying, non-derivative synfuel related positions through 2007. The amounts shown in the following tables exclude the value of the underlying gas reserves and synfuel proceeds including changes therein.

Roll-Forward of Mark-to-Market Energy Contract Net Assets

The following tables provide details on changes in our MTM net asset or (liability) position during 2006:

(in Millions)


													Other
	Trading Activities												Non-
	Proprietary			Structured			Economic						Trading
	Trading			Contracts			Hedges			Total			Activities			Total
MTM at December 31, 2005	$	(108	)	$	(136	)	$	(110	)	$	(354	)	$	(140	)	$	(494	)

Reclassed to realized upon settlement		(37	)		41			30			34			97			131
Liquidation of in-the-money positions (1)		—			—			(123	)		(123	)		—			(123	)
Changes in fair value recorded to income		(39	)		62			77			100			83			183
Amortization of option premiums		107			(2	)		—			105			—			105

Amounts recorded to unrealized income		31			101			(16	)		116			180			296
Amounts recorded in OCI		—			17			—			17			12			29
Option premiums paid and other		8			8			—			16			9			25

MTM at September 30, 2006	$	(69	)	$	(10	)	$	(126	)	$	(205	)	$	61		$	(144	)


(1)		In conjunction with our overall tax planning and cash initiatives, we monetized certain in-the-money contracts while simultaneously entering into at-the-market contracts with various counterparties. This had the impact of optimizing taxable income and cash flow while having minimal impact on earnings.

The following table provides a current and noncurrent analysis of Assets and liabilities from risk management and trading activities as reflected in the consolidated statement of financial position as of September 30, 2006. Amounts that relate to contracts that become due within twelve months are classified as current and all remaining amounts are classified as noncurrent.

(in Millions)


																Other
	Trading Activities															Non-			Total
	Proprietary			Structured			Economic									Trading			Assets
	Trading			Contracts			Hedges			Eliminations			Totals			Activities			(Liabilities)
Current assets	$	136		$	202		$	89		$	(26	)	$	401		$	174		$	575
Noncurrent assets		9			54			130			(1	)		192			70			262

Total MTM assets		145			256			219			(27	)		593			244			837


Current liabilities		(210	)		(191	)		(212	)		26			(587	)		(61	)		(648	)
Noncurrent liabilities		(4	)		(75	)		(133	)		1			(211	)		(122	)		(333	)

Total MTM liabilities		(214	)		(266	)		(345	)		27			(798	)		(183	)		(981	)


Total MTM net assets (liabilities)	$	(69	)	$	(10	)	$	(126	)	$	—		$	(205	)	$	61		$	(144	)

Maturity of Fair Value of MTM Energy Contract Net Assets

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

As a result of adherence to generally accepted accounting principles, the tables above do not include the expected favorable earnings impacts of certain non-derivative gas storage and power contracts. We entered into economically favorable transactions in early 2005 to delay previously planned withdrawals from gas storage due to a decrease in the current price for natural gas and an increase in the forward price for natural gas. As anticipated, the financial impact of this timing difference has reversed as the gas is withdrawn from storage in the current storage cycle and is sold at prices significantly in excess of the cost of gas in storage. In addition, we entered into forward power contracts to economically hedge certain physical and capacity power contracts. We expect the timing difference on the forward power contracts will be fully realized by the end of 2007.

The table below shows the maturity of our MTM positions:

(in Millions)


													Total
	2006			2007			2008			2009 and Beyond			Fair Value
Source of Fair Value
Proprietary Trading	$	(75	)	$	2		$	4		$	—		$	(69	)
Structured Contracts		21			(16	)		(11	)		(4	)		(10	)
Economic Hedges		(78	)		(43	)		(12	)		7			(126	)

Total Energy Trading		(132	)		(57	)		(19	)		3			(205	)
Other Non-Trading Activities		153			(16	)		(61	)		(15	)		61

Total	$	21		$	(73	)	$	(80	)	$	(12	)	$	(144	)

Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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

Our Power and Industrial Project and Synthetic Fuel segments are also subject to crude oil price risk. As previously discussed, production tax credits generated by DTE Energy’s synfuel, coke battery and landfill gas recovery operations are subject to phase-out if domestic crude oil prices reach certain levels. We have entered into a series of derivative contracts for 2006 through 2007 to economically hedge the impact of oil prices on a portion of our synfuel cash flow. See Note 2.

Credit Risk

Bankruptcies

We purchase and sell electricity, gas, coal, coke and other energy products from and to numerous companies operating in the steel, automotive, energy, retail and other industries. Certain of our customers have filed for bankruptcy protection under Chapter 11 of the U. S. Bankruptcy Code. We regularly review contingent matters relating to these customers and our purchase and sale contracts and we record provisions for amounts considered at risk of probable loss. We believe our previously accrued amounts are adequate for probable loss. The final resolution of these matters is not expected to have a material effect on our financial statements.

Other

We engage in business with customers that are non-investment grade. We closely monitor the credit ratings of these customers and, when deemed necessary, we request collateral or guarantees from such customers to secure their obligations. We utilize both external and internally generated credit assessments when determining the credit quality of our trading counterparties.

Interest Rate Risk

DTE Energy is subject to interest rate risk in connection with the issuance of debt and preferred securities. In order to manage interest costs, we 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 September 30, 2006, we have a floating rate debt to total debt ratio of approximately 15% (excluding securitized debt).

Foreign Currency Risk

DTE Energy has foreign currency exchange risk arising from market price fluctuations associated with fixed priced contracts. These contracts are denominated in Canadian dollars and are primarily for the purchase and sale of power as well as for long-term transportation capacity. To limit our exposure to foreign currency fluctuations, we have entered into a series of currency forward contracts through 2011. 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

CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures

Management of the Company carried out an evaluation, under the supervision and with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of September 30, 2006, which is the end of the period covered by this report. Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that such controls and procedures are effective in ensuring that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be met.

(b) Changes in internal control over financial reporting

There has been no change in the Company’s internal control over financial reporting during the quarter ended September 30, 2006 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

DTE Energy Company

Consolidated Statement of Operations (unaudited)

(in Millions, Except per Share Amounts)


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2006			2005			2006			2005
Operating Revenues	$	2,196		$	2,060		$	6,726		$	6,310


Operating Expenses
Fuel, purchased power and gas		629			839			2,277			2,446
Operation and maintenance		771			973			2,698			2,794
Depreciation, depletion and amortization		355			239			801			662
Taxes other than income		74			66			249			246
Asset (gains) and losses, reserves and impairments, net		(6	)		(108	)		116			(203	)

		1,823			2,009			6,141			5,945


Operating Income		373			51			585			365


Other (Income) and Deductions
Interest expense		123			129			390			385
Interest income		(9	)		(15	)		(34	)		(42	)
Other income		(17	)		(22	)		(41	)		(45	)
Other expenses		38			8			58			34

		135			100			373			332

Income (Loss) Before Income Taxes and Minority Interest		238			(49	)		212			33

Income Tax Provision		59			10			109			54

Minority Interest		(10	)		(88	)		(190	)		(209	)


Income from Continuing Operations		189			29			293			188

Loss from Discontinued Operations, net of tax (Note 4)		(1	)		(25	)		(3	)		(33	)

Cumulative Effect of Accounting Change, net of tax (Note 3)		—			—			1			—


Net Income	$	188		$	4		$	291		$	155


Basic Earnings per Common Share (Note 7)
Income from continuing operations	$	1.07		$	.17		$	1.65		$	1.08
Discontinued operations		(.01	)		(.15	)		(.02	)		(.19	)
Cumulative effect of accounting change		—			—			.01			—

Total	$	1.06		$	.02		$	1.64		$	.89


Diluted Earnings per Common Share (Note 7)
Income from continuing operations	$	1.07		$	.17		$	1.65		$	1.07
Discontinued operations		(.01	)		(.15	)		(.02	)		(.18	)
Cumulative effect of accounting change		—			—			.01			—

Total	$	1.06		$	.02		$	1.64		$	.89


Average Common Shares
Basic		177			176			177			174
Diluted		178			177			178			175

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

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statement of Financial Position

(in Millions)


	(Unaudited)
	September 30			December 31
	2006			2005
ASSETS
Current Assets
Cash and cash equivalents	$	65		$	88
Restricted cash		93			122
Accounts receivable
Customer (less allowance for doubtful accounts of $159 and $136, respectively)		1,152			1,746
Collateral held by others		248			286
Other		209			363
Accrued power and gas supply cost recovery revenue		178			186
Inventories
Fuel and gas		661			522
Materials and supplies		148			146
Deferred income taxes		143			257
Assets from risk management and trading activities		575			806
Other		238			160

		3,710			4,682


Investments
Nuclear decommissioning trust funds		709			646
Other		501			530

		1,210			1,176


Property
Property, plant and equipment		18,842			18,660
Less accumulated depreciation and depletion		(7,677	)		(7,830	)

		11,165			10,830


Other Assets
Goodwill		2,057			2,057
Regulatory assets		1,991			2,074
Securitized regulatory assets		1,264			1,340
Intangible assets		102			99
Notes receivable		226			409
Assets from risk management and trading activities		262			316
Prepaid pension assets		184			186
Other		145			166

		6,231			6,647


Total Assets	$	22,316		$	23,335

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Consolidated Statement of Financial Position

(in Millions, Except Shares)


	(Unaudited)
	September 30			December 31
	2006			2005
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	909		$	1,187
Accrued interest		128			115
Dividends payable		92			92
Short-term borrowings		884			943
Current portion of long-term debt, including capital leases		362			691
Liabilities from risk management and trading activities		648			1,089
Other		810			803

		3,833			4,920


Other Liabilities
Deferred income taxes		1,363			1,396
Regulatory liabilities		753			715
Asset retirement obligations (Note 1)		1,158			1,091
Unamortized investment tax credit		122			131
Liabilities from risk management and trading activities		333			527
Liabilities from transportation and storage contracts		288			317
Accrued pension liability		376			284
Deferred gains from asset sales		72			188
Minority interest		41			92
Nuclear decommissioning		94			85
Other		737			740

		5,337			5,566


Long-Term Debt (net of current portion) (Note 8)
Mortgage bonds, notes and other		5,724			5,234
Securitization bonds		1,185			1,295
Equity-linked securities		—			175
Trust preferred-linked securities		289			289
Capital lease obligations		84			87

		7,282			7,080


Commitments and Contingencies (Notes 2, 6 and 10)

Shareholders’ Equity
Common stock, without par value, 400,000,000 shares authorized, 177,964,872 and 177,814,429 shares issued and outstanding, respectively		3,480			3,483
Retained earnings		2,574			2,557
Accumulated other comprehensive loss		(190	)		(271	)

		5,864			5,769


Total Liabilities and Shareholders’ Equity	$	22,316		$	23,335

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statement of Cash Flows (Unaudited)

(in Millions)


	Nine Months Ended
	September 30
	2006			2005
Operating Activities
Net Income	$	291		$	155
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		801			663
Deferred income taxes		24			121
Gain on sale of interests in synfuel projects		(72	)		(180	)
Gain on sale of assets, net		(1	)		(31	)
Impairment of synfuel projects		124			—
Partners’ share of synfuel project losses		(191	)		(241	)
Contributions from synfuel partners		155			177
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		52			(71	)

Net cash from operating activities		1,183			593


Investing Activities
Plant and equipment expenditures – utility		(830	)		(564	)
Plant and equipment expenditures – non-utility		(214	)		(145	)
Acquisitions, net of cash acquired		(27	)		—
Proceeds from sale of interests in synfuel projects		203			251
Proceeds from sale of other assets		44			56
Restricted cash for debt redemptions		29			30
Proceeds from sale of nuclear decommissioning trust fund assets		136			159
Investment in nuclear decommissioning trust funds		(163	)		(188	)
Other investments		(18	)		(80	)

Net cash used for investing activities		(840	)		(481	)


Financing Activities
Issuance of long-term debt		545			623
Redemption of long-term debt		(672	)		(1,059	)
Short-term borrowings, net		44			472
Issuance of common stock		9			172
Repurchase of common stock		(10	)		(12	)
Dividends on common stock		(274	)		(268	)
Other		(8	)		(5	)

Net cash used for financing activities		(366	)		(77	)


Net Increase (Decrease) in Cash and Cash Equivalents		(23	)		35
Cash and Cash Equivalents at Beginning of the Period		88			56

Cash and Cash Equivalents at End of the Period	$	65		$	91

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statement of Changes in Shareholders’ Equity

and Comprehensive Income (unaudited)

(Dollars in Million, Shares in Thousands)


										Accumulated
										Other
	Common Stock						Retained			Comprehensive
	Shares			Amount			Earnings			Loss			Total
Balance, December 31, 2005		177,814		$	3,483		$	2,557		$	(271	)	$	5,769

Net income		—			—			291			—			291
Dividends declared on common stock		—			—			(274	)		—			(274	)
Issuance, repurchase and retirement of common stock, net		215			(1	)		—			—			(1	)
Net change in unrealized losses on derivatives, net of tax		—			—			—			87			87
Net change in unrealized gain on investments, net of tax		—			—			—			(6	)		(6	)
Unearned stock compensation and other		(64	)		(2	)		—			—			(2	)

Balance, September 30, 2006		177,965		$	3,480		$	2,574		$	(190	)	$	5,864

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

(in Millions)


	2006			2005
Net income	$	291		$	155

Other comprehensive income (loss), net of tax:
Net unrealized income (losses) on derivatives:
Gains (losses) arising during the period, net of taxes of $79 and $(103), respectively		146			(191	)
Amounts reclassified to earnings, net of taxes of $(32) and $15, respectively		(59	)		28

		87			(163	)
Net change in unrealized gain on investments, net of taxes of $(3) and $2		(6	)		4

		81			(159	)

Comprehensive income (loss)	$	372		$	(4	)

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited)

NOTE 1 — GENERAL

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

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

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

We reclassified certain prior year balances to match the current year’s financial statement presentation.

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

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. The impending loss of synfuel tax credits in 2007, combined with the sustained volatility of oil prices, increased management focus on synfuels, thereby requiring a separate business segment. There is approximately $41 million of goodwill previously allocated to the Power and Industrial Projects segment of which $4 million is attributable to the Synthetic Fuel business and $37 million to other businesses within the Power and Industrial segment. Our other segments, Electric Utility, Gas Utility, Unconventional Gas Production, Fuel Transportation and Marketing and Corporate and Other were unaffected by this realignment. Based on this structure, we set strategic goals, allocate resources and evaluate performance. Our segment information is based on the following alignment:

	•		Electric Utility, consisting of Detroit Edison;

	•		Gas Utility, primarily consisting of MichCon;

	•		Non-utility Operations

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

	•		Synthetic Fuel, consisting of the operations of the nine synfuel plants we operate;

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

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

•

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

Asset Retirement Obligations

We have recorded asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and FASB Interpretation FIN No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. We identified a legal retirement obligation for the decommissioning costs for our Fermi 1 and Fermi 2 nuclear plants. To a lesser extent, we have legal retirement obligations for the synthetic fuel operations, gas production facilities, gas

gathering facilities and various other operations. We identified conditional retirement obligations for gas pipeline retirement costs and disposal of asbestos at certain of our power plants. To a lesser extent, we have conditional retirement obligations at certain service centers, compressor and gate stations, and disposal costs for PCB contained within transformers and circuit breakers.

As to regulated operations, we believe that adoptions of SFAS No. 143 and FIN 47 result primarily in timing differences in the recognition of legal asset retirement costs that we are currently recovering in rates. We will be deferring such differences under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

A reconciliation of the asset retirement obligation for the 2006 nine-month period follows:

(in Millions)


Asset retirement obligations at January 1, 2006	$	1,091
Accretion		53
Liabilities incurred		4
Liabilities settled		(5	)
Revision in estimated cash flows		15

Asset retirement obligations at September 30, 2006	$	1,158

A significant portion of the asset retirement obligations represents nuclear decommissioning liabilities which are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear plant.

Retirement Benefits and Trusteed Assets

The components of net periodic benefit costs for qualified and non-qualified pension benefits and other postretirement benefits follow:

(in Millions)


							Other Postretirement
	Pension Benefits						Benefits
	2006			2005			2006			2005
Three Months Ended September 30
Service Cost	$	16		$	16		$	13		$	13
Interest Cost		44			43			30			27
Expected Return on Plan Assets		(56	)		(54	)		(17	)		(17	)
Amortization of
Net loss		15			17			19			15
Prior service cost		2			2			(1	)		(1	)
Net transition liability		—			—			2			1
Special Termination Benefits		19			—			3			—

Net Periodic Benefit Cost	$	40		$	24		$	49		$	38


Nine Months Ended September 30

Service Cost	$	48		$	49		$	44		$	41
Interest Cost		132			129			87			79
Expected Return on Plan Assets		(167	)		(163	)		(46	)		(52	)
Amortization of
Net loss		45			51			54			45
Prior service cost		6			6			(2	)		(2	)
Net transition liability		—			—			5			5
Special Termination Benefits		34			—			4			—

Net Periodic Benefit Cost	$	98		$	72		$	146		$	116

During the third quarter of 2006, we recorded a $19 million pension cost and a $3 million postretirement benefit cost associated with our Performance Excellence Process. For the nine-month period ending September 30, 2006, we recorded a $34 million pension cost and a $4 million postretirement benefit cost associated with our Performance Excellence Process. In the third quarter, we deferred $74 million of Performance Excellence Process costs at Detroit Edison pursuant to MPSC authorization. See Note 6. In 2006, we made cash contributions of $60 million to our postretirement benefit plans.

Consolidated Statement of Cash Flows

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

(in Millions)


	Nine Months Ended
	September 30
	2006			2005
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	546		$	(501	)
Accrued GCR revenue		149			5
Inventories		(143	)		(190	)
Accrued/Prepaid pensions		94			69
Accounts payable		(260	)		387
Accrued PSCR refund		(162	)		(121	)
Exchange gas payable		23			10
Income taxes payable		29			(165	)
General taxes		(17	)		(5	)
Risk management and trading activities		(266	)		612
Postretirement obligation		16			51
Other assets		(143	)		(63	)
Other liabilities		186			(160	)

	$	52		$	(71	)

Supplementary cash and non-cash information follows:

(in Millions)


	Nine Months Ended
	September 30
	2006		2005
Cash Paid for
Interest (excluding interest capitalized)	$	376	$	383
Income taxes	$	53	$	79
Noncash Investing and Financing Activities
Notes received from sale of synfuel projects		—	$	20
Sale of assets
Note receivable	$	—	$	47
Other assets	$	—	$	45

We have entered into a Margin Loan Facility (Facility) with an affiliate of the clearing agent of a commodity exchange in lieu of posting additional cash collateral (a non-cash transaction). The loan outstanding under the Facility was $17 million as of September 30, 2006 and $103 million as of December 31, 2005, and the related margin deposit is included in “collateral held by others” on the consolidated statement of financial position at December 31, 2005. See Note 9.

Asset (gains) and losses, reserves and impairments, net

The following items are included in the Asset (gains) and losses, reserves and impairments, net line in the consolidated statement of operations:

(in Millions)


	Three Months Ended						Nine Months Ended
	September 30						September 30
Description	2006			2005			2006		2005
Net Synthetic Fuels	$	(50	)	$	(80	)	$	52	$	(180	)
Non-utility impairments:
Waste coal recovery		4			—			20		—
Landfill gas recovery		3			—			3		—
Power generation		41			—			41		—

		48			—			64		—
Electric utility sale of land		—			(25	)		—		(25	)
Other, net		(4	)		(3	)		—		2

	$	(6	)	$	(108	)	$	116	$	(203	)

NOTE 2 – SYNFUEL OPERATIONS

Synthetic Fuel Operations

We are the operator of nine synthetic fuel production facilities throughout the United States. Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applicable Internal Revenue Service rules. Production tax credits are provided for the production and sale of solid synthetic fuels produced from coal. To qualify for the production tax credits, the synthetic fuel must meet three primary conditions: (1) there must be a significant chemical change in the coal feedstock, (2) the product must be sold to an unaffiliated entity, and (3) the production facility must have been placed in service before July 1, 1998. Through September 30, 2006, we have generated and recorded approximately $572 million in synfuel tax credits.

To reduce U.S. dependence on imported oil, the Internal Revenue Code provides production tax credits as an incentive for taxpayers to produce fuels from alternative sources. This incentive is not deemed necessary if the price of oil increases and provides significant market incentives for the production of these fuels. As such, the tax credit in a given year is reduced if the Reference Price of oil within that year exceeds a threshold price. The Reference Price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil. We project the yearly average wellhead price per barrel of oil for the year to be approximately $7 lower than the New York Mercantile Exchange (NYMEX) price for light, sweet crude oil. The threshold price at which the credit begins to be reduced was set in 1980 and is adjusted annually for inflation. For 2006, we estimate the threshold price at which the tax credit would begin to be reduced is $55 per barrel and would be completely phased out if the Reference Price reached $69 per barrel. As of October 31, 2006, the realized and unrealized NYMEX daily closing price of a barrel of oil was approximately $66 for 2006, equating to an estimated Reference Price of $59, which we estimate to be within the phase-out range. The average NYMEX daily closing price of a barrel of oil would have to average less than approximately $38 for the remainder of 2006 in order that no phase-out of production tax credits occurs. Unless oil prices drop significantly for the remainder of 2006, we expect a significant phase-out of the production tax credits in 2006 which could adversely impact our results of operations, cash flow, and financial condition.

To mitigate the effect of a potential phase-out and minimize operating losses, on May 12, 2006, we idled production at all nine of the synthetic fuel facilities that we operate. The decision to idle synfuel production was driven by the level and volatility of oil prices at that time. During the idle period, we renegotiated a significant number of commercial agreements which will result in lower operating costs at all the synthetic fuel facilities in the event of sustained high oil prices. Beginning September 5, 2006 through October 4, 2006, we resumed production at each of the nine synfuel facilities due to these amended commercial agreements and declines in the level of oil prices. However, we cannot predict with any certainty the Reference Price for the remainder of 2006 or beyond.

Gains (Losses) from Sale of Interests in Synthetic Fuel Facilities

Through September 2006, we have sold interests in all of the synthetic fuel production plants, representing approximately 91% of our total production capacity. Proceeds from the sales are contingent upon production levels, the production qualifying for production tax credits, and the value of such credits. Production tax credits are subject to phase-out if domestic crude oil prices reach certain levels. We recognize gains from the sale of interests in the synfuel facilities as synfuel is produced and sold, and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectibility is reasonably assured. Until the gain recognition criteria are met, gains from selling interests in synfuel facilities are deferred. It is possible that gains will be deferred in the first, second and/or third quarters of each year until there is persuasive evidence that no tax credit phase-out will occur for the applicable calendar year. This could result in shifting earnings from earlier quarters to later quarters of a calendar year. We have recorded no pre-tax gains from the sale of interests in synthetic fuel facilities in the third quarter of 2006 and a pre-tax gain of $39 million in the nine months ended September 30, 2006, compared to pre-tax gains of $34 million in the third quarter of 2005 and $91 million in the nine months ended September 30, 2005.

The gain from the sale of synfuel facilities is comprised of fixed and variable components. The fixed component represents note payments of principal and interest, is not subject to refund, and is recognized as a gain when earned and collectibility is assured. The variable component is based on an estimate of tax credits allocated to our partners 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. Additionally, based on estimates of tax credits allocated, our partners reimburse us (through the project entity) for the operating losses of the synfuel facilities, referred to as capital contributions. In the event that the tax credit is phased out, we are contractually obligated to refund 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. We recorded reserves for contractual partners’ obligations of $125 million through the second quarter of 2006. During the third quarter of 2006, we reversed $76 million of reserves due to the resumption of synfuel production.

Derivative Instruments — Commodity Price Risk

To manage our exposure in 2006 and 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 full years’ 2006 and 2007 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 2006 and 2007 are less than approximately $58, and $60, per barrel, respectively, the derivatives will yield no payment. If the average NYMEX prices of oil exceed approximately $58, and $60, per barrel, respectively, the derivatives will yield a payment equal to the excess of the average NYMEX price over these initial strike prices, multiplied by the number of barrels covered, up to a maximum price of approximately $73, and $71 per barrel, respectively. We also entered into put options based on the average of NYMEX prices during the second half of 2006. If the average of NYMEX prices falls below $68 per barrel for that period, we will receive payments on the difference between that

average price and $68, multiplied by the number of barrels covered. During the third quarter of 2006, we entered into derivative contracts that are based on the average NYMEX price for the remainder of 2006. These contracts are based on various terms to take advantage of favorable oil price movements. The agreements do not qualify for hedge accounting, therefore, the changes in the fair value of the options are recorded currently in earnings. The fair value changes were a pre-tax loss of $24 million in the third quarter of 2006 and a pre-tax gain of $83 million in the nine months ended September 30, 2006, compared to pre-tax gains of $46 million in the third quarter of 2005 and $89 million in the nine months ended September 30, 2005. 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.

Impairment

During the second quarter of 2006, we determined that certain assets related to our synfuel operations were impaired. The decision to record an impairment was based on the level and volatility of oil prices and the ability of the synfuel operations to generate production tax credits. During the second quarter of 2006, we recorded a pre-tax impairment loss of $123 million within the Asset (gains) and losses, reserves and impairments, net, line item in the consolidated statement of operations. The impairment primarily consists of two components; $77 million for synfuel related fixed assets and $42 million for a reserve for notes receivable related to the sale of interests in synfuel facilities. We based this decision utilizing expected undiscounted cash flows from the use and eventual disposition of the assets and determined that the carrying amount of the assets exceeded their expected fair value. The impairment was partially offset by $70 million, representing our partners’ share of the asset write down, included in the Minority Interest line in the consolidated statement of operations. During the third quarter of 2006, we recorded an additional reserve for notes receivable of $2 million, resulting in a reserve of $44 million at September 30, 2006.

Guarantees

We have provided certain guarantees and indemnities in conjunction with the sales of interests in our synfuel facilities. The guarantees cover general commercial, environmental, oil price and tax-related exposure and will survive until 90 days after expiration of all applicable statute of limitations. We estimate that our maximum potential liability under these guarantees at September 30, 2006 is $2.2 billion. Through the third quarter of quarter of 2006, we have reserved $140 million of our maximum potential liability for the possible refund of certain payments made by our synfuel partners and reserves on partner capital contributions related to tax credits generated during 2006.

NOTE 3 – NEW ACCOUNTING PRONOUNCEMENTS

Stock-Based Compensation

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

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

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

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

As of September 30, 2006, no performance units have been granted under either the LTIP or the previous stock incentive plan.

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

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

	•		Net income was reduced by $1 million;

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

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

Stock-based compensation for the reporting periods is as follows:

(in Millions)


	Three Months Ended				Nine Months Ended
	September 30				September 30
	2006		2005		2006		2005
Stock-based compensation expense	$	4	$	3	$	17	$	11
Tax benefit of compensation expense	$	2	$	1	$	6	$	4

The cumulative effect of the adoption of SFAS 123(R) was an increase in net income of $1 million as a result of estimating forfeitures for previously granted stock awards and performance shares. We have not restated any prior periods as a result of the adoption of SFAS 123(R). We generally purchase shares on the open market for options that are exercised or we may settle in cash other stock based compensation.

Options

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

(In Millions)


				Weighted		Aggregate
	Number of			Average		Intrinsic
	Options			Exercise Price		Value
Outstanding at December 31, 2005		6,236,343		$	41.31
Granted Granted		621,720		$	43.39
Exercised		(101,857	)	$	37.30
Forfeited or Expired		(142,146	)	$	42.73

Outstanding at September 30, 2006		6,614,060		$	41.53	$	7


Exercisable at September 30, 2006		5,023,649				$	6


	(1)		As of September 30, 2006 and 2005, the weighted average remaining contractual life for the exercisable shares is 5.25 years and 5.97 years respectively.

	(2)		During the first nine months of 2006 and 2005, 1,168,411 and 1,408,009 options, respectively, vested during the period.

The weighted average grant date fair value of options granted during the first nine months of 2006 and 2005 was $6.12 and $5.89, respectively. The intrinsic value of options exercised for both the nine month

periods ending September 30, 2006 and 2005 was less than $1 million and $8 million, respectively. Total option expense recognized during the first nine months of 2006 was $5 million.

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


					Weighted
			Weighted		Average
Range of	Number of		Average		Remaining
Exercise Prices	Options		Exercise Price		Contractual Life (years)
$27.62 - $38.04		384,834		$31.26		3.13
$38.60 - $42.44		3,616,270		$40.65		6.01
$42.60 - $44.54		1,075,255		$43.08		7.32
$44.56 - $48.00		1,537,701		$45.09		6.70

		6,614,060		$41.53		6.22

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


	September 30		December 31
	2006		2005
Risk-free interest rate		4.87%		3.93%
Dividend yield		4.99%		4.60%
Expected volatility		19.25%		19.56%

Expected life	6 years		6 years

Fair value per option		$6.12		$5.89

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

Pro forma information for the three and nine months ended September 30, 2005 is provided to show what our net income and earnings per share would have been if compensation costs had been determined as prescribed by SFAS 123(R):

(in Millions, except per share amounts)


	Three Months Ended			Nine Months Ended
	September 30,			September 30,
	2005			2005
Net Income As Reported	$	4		$	155
Less: Total stock-based expense		(2	)		(5	)

Pro Forma Net Income	$	2		$	150


Earnings Per Share
Basic – as reported	$	.02		$	.89

Basic – pro forma	$	.01		$	.86


Diluted – as reported	$	.02		$	.89

Diluted – pro forma	$	.01		$	.86

Stock Awards

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

The stock awards are recorded at cost that approximates fair value on the date of grant. We account for stock awards as unearned compensation, which is recorded as a reduction to common stock. The cost is amortized to compensation expense over the vesting period. Stock award activity for the periods ended September 30 was:


	Three Months Ended				Nine Months Ended
	September 30				September 30
	2006		2005		2006		2005
Fair value of awards vested (in millions)	$	1	$	—	$	5	$	4
Restricted common shares awarded		1,500		40,000		246,305		280,160
Weighted average market price of shares awarded	$	41.59	$	45.72	$	43.14	$	44.98
Compensation cost charged against income (in millions)	$	2	$	2	$	7	$	6

The following table summarizes our stock awards activity for the nine months ended September 30, 2006:


	Restricted			Weighted Average Grant Date
	Stock			Fair Value
Balance at December 31, 2005		544,087		$	42.68
Grants		246,305		$	43.14
Forfeitures		(26,391	)	$	42.87
Vested		(109,047	)	$	41.81

Balance at September 30, 2006		654,954		$	42.99

Performance Share Awards

Performance shares awarded under the plan are for a specified number of shares of common stock that entitles the holder to receive a cash payment, shares of common stock or a combination thereof. The final value of the award is determined by the achievement of certain performance objectives. The awards vest at the end of a specified period, usually three years. We account for performance share awards by accruing compensation expense over the vesting period based on: (i) the number of shares expected to be paid which is based on the probable achievement of performance objectives; and (ii) the fair value of the shares. We recorded compensation expense as follows:

(in millions)


	Three Months Ended				Nine Months Ended
	September 30				September 30
	2006		2005		2006		2005
Compensation expense	$	1	$	1	$	5	$	5
Cash settlements (1)	$	—	$	—	$	4	$	5


(1)		approximates the intrinsic value of the liability.

During the vesting period, the recipient of a performance share award has no shareholder rights. However, recipients will be paid an amount equal to the dividend equivalent on such shares. Performance share awards are nontransferable and are subject to risk of forfeiture. As of September 30, 2006, there were 1,084,983 performance share awards outstanding.

The following table summarizes our performance share activity for the nine months ended September 30, 2006:


	Performance Shares
Balance at December 31, 2005		803,071
Grants		520,395
Forfeitures		(83,258	)
Payouts		(155,225	)

Balance at September 30, 2006		1,084,983

As of September 30, 2006, there was $28 million of total unrecognized compensation cost related to non-vested stock incentive plan arrangements. That cost is expected to be recognized over a weighted-average period of 1.36 years.


	(In millions)
	Unrecognized		(in years)
Type	Compensation cost		Weighted Average to be recognized
Stock Awards	$	12		1.37
Performance Shares		11		1.43
Options		5		1.20

	$	28		1.36

The tax benefit realized for tax deductions related to our stock incentive plan totaled $6 million for the nine months ended September 30, 2006. Approximately $2 million of compensation cost was capitalized as a part of fixed assets during the first nine months of 2006.

Accounting for Uncertainty in Income Taxes

In July 2006, the FASB issued Financial Interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109 – Accounting for Income Taxes. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109. Additionally, it prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in the tax return. FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition and is effective for fiscal years beginning after December 15, 2006. We plan to adopt FIN 48 on January 1, 2007. We are currently assessing the effects of this interpretation, and have not yet determined the impact on the consolidated financial statements.

Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. It emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Fair value measurement should be determined based on the assumptions that market participants would use in pricing an asset or liability. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We plan to adopt SFAS 157 on January 1, 2008. We are currently assessing the effects of this statement, and have not yet determined the impact on the consolidated financial statements.

Accounting for Defined Benefit Pension and Other Postretirement Plans

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an Amendment of FASB Statements No. 87, 88, 106, and 132(R). SFAS 158 requires companies to (1) recognize the overfunded or underfunded status of defined benefit pension and defined benefit other postretirement plans in its financial statements, (2) recognize as a component of other comprehensive income, net of tax, the actuarial gains or losses and the prior service costs or credits that arise during the period but are not immediately recognized as components of net periodic benefit cost, (3) recognize adjustments to other comprehensive income when the actuarial gains or losses, prior service costs or credits, and transition assets or obligations are recognized as components of net periodic benefit cost, (4) measure postretirement benefit plan assets and plan obligations as of the date of the employer’s statement of financial position, and (5) disclose additional information in the notes to financial statements about certain effects on net periodic benefit cost in the upcoming fiscal year that arise from delayed recognition of the actuarial gains and losses and the prior service cost and credits.

The requirement to recognize the funded status of a postretirement benefit plan and the related disclosure requirements is effective for fiscal years ending after December 15, 2006. We plan to adopt this requirement as of December 31, 2006. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. We plan to adopt this requirement as of December 31, 2008. We are currently assessing the effects of this statement, and have not yet determined the impact on the consolidated financial statements.

Accounting for Planned Major Maintenance

In September 2006, the FASB issued its Staff Position (FSP), AUG AIR-1, Accounting for Planned Major Maintenance Activities. This FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. The FSP is effective for fiscal years beginning after December 15, 2006. We have historically charged expenditures for maintenance and repairs to expense as they were incurred, with the exception of Fermi 2, where we have utilized the accrue-in-advance policy for nuclear refueling outage costs since the plant was placed in service in 1988. We plan to adopt this FSP as of January 1, 2007. We are currently assessing the effects of this statement, and have not yet determined the impact on the consolidated financial statements.

Quantifying Misstatements

In September 2006, the SEC staff issued Staff Accounting Bulletin (SAB) Topic 1N, Financial Statements — Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements (SAB 108). SAB 108 addresses how a registrant should quantify the effect of an error on the financial statements. The SEC staff concludes in SAB 108 that a dual approach should be used to compute the amount of a misstatement. Specifically, the amount should be computed using both the “rollover” (current year income statement perspective) and “iron curtain” (year-end balance sheet perspective) methods. SAB 108 is effective for years ending after November 15, 2006. We plan to adopt SAB 108 as of December 31, 2006. We are currently assessing the effects of this statement, and have not yet determined the impact on the consolidated financial statements.

NOTE 4 – DISCONTINUED OPERATIONS

Discontinued Operations — DTE Energy Technologies (Dtech)

We own Dtech, which assembled, marketed, distributed and serviced distributed generation products, provided application engineering, and monitored and managed on-site generation system operations. In July 2005, management approved the restructuring of this business resulting in the identification of

certain assets and liabilities to be sold or abandoned, primarily associated with standby and continuous duty generation sales and service. The systems monitoring business and certain other operations are planned to be retained by the Company. We anticipate substantially completing the restructuring plan by the end of 2006.

During the third quarter of 2005, the restructuring plan met criteria to classify the assets as “held for sale.” Accordingly, we recognized a net of tax restructuring loss of $23 million during the third quarter of 2005 primarily representing the write down to fair value of the assets of Dtech, less costs to sell, and the write-off of goodwill of $16 million. As of September 30, 2006, Dtech assets are $2 million, consisting primarily of receivables and inventory, and liabilities are $7 million.

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

(in millions)


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2006			2005			2006			2005
Revenues (1)	$	—		$	3		$	—		$	13
Expenses		(2	)		(37	)		(5	)		(58	)

Loss before taxes		(2	)		(34	)		(5	)		(45	)
Income tax benefit		1			9			2			13

(Loss) from Discontinued Operations	$	(1	)	$	(25	)	$	(3	)	$	(32	)


(1)		Includes intercompany revenues of $1 million and $4 million for the three and nine months ended September 30, 2005, respectively.

NOTE 5 – IMPAIRMENTS AND RESTRUCTURING

Impairments

Waste Coal Recovery

During the first quarter of 2006, our Power and Industrial Projects segment impaired its investment in proprietary technology used to refine waste coal. The fixed assets at our development operation were impaired due to continued operating losses and negative cash flow. In addition, we impaired all our patents related to waste coal technology. Through September 30, 2006, we have recorded a pre-tax impairment loss of $20 million ($16 million in the first quarter and $4 million in the third quarter) within the Asset (gains) and losses, reserves and impairments, net line in the consolidated statement of operations. We calculated the expected undiscounted cash flows from the use and eventual disposition of the assets, which indicated that the carrying amount of the assets was not recoverable. We determined the fair value of the assets utilizing a discounted cash flow technique.

Landfill Gas Recovery

During the third quarter of 2006, our Power and Industrial Projects segment recorded a pre-tax impairment loss of $3 million at our landfill gas recovery unit relating to the write-down of assets at several landfill sites. The fixed assets were impaired due to continued operating losses and the oil price-related phase-out of production tax credits. The impairment was recorded within the Asset (gains) and losses, reserves and impairments, net line in the consolidated statement of operations. We calculated the expected undiscounted cash flows from the use and eventual disposition of the assets, which indicated

that the carrying amount of certain assets was not recoverable. We determined the fair value of the assets utilizing a discounted cash flow technique.

Non-Utility Power Generation

During the third quarter of 2006, our Power and Industrial Projects segment recorded a pre-tax impairment loss totaling $72 million for its investments in two natural gas-fired electric generating plants.

A loss of $41 million related to a 100% owned plant is recorded within the Asset (gains) and losses, reserves and impairments, net line in the consolidated statement of operations. The generating plant was impaired due to continued operating losses and the September 2006 delisting by MISO, resulting in the plant no longer providing capacity for the power grid. We calculated the expected undiscounted cash flows from the use and eventual disposition of the plant, which indicated that the carrying amount of the plant was not recoverable. We determined the fair value of the plant utilizing a discounted cash flow technique.

A loss of $31 million related to a 50% equity interest in a plant is recorded within the Other (income) and deductions, other expenses line in the consolidated statement of operations. The investment was impaired due to continued operating losses and the expected sale of the investment. We determined the fair value of the plant utilizing a discounted cash flow technique, which indicated that the carrying amount of the investment exceeded its fair value.

Restructuring – Performance Excellence Process

In mid-2005, we initiated a company-wide review of our operations called the Performance Excellence Process. We have identified the Performance Excellence Process as critical to our long-term growth strategy. The overarching goal has been to become more competitive by reducing costs, eliminating waste and optimizing business processes while improving customer service. Additionally, we will need significant resources in the future to invest in maintaining the capital infrastructure and meeting compliance mandates. Specifically, we began a series of focused improvement initiatives within our Electric and Gas Utilities, and associated corporate support functions. We expect this process will be carried out over a two-to three- year period beginning in 2006.

We have incurred costs to achieve (CTA) for employee severance and other costs, consisting primarily of project management and consultant support. Detroit Edison’s CTA is estimated to total between $160 million and $190 million. MichCon’s CTA is estimated to total between $55 million and $60 million. Pursuant to MPSC authorization, in the third quarter of 2006, Detroit Edison deferred approximately $74 million of CTA, including all amounts incurred in the third quarter and approximately $49 million of costs that were previously expensed through June 30, 2006. Detroit Edison will begin amortizing deferred 2006 costs in 2007 as the recovery of these costs was provided for by the MPSC. MichCon cannot defer CTA costs at this time because a recovery mechanism has not been established. See Note 6.

Amounts expensed are recorded within the operations and maintenance line in the consolidated statement of operations. Deferred amounts are recorded within the regulatory asset line in the consolidated statement of financial position. Expenses incurred in 2006 are as follows:


	Employee Severance Costs					Other Costs					Total Cost
	Three			Nine		Three			Nine		Three			Nine
	Months			Months		Months			Months		Months			Months
	Ended			Ended		Ended			Ended		Ended			Ended
	September			September		September			September		September			September
Business Segment	30			30		30			30		30			30
Costs incurred:
Electric Utility	$	18		$	36	$	10		$	41	$	28		$	77
Gas Utility		8			10		4			8		12			18
Other		1			1		—			1		1			2

Total costs		27			47		14			50		41			97

Less amounts deferred or capitalized:
Electric Utility		36			36		41			41		77			77
Gas Utility		—			—		—			—		—			—

		36			36		41			41		77			77


Amount expensed	$	(9	)	$	11	$	(27	)	$	9	$	(36	)	$	20

A liability for future CTA associated with the Performance Excellence Process has not been recognized because we have not met the recognition criteria pursuant to SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities.

NOTE 6 – REGULATORY MATTERS

Electric Rate Restructuring Proposal

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

2004 PSCR Reconciliation and 2004 Net Stranded Cost Case

In accordance with the MPSC’s directive in Detroit Edison’s November 2004 rate order, in March 2005, Detroit Edison filed a joint application and testimony in its 2004 PSCR Reconciliation Case and its 2004 Net Stranded Cost Recovery Case. In September 2006, the MPSC issued an order recognizing $19 million of 2004 net stranded costs that required Detroit Edison to write off $112 million of 2004 net stranded costs. The MPSC order resulted in a $39 million reduction in the 2004 PSCR over-collection by allowing Detroit Edison to retain the benefit of third party wholesale sales required to support the electric Customer Choice program and to offset the recognition of the $19 million of 2004 stranded costs. The MPSC order also resulted in adjustments to accrued interest on the 2004 and 2005 PSCR amounts of $15 million. The MPSC directed Detroit Edison to include the remaining 2004 PSCR over-collection amount and related interest in the 2005 PSCR Reconciliation which is in an under-collected position. The order resulted in a reduction of pre-tax income of approximately $58 million.

MPSC Show-Cause Order

In March 2006, the MPSC issued an order directing Detroit Edison to show cause by June 1, 2006 why its retail electric rates should not be reduced in 2007. The MPSC cited certain changes that have occurred since the November 2004 order in Detroit Edison’s last general rate case, or are expected to occur. These changes included: declines in electric Customer Choice program participation, expiration of the residential rate caps, and projected reductions in Detroit Edison operating costs. The show cause filing was to reflect sales, costs and financial conditions that were expected to occur by 2007. On June 1, 2006, Detroit Edison filed its response explaining why its electric rates should not be reduced in 2007. Detroit Edison indicated that it will have a revenue deficiency of approximately $45 million beginning in 2007 due to significant capital investments over the next several years for infrastructure improvements to enhance electric service reliability and for mandated environmental expenditures. The impacts of these investments will be partially offset by efficiency and cost-savings measures that have been initiated. Therefore, Detroit Edison requested that the show cause proceeding allow for rate increase adjustments based on the combined effects of investment expenditures and cost-savings programs. The MPSC denied this request and indicated that a full review of rates will be made in Detroit Edison’s next general rate case, which is due to be filed by July 1, 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 the later of March 31, 2008 or 12 months from the filing date of Detroit Edison’s next main case, rates will be reduced by an additional $26 million, for a total reduction of $79 million. 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 share of the rate reduction to the commercial and industrial customer classes than to the residential customer classes.

As part of the settlement agreement, a Choice Incentive Mechanism (CIM) was established with a base level of electric choice sales set at 3,400 GWh. The CIM prescribes regulatory treatment of changes in non-fuel revenue attributed to increases or decreases in electric Customer Choice sales. The CIM has a deadband of ±200 GWh. If electric Customer Choice sales exceed 3,600 GWh, Detroit Edison will be able to recover 90% of its reduction in non-fuel revenue from full service customers up to $71 million. If electric Customer Choice sales fall below 3,200 GWh, Detroit Edison will credit 100% of the increase in non-fuel revenue to the unrecovered regulatory asset recovery balances.

Regulatory Accounting Treatment for Performance Excellence Process

In May 2006, Detroit Edison and MichCon filed applications with the MPSC to allow deferral of costs associated with the implementation of the Performance Excellence Process, a company-wide cost-savings and performance improvement program. Implementation costs include project management, consultant support and employee severance expenses. Detroit Edison and MichCon sought MPSC authorization to defer and amortize Performance Excellence Process implementation costs for accounting purposes to match the expected savings from the Performance Excellence Process program with the related CTA. Detroit Edison and MichCon anticipate that the Performance Excellence Process will be carried out over a two- to three-year period beginning in 2006. Detroit Edison’s CTA is estimated to total between $160 million and $190 million. MichCon’s CTA is estimated to total between $55 million and $60 million. 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 recorded the deferred CTA costs of $74 million as a regulatory asset and will begin 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. MichCon cannot defer CTA costs at this time because a recovery mechanism has not been established.

Power Supply Costs Recovery Proceedings

2005 Plan Year – In September 2004, Detroit Edison filed its 2005 PSCR plan case seeking approval of a levelized PSCR factor of 1.82 mills per kWh above the amount included in base rates. In December 2004, Detroit Edison filed revisions to its 2005 PSCR plan case in accordance with the November 2004 MPSC rate order. The revised filing seeks approval of a levelized PSCR factor of up to 0.48 mills per kWh above the new base rates established in the final electric rate order. Included in the factor are power supply costs, transmission expenses and nitrogen oxide (NOx) emission allowance costs. Detroit Edison self-implemented a factor of negative 2.00 mills per kWh on January 1, 2005. Effective June 1, 2005, Detroit Edison began billing the maximum allowable factor of 0.48 mills per kWh due to increased power supply costs. In September 2005, the MPSC approved Detroit Edison’s 2005 PSCR plan case. At December 31, 2005, Detroit Edison has recorded an under-recovery of approximately $144 million related to the 2005 plan year. In March 2006, Detroit Edison filed its 2005 PSCR reconciliation. The filing seeks approval for recovery of approximately $144 million from its commercial and industrial customers. The filing included a motion for entry of an order to implement immediately a reconciliation surcharge of 4.96 mills per kWh on the bills of its commercial and industrial customers. The under-collected PSCR expense allocated to residential customers could not be recovered due to the PA 141 rate cap for residential customers, which expired January 1, 2006. In addition to the 2005 PSCR Plan Year Reconciliation, the filing included a reconciliation for the Pension Equalization Mechanism (PEM) for the periods from November 24, 2004 through December 31, 2004 and from January 1, 2005 through December 31, 2005. The PEM reconciliation seeks to allocate and refund approximately $12 million to customers based upon their contributions to pension expense during the subject periods. The September 2006 order in the Company’s 2004 PSCR Reconciliation and Stranded Cost proceeding directed the Company to roll the entire 2004 PSCR over-collection amount to the Company’s 2005 PSCR Reconciliation, thereby reducing the Company’s 2005 PSCR Reconciliation under-collection amount for commercial and industrial customers to $64 million.

2006 Plan Year — In September 2005, Detroit Edison filed its 2006 PSCR plan case seeking approval of a levelized PSCR factor of 4.99 mills per kWh above the amount included in base rates for residential customers and 8.29 per kWh above the amount included in base rates for commercial and industrial customers. Included in the factor for all customers are fuel and power supply costs, including transmission expenses, Midwest Independent Transmission System Operator (MISO) market participation costs, and NOx emission allowance costs. The Company’s PSCR Plan includes a matrix which provides for different maximum PSCR factors contingent on varying electric Customer Choice sales levels. The plan also includes $97 million for recovery of its projected 2005 PSCR under-collection associated with commercial and industrial customers. Additionally, the PSCR plan requests MPSC approval of expense associated with sulfur dioxide emission allowances, mercury emission allowances, and a fuel additive. In conjunction with DTE Energy’s sale of the transmission assets of ITC in February 2003, the FERC froze ITC’s transmission rates through December 2004. In approving the sale, FERC authorized ITC recovery of the difference between the revenue it would have collected and the actual revenue ITC did collect during the rate freeze period. At December 31, 2005, this amount is estimated to be $66 million which is to be included in ITC’s rates over a five-year period beginning June 1, 2006. It is expected that this amortization will increase Detroit Edison’s transmission expense in 2006 by $7 million. The MPSC authorized Detroit Edison in 2004 to recover transmission expenses through the PSCR mechanism.

In December 2005, the MPSC issued a temporary order authorizing the Company to begin implementation of maximum quarterly PSCR factors on January 1, 2006. The quarterly factors reflect a downward adjustment in the Company’s total power supply costs of approximately 2% to reflect the potential variability in cost projections. The quarterly factors will allow the Company to more closely track the costs of providing electric service to our customers and, because the non-summer factors are well below those ordered for the summer months, effectively delay the higher power supply costs to the summer months at which time our customers will not be experiencing large expenditures for home

heating. The MPSC did not adopt the Company’s request to recover its projected 2005 PSCR under-collection associated with commercial and industrial customers nor did it adopt the Company’s request to implement contingency factors based upon the Company’s increased costs associated with providing electric service to returning electric Customer Choice customers. The MPSC deferred both of those Company proposals to the final order on the Company’s entire 2006 PSCR Plan. In September 2006, the MPSC issued an order in this case that approved the inclusion of sulfur dioxide emission allowance expense in the PSCR, determined that fuel additive expense should not be included in the PSCR based upon its impact on maintenance expense, found the Company’s determination of third party sales revenues to be correct, and allowed the Company to increase its PSCR factor for the balance of the year in an effort to reverse the effects of the previously ordered temporary reduction. This factor increase will effectively reduce the projected 2006 PSCR under-collection by $36 million to $130 million. The MPSC declined to rule on the Company’s requests to include mercury emission allowance expense in the PSCR or its request to include prior PSCR over/(under) recoveries in future year PSCR plans. We have filed a petition for re-hearing.

2007 Plan Year — In September 2006, Detroit Edison filed its 2007 PSCR plan case seeking approval of a levelized PSCR factor of 6.98 mills per kWh above the amount included in base rates for all PSCR customers. The Company’s PSCR plan includes $130 million for the recovery of its projected 2006 PSCR under-collection, bringing the total requested PSCR factor to 9.73 mills/kWh. The Company’s application includes a request for an early hearing and temporary order granting such ratemaking authority. The Company’s 2007 PSCR Plan includes fuel and power supply costs, including NOx and sulfur dioxide emission allowance costs, transmission costs and MISO costs.

Electric Shut-Off and Restoration

In June 2006, the MPSC approved a settlement agreement with Detroit Edison regarding issues related to service restoration. The MPSC had determined that restoration of certain electric service shut-offs effected between October 28, 2005 and March 14, 2006 did not conform to MPSC rules. The settlement agreement directed Detroit Edison to bring its service restoration process into compliance with MPSC rules and submit monthly reports identifying progress toward compliance. Detroit Edison also paid a fine of $105,000 and filed a plan with the MPSC that details assistance customers can receive to avoid service shut-offs.

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

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

Gas Cost Recovery Proceedings

2004 Plan Year — In September 2003, MichCon filed its 2004 GCR plan case proposing a maximum GCR factor of $5.36 per Mcf. MichCon agreed to switch from a calendar year to an operational year as a condition of its settlement in the 2003 GCR plan case. The operational GCR year runs from April to

March of the following year. To accomplish the switch, the 2004 GCR plan reflected a 15-month transitional period, January 2004 through March 2005. Under this transition proposal, MichCon filed two reconciliations pertaining to the transition period; one in June 2004 addressing January through March 2004, one filed in June 2005 addressing the remaining April 2004 through March 2005 period and consolidating the two for purposes of the case. The June 2005 filing supported the $46 million under-recovery with interest MichCon had accrued for the period ending March 31, 2005. In March 2006, MPSC Staff filed testimony recommending an adjustment to the accounting treatment of the injected base gas remaining in the New Haven storage field when it was sold in early 2004 that would result in a $3 million reduction to MichCon’s accrued underrecovery. In June 2006, an MPSC ALJ issued a PFD recommending an approximately $43 million under-recovery. MichCon recorded the $3 million reduction to the 2004 underrecovery in the second quarter of 2006. The MPSC issued an order in August 2006 authorizing MichCon to roll a $42 million net underrecovery, including interest, into its 2005 – 2006 GCR reconciliation. This order disallowed $0.3 million related to the sale of storage services and concurrent reduction in gas purchases in February and March of 2005. The MPSC also found that the Staff’s proposed accounting for the sale of the New Haven injected base gas was appropriate.

2005-2006 Plan Year — In December 2004, MichCon filed its 2005-2006 GCR plan case proposing a maximum GCR factor of $7.99 per Mcf. The plan includes quarterly contingent GCR factors. These contingent factors will allow MichCon to increase the maximum GCR factor to compensate for increases in gas market prices, thereby reducing the possibility of a GCR under-recovery. In April 2005, the MPSC issued an order recognizing that Michigan law allows MichCon to self-implement its quarterly contingent factors. MichCon self-implemented quarterly contingent GCR factors of $8.54 per Mcf in July 2005 and $10.09 per Mcf in October 2005. In response to market price increases in the fall of 2005, MichCon filed a petition to reopen the record in the case during September 2005. MichCon proposed a revised maximum GCR factor of $13.10 per Mcf and a revised contingent factor matrix. In October 2005, the MPSC approved an increase in the GCR factor to a cap of $11.3851 per Mcf for the period November 2005 through March 2006. In June 2006, MichCon filed its GCR reconciliation for the 2005-2006 GCR year. The filing supported a total over-recovery, including interest through March 2006, of $13 million. An MPSC order is expected in 2007.

2006-2007 Plan Year – In December 2005, MichCon filed its 2006-2007 GCR plan case proposing a maximum GCR Factor of $12.15 per Mcf. In July 2006, MichCon and the parties to the case reached a settlement agreement that provides for a maximum GCR factor of $8.95 per Mcf, plus quarterly contingent GCR factors. These contingent factors will allow MichCon to increase the maximum GCR factor to compensate for increases in gas market prices, thereby reducing the possibility of a GCR under-recovery. The MPSC issued an order approving the settlement in August 2006.

Revenue Sufficiency Guarantee

Since the April 2005 implementation of Midwest Independent Transmission System Operator (MISO) market operations, MISO’s business practice manuals and other instructions to market participants have stated that Revenue Sufficiency Guarantee (RSG) charges will not be imposed on day-ahead virtual offers to supply power. RSG charges are collected by MISO from market participants in order to compensate generators that are standing by to supply electricity when called upon by MISO. In an April 2006 order, FERC interpreted MISO’s tariff to require that virtual supply offers be subject to RSG charges. Thus, FERC ordered MISO to recalculate RSG charges, and assess the same on all virtual supply offers, retroactive to April 1, 2005.

Numerous requests for rehearing were filed and in October 2006 FERC issued its order on rehearing as to refunds associated with virtual transactions. In this order, FERC reversed its earlier position and now finds retroactive refunds to be inappropriate. Therefore, DTE Energy has no exposure for additional RSG charges.

Other

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

NOTE 7 – COMMON STOCK AND EARNINGS PER SHARE

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

(Millions, except per share amounts)


	Three Months Ended				Nine Months Ended
	September 30				September 30
	2006		2005		2006		2005
Basic Earnings Per Share
Income from continuing operations	$	189	$	29	$	293	$	188
Average number of common shares outstanding		177		176		177		174

Income per share of common stock based on weighted average number of shares outstanding	$	1.07	$	.17	$	1.65	$	1.08


Diluted Earnings Per Share
Income from continuing operations	$	189	$	29	$	293	$	188

Average number of common shares outstanding		177		176		177		174
Incremental shares from stock-based awards		1		1		1		1

Average number of dilutive shares outstanding		178		177		178		175


Income per share of common stock assuming issuance of incremental shares	$	1.07	$	.17	$	1.65	$	1.07

Options to purchase approximately 4.8 million shares of common stock in 2006 and 102,000 shares of common stock in 2005, were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares, thus making these options anti-dilutive.

NOTE 8 – LONG -TERM DEBT

Debt Issuances

In 2006, we issued the following long-term debt:

(in Millions)

Month

Company

Issued

Type

Interest Rate

Maturity

Amount

Detroit Edison

May

Senior Notes (1)

6.625

June 2036

250

DTE Energy

May

Senior Notes (2)

6.35

June 2016

300

Total Issuances

550


(1)		The proceeds from the issuance were used to repay short-term borrowings of Detroit Edison and for general corporate purposes.

(2)		The proceeds from the issuance were used to repay a portion of DTE Energy’s 6.45% Senior Notes due 2006 and for general corporate purposes.

Debt Retirements and Redemptions

The following debt was retired, through optional redemption or payment at maturity, during 2006.

(in Millions)

Month

Company

Retired

Type

Interest Rate

Maturity

Amount

MichCon

May

First Mortgage Bonds

7.15

May 2006

DTE Energy

June

Senior Notes (1)

6.45

June 2006

500

Total Retirements

540


(1)		These Senior Notes were paid at maturity with the proceeds from the issuance of Senior Notes by DTE Energy and short-term borrowings.

NOTE 9 – SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

In conjunction with maintaining certain exchange traded risk management positions, we may be required to post cash collateral with our clearing agent. We have entered into a Margin Loan Facility (Facility) with an affiliate of the clearing agent of up to $103 million as of September 30, 2006. We entered into this Facility in lieu of posting cash. This Facility was backed by a letter of credit issued for the account of DTE Energy in the amount of $100 million. Any margin requirement in excess of the Facility is funded in cash by DTE Energy. The amount outstanding under the Facility is subject to an interest rate at a per annum rate of interest equal to the LIBOR rate, plus 0.75%, calculated daily. The amount outstanding under the Facility was $17 million as of September 30, 2006 and $103 million as of December 31, 2005. The amounts were shown as “Collateral held by others” and “Short-term borrowings” in the consolidated statement of financial position at December 31, 2005. Effective March 31, 2006, the Facility was amended to provide for the netting of all positions and payments under the Facility.

NOTE 10 – COMMITMENTS AND CONTINGENCIES

Environmental

Electric Utility

Air - Detroit Edison is subject to EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. In March 2005, EPA issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide

and mercury emissions. To comply with these requirements, Detroit Edison has spent approximately $644 million through 2005. We estimate Detroit Edison’s future capital expenditures at up to $218 million in 2006 and up to $2.2 billion of additional capital expenditures through 2018 to satisfy both the existing and proposed new control requirements.

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

Contaminated Sites - Detroit Edison conducted remedial investigations at contaminated sites, including two former manufactured gas plant (MGP) sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is approximately $13 million which was accrued in 2005 and is expected to be incurred over the next several years.

Gas Utility

Contaminated Sites - Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. Gas Utility owns, or previously owned, 15 such former MGP sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, we are also in the process of cleaning up other contaminated sites. Cleanup activities associated with these sites will be conducted over the next several years.

In 1993, a cost deferral and rate recovery mechanism was approved by the MPSC for investigation and remediation costs incurred at former MGP sites in excess of this reserve. Gas Utility employed outside consultants to evaluate remediation alternatives for these sites, to assist in estimating its potential liabilities and to review its archived insurance policies. As a result of these studies, Gas Utility accrued an additional liability and a corresponding regulatory asset of $35 million during 1995. During 2005, we spent approximately $4 million investigating and remediating these former MGP sites. In December 2005, we retained multiple environmental consultants to estimate the projected cost to remediate each MGP site. We accrued an additional $9 million in remediation liabilities associated with two of our MGP sites, to increase the reserve balance to $35 million at December 31, 2005.

Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows. However, we anticipate the cost deferral and rate recovery mechanism approved by the MPSC will prevent environmental costs from having a material adverse impact on our results of operations.

Other

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

Guarantees

In certain limited circumstances, we enter into contractual guarantees. We may guarantee another entity’s obligation in the event it fails to perform. We may provide guarantees in certain indemnification agreements. Finally, we may provide indirect guarantees for the indebtedness of others. Below are the

details of specific material guarantees we currently provide. Our other guarantees are not individually material and total approximately $43 million at September 30, 2006.

Parent Company Guarantee of Subsidiary Obligations

We have issued guarantees for the benefit of various non-utility subsidiary transactions. In the event that DTE Energy’s credit rating is downgraded below investment grade, certain of these guarantees would require us to post cash or letters of credit valued at approximately $503 million at September 30, 2006. This estimated amount fluctuates based upon commodity prices (primarily power and gas) and the provisions and maturities of the underlying agreements.

Personal Property Taxes

Detroit Edison, MichCon and other Michigan utilities have asserted that Michigan’s valuation tables result in the substantial overvaluation of utility personal property. Valuation tables established by the Michigan State Tax Commission (STC) are used to determine the taxable value of personal property based on the property’s age. In November 1999, the STC approved new valuation tables that more accurately recognize the value of a utility’s personal property. The new tables became effective in 2000 and are currently used to calculate property tax expense. However, several local taxing jurisdictions took legal action attempting to prevent the STC from implementing the new valuation tables and continued to prepare assessments based on the superseded tables. The legal actions regarding the appropriateness of the new tables were before the Michigan Tax Tribunal (MTT) which, in April 2002, issued a decision essentially affirming the validity of the STC’s new tables. In June 2002, petitioners in the case filed an appeal of the MTT’s decision with the Michigan Court of Appeals. In January 2004, the Michigan Court of Appeals upheld the validity of the new tables. With no further appeal by the petitioners available, the MTT began to schedule utility personal property valuation cases for Prehearing General Calls. After a period of abeyance, the MTT issued a scheduling order in a significant number of Detroit Edison and MichCon appeals that set litigation calendars for these cases extending into mid-2006. After an extended period of settlement discussions, a Memorandum of Understanding was reached with six principals in the litigation and the Michigan Department of Treasury that is expected to lead to settlement of all outstanding property tax disputes on a global basis.

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

Income Taxes

The Internal Revenue Service is currently conducting audits of our federal income tax returns for the years 2002 and 2003. We have accrued tax and interest related to tax uncertainties that arise due to actual or potential disagreements with governmental agencies about the tax treatment of specific items. At September 30, 2006, we have accrued approximately $31 million for such uncertainties. We believe that our accrued tax liabilities are adequate for all years.

Other Commitments

Detroit Edison has an Energy Purchase Agreement to purchase steam and electricity from the Greater Detroit Resource Recovery Authority (GDRRA). Under the agreement, Detroit Edison will purchase steam through 2008 and electricity through June 2024. In 1996, a special charge to income was recorded that included a reserve for steam purchase commitments in excess of replacement costs from 1997

through 2008. The reserve for steam purchase commitments is being amortized to fuel, purchased power and gas expense with non-cash accretion expense being recorded through 2008. We purchased $42 million of steam and electricity in 2005 and 2004 and $39 million in 2003. We estimate steam and electric purchase commitments through 2024 will not exceed $427 million. In January 2003, we sold the steam heating business of Detroit Edison to Thermal Ventures II, LP. Due to terms of the sale, Detroit Edison remains contractually obligated to buy steam from GDRRA until 2008 and recorded an additional liability of $20 million for future commitments. Also, we have guaranteed bank loans that Thermal Ventures II, LP may use for capital improvements to the steam heating system.

As of December 31, 2005, we were party to numerous long-term purchase commitments relating to a variety of goods and services required for our business. These agreements primarily consist of fuel supply commitments and energy trading contracts. We estimate that these commitments will be approximately $6.7 billion through 2051. We also estimate that 2006 base level capital expenditures will be $1.2 billion. We have made certain commitments in connection with expected capital expenditures.

Bankruptcies

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

Other

Detroit Edison and DTE Coal Services Inc. are involved in a contract dispute with BNSF Railway Company that has been referred to arbitration. Under this contract, BNSF transports western coals east for Detroit Edison and DTE Coal Services. 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. The arbitration hearing is scheduled for mid-2007. While we believe we will prevail on the merits in this matter, a negative decision with respect to the significant issues being heard in the arbitration could have an adverse effect on our ability to grow the Coal Transportation and Marketing business segment as currently contemplated.

Also, we are involved in certain legal, regulatory, administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning claims arising in the ordinary course of business. These proceedings include certain contract disputes, environmental reviews and investigations, audits, inquiries from various regulators, and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss. The resolution of pending proceedings is not expected to have a material effect on our operations or financial statements in the period they are resolved.

See Note 2 for a discussion of contingencies related to synfuel operations and Note 6 for a discussion of contingencies related to regulatory matters.

NOTE 11 – SEGMENT INFORMATION

We operate our businesses through three strategic business units, Electric Utility, Gas Utility and Non-utility operations (Power and Industrial Projects, Synthetic Fuel, Unconventional Gas Production and Fuel Transportation and Marketing). 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. The impending loss of synfuel tax credits in 2007 combined with the sustained volatility of oil prices increased management focus on synfuels, thereby requiring a separate business segment. The balance of our business consists of Corporate

& Other. Based on this structure, we set strategic goals, allocate resources and evaluate performance. Inter-segment billing for goods and services exchanged between segments is based upon tariffed or market-based prices of the provider and primarily consists of power sales, gas sales and coal transportation services in the Electric Utility, Unconventional Gas Production and Fuel Transportation and Marketing segments.

(in Millions)


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2006			2005			2006			2005
Operating Revenues
Electric Utility	$	1,460		$	1,409		$	3,685		$	3,434
Gas Utility		172			210			1,283			1,329
Non-utility Operations:
Power and Industrial Projects		105			112			312			320
Synthetic Fuel		142			237			605			688
Unconventional Gas Production		26			20			72			53
Fuel Transportation and Marketing		418			277			1,110			1,024

		691			646			2,099			2,085


Corporate & Other		1			3			5			9
Reconciliation & Eliminations		(128	)		(208	)		(346	)		(547	)

Total	$	2,196		$	2,060		$	6,726		$	6,310

(in Millions)


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2006			2005			2006			2005
Income (Loss)
Electric Utility	$	141		$	114		$	257		$	212
Gas Utility		(20	)		161			16			123
Non-utility Operations:
Power and Industrial Projects		(50	)		(1	)		(74	)		2
Synthetic Fuel		43			69			30			165
Unconventional Gas Production		2			2			5			3
Fuel Transportation and Marketing		75			(129	)		103			(139	)

Corporate & Other		(2	)		(187	)		(44	)		(178	)

Income (Loss) from Continuing Operations
Utility		121			275			273			335
Non-utility		70			(59	)		64			31
Corporate & Other		(2	)		(187	)		(44	)		(178	)

		189			29			293			188
Discontinued Operations (Note 4)		(1	)		(25	)		(3	)		(33	)
Cumulative Effect of Accounting Change (Note 3)		—			—			1			—

Net Income	$	188		$	4		$	291		$	155

Other Information

Legal Proceedings

We are involved in certain legal, regulatory, administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, environmental reviews and investigations, audits, inquiries from various regulators, and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss. The resolution of pending proceedings is not expected to have a material effect on our operations or financial statements in the period they are resolved.

Amendment of Benefit Plans

On October 30, 2006, the Organization and Compensation Committee of the Company’s Board of Directors amended the DTE Energy Company Executive Supplemental Retirement Plan (“ESRP”) to allow for discretionary contribution percentages or discretionary lump-sum contributions to participants’ accounts if approved by the Organization & Compensation Committee. The plan was further amended to provide that certain executives who are participants in the Management Supplemental Benefit Plan and have an ESRP account to be treated as grandfathered participants (entitled to a choice of benefits at termination, but not both.)

Risk Factors

In addition to the risk factor discussed below and other information set forth in this report, the risk factors discussed in Part 1, Item 1A. Company Risk Factors in DTE Energy Company’s Form 10-K, which could materially affect the Company’s businesses, financial condition and/or future operating results, should be carefully considered. The risks described herein and in the Company’s Form 10-K are not the only risks facing the Company. Additional risks and uncertainties not currently known to the Company, or that are currently deemed to be immaterial, also may materially adversely affect the Company’s business, financial condition and/or future operating results.

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

This incentive provided by production tax credits is not deemed necessary if the price of oil increases and provides significant market incentives for the production of these fuels. As such, the tax credit in a given year is reduced if the Reference Price of oil within that year exceeds a threshold price. The Reference Price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil. We project the yearly average wellhead price per barrel of oil for the year to be approximately $7 lower than the NYMEX price for light, sweet crude oil. The threshold price at which the credit begins to be reduced was set in 1980 and is adjusted annually for inflation. For 2006, we estimate the threshold price at which the tax credit would begin to be reduced is $55 per barrel and would be completely phased

out if the Reference Price reached $69 per barrel. As of October 31, 2006, the realized and unrealized NYMEX daily closing price of a barrel of oil was approximately $66 for 2006, equating to an estimated Reference Price of $59, which we estimate to be within the phase-out range. The average NYMEX daily closing price of a barrel of oil would have to average less than approximately $38 for the remainder of 2006 in order that no phase-out of production tax credits occurs. Unless oil prices drop significantly for the remainder of 2006, we expect at least a partial phase-out of the production tax credits in 2006 which could adversely impact on our results of operations, cash flow, and financial condition. To mitigate the effect of a potential phase out and minimize operating losses, on May 12, 2006 we idled production at all nine of the synfuel facilities. The decision to idle synfuel production was driven by the level and volatility of oil prices at that time. Beginning September 5, 2006 through October 4, 2006, we resumed production at each of the nine synfuel facilities due to declines in the level of oil prices. However, we cannot predict with any certainty the Reference Price for the remainder of 2006 or beyond.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table provides information about Company purchases of equity securities that are registered by the Company pursuant to Section 12 of the Exchange Act during the nine months ended September 30, 2006:


					Total Number of		Maximum Dollar
					Shares Purchased as		Value that May Yet
	Total Number of				Part of Publicly		Be Purchased Under
	Shares Purchased		Average Price Paid		Announced Plans or		the Plans or
Period	(1)		Per Share		Programs		Programs (2)
01/01/06 - 01/31/06		—		—		—	$	700,000,000
2/01/06 - 02/28/06		—		—		—	$	700,000,000
03/01/06 - 03/31/06		199,555	$	42.77		—	$	700,000,000
04/01/06 – 04/30/06		37,525	$	40.72		—	$	700,000,000
05/01/06 – 05/31/06		—		—		—	$	700,000,000
06/01/06 – 06/30/06		6,725	$	41.20		—	$	700,000,000
07/01/06 – 07/31/06		1,000	$	40.90		—	$	700,000,000
08/01/06 – 08/31/06		—		—		—	$	700,000,000
09/01/06 – 09/30/06		1,500	$	40.78		—	$	700,000,000

Total		246,305				—


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

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

Exhibits


Exhibit
Number		Description

Filed:

10-65		Third Amendment to the DTE Energy Company Executive Supplemental Retirement Plan
31-27		Chief Executive Officer Section 302 Form 10-Q Certification
31-28		Chief Financial Officer Section 302 Form 10-Q Certification

Furnished:

32-27		Chief Executive Officer Section 906 Form 10-Q Certification
32-28		Chief Financial Officer Section 906 Form 10-Q Certification


	Page
Definitions		1

Forward-Looking Statements		3

Part I – Financial Information

Item 1. Financial Statements

Consolidated Statement of Operations		32

Consolidated Statement of Financial Position		33

Consolidated Statement of Cash Flows		35

Consolidated Statement of Changes in Shareholders’ Equity and Comprehensive Income		36

Notes to Consolidated Financial Statements		37

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk		29

Item 4. Controls and Procedures		31

Part II – Other Information

Item 1. Legal Proceedings		61

Item 1A. Risk Factors		61

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		63

Item 6. Exhibits		63

Signature		64
Third Amendment to the Executive Supplemental Retirement Plan
Chief Executive Officer Section 302
Chief Financial Officer Section 302
Chief Executive Officer Section 906
Chief Financial Officer Section 906


	Assuming a			Assuming
	10%			a 10%
(in Millions)	increase in			decrease
Activity	rates			in rates			Change in the fair value of

Gas Contracts	$	(11	)	$	11		Commodity contracts
Power Contracts	$	(11	)	$	11		Commodity contracts
Oil Contracts	$	26		$	(34	)	Commodity options
Interest Rate Risk	$	(313	)	$	337		Long-term debt
Foreign Currency Risk	$	2		$	(2	)	Forward contracts


		DTE ENERGY COMPANY

Date: November 14, 2006		/s/ PETER B. OLEKSIAK

		Peter B. Oleksiak
		Controller


Exhibit No.		Description of Exhibits

10-65		Third Amendment to the DTE Energy Company Executive Supplemental Retirement Plan
31-27		Chief Executive Officer Section 302 Form 10-Q Certification
31-28		Chief Financial Officer Section 302 Form 10-Q Certification

32-27		Chief Executive Officer Section 906 Form 10-Q Certification
32-28		Chief Financial Officer Section 906 Form 10-Q Certification