Edgar Filing: DTE ENERGY CO

10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period ended March 31, 2009

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.)

One Energy Plaza, 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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ

Accelerated filer o

Non-accelerated filer o
(Do not check if a smaller reporting company)

Smaller reporting company o

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

Yes o No þ

At March 31, 2009, 163,876,686 shares of DTE Energy’s common stock were outstanding, substantially all of which were held by non-affiliates.

DTE Energy Company
Quarterly Report on Form 10-Q
Quarter Ended March 31, 2009

TABLE OF CONTENTS


			Page

Definitions				1

Forward-Looking Statements				3

Part I — Financial Information

	Item 1.	Financial Statements

		Consolidated Statements of Operations (Unaudited)		29
		Consolidated Statements of Financial Position (Unaudited)		30
		Consolidated Statements of Cash Flows (Unaudited)		32
		Consolidated Statements of Changes in Shareholders’ Equity and Comprehensive Income (Unaudited)		33
		Notes to Consolidated Financial Statements (Unaudited)		34

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		5

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		25

	Item 4.	Controls and Procedures		28

Part II — Other Information

	Item 1.	Legal Proceedings		57

	Item 1A.	Risk Factors		57

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		57

	Item 6.	Exhibits		58

Signature				59
EX-12.42
EX-31.49
EX-31.50
EX-32.49
EX-32.50

Definitions


Company		DTE Energy Company and any subsidiary companies

CTA		Costs to achieve, consisting of project management, consultant support and employee severance, related to the Performance Excellence Process

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

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

FASB		Financial Accounting Standards Board

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 subsidiary companies

MISO		Midwest Independent System Operator, a Regional Transmission Organization

MPSC		Michigan Public Service Commission

Non-utility		An entity that is not a public utility. Its conditions of service, prices of goods and services and other operating related matters are not directly regulated by the MPSC or the FERC.

NRC		Nuclear Regulatory Commission

Production tax credits		Tax credits as authorized under Sections 45K and 45 of the Internal Revenue Code that are designed to stimulate investment in and development of alternate fuel sources. The amount of a production tax credit can vary each year as determined by the Internal Revenue Service.

Proved reserves		Estimated quantities of natural gas, natural gas liquids and crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reserves under existing economic and operating conditions.

PSCR		A power supply cost recovery mechanism authorized by the MPSC that allows Detroit Edison to recover through rates its fuel, fuel-related and purchased power expenses.

Securitization		Detroit Edison financed specific stranded costs at lower interest rates through the sale of rate reduction bonds by a wholly-owned special purpose entity, the Detroit Edison Securitization Funding LLC.

SFAS		Statement of Financial Accounting Standards

Subsidiaries		The direct and indirect subsidiaries of DTE Energy Company

Synfuels		The fuel produced through a process involving chemically modifying and binding particles of coal. Synfuels are used for power generation and coke production. Synfuel production through December 31, 2007 generated 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
GWh		Gigawatthour of electricity
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:

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

	•		instability in capital markets which could impact availability of short and long-term financing;

	•		potential for continued loss on investments, including nuclear decommissioning and benefit plan assets;

	•		the length and severity of ongoing economic decline;

	•		the timing and extent of changes in interest rates;

	•		the level of borrowings;

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

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

	•		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 increasing costs of remediation and compliance, including actual and potential new federal and state requirements that could include carbon and more stringent mercury emission controls, a renewable portfolio standard, energy efficiency mandates, and a carbon tax or cap and trade structure;

	•		nuclear regulations and operations associated with nuclear facilities;

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

	•		employee relations and the impact of collective bargaining agreements;

	•		unplanned outages;

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

	•		the effects of competition;

	•		the uncertainties of successful exploration of gas shale resources and challenges in estimating gas reserves with certainty;

	•		impact of regulation by the FERC, MPSC, NRC and other applicable governmental proceedings and regulations, including any associated impact on rate structures;

	•		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 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;

	•		high levels of uncollectible accounts receivable; and

	•		binding arbitration, litigation and related appeals.

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 refer 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.

Part I — Item 2.

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

OVERVIEW

DTE Energy is a diversified energy company with 2008 revenues in excess of $9 billion and over $24 billion of 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.

Net income attributable to DTE Energy in the first quarter of 2009 was $178 million, or $1.09 per diluted share, compared to net income of $212 million, or $1.29 per diluted share, in the first quarter of 2008. The decrease in net income is primarily due to the $80 million after-tax gain on the 2008 sale of a portion of Barnett shale properties, partially offset by higher earnings in the electric and gas utilities and in the gas midstream and energy trading segments in our non-utility operations.

Please see detailed explanations of segment performance in the following Results of Operations section.

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

•		Impacts of national and regional economic conditions on utility operations, including automotive industry uncertainty;

•		Effects of weather on utility operations;

•		Collectibility of accounts receivable on utility operations;

•		Impact of regulatory decisions on utility operations;

•		Fluctuations in market demand on coal supply;

•		Challenges associated with nuclear fuel;

•		Results in our Energy Trading business; and

•		Required renewable, energy-efficiency, environmental and reliability-related capital investments and other costs.

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

UTILITY OPERATIONS

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

Our Gas Utility segment consists of MichCon and Citizens Gas Fuel Company (Citizens). MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan. MichCon also has subsidiaries involved in the gathering, processing and transmission of natural gas in northern Michigan. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.

Impact of National and Regional Economic Conditions on our Utility Operations — Revenues from our utility operations follow the economic cycles of the customers we serve. Our utilities provide services to the domestic automotive industry which is under considerable financial distress, exacerbating the decline in regional conditions.

In the first quarter of 2009, Detroit Edison experienced an approximate 9 percent decline in sales in its service territory as compared to 2008. For 2009, as compared to 2008, we are expecting a 6 percent decline in sales in the Detroit Edison service territory. As discussed further below, deteriorating economic conditions impact our ability to collect amounts due from our customers of our electric and gas utilities and drive higher levels of lost and stolen natural gas at MichCon. In the face of the economic conditions, we are actively managing our cash, capital expenditures, cost structure and liquidity to maintain our financial strength. See Note 9 of the Notes to Consolidated Financial Statements.

Effects of Weather on Utility Operations — 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.

Collectibility of Accounts Receivable on Utility Operations — Both utilities continue to experience high levels of past due receivables, which is primarily attributable to economic conditions, including high levels of unemployment and home foreclosures. High energy prices and a lack of adequate levels of assistance for low-income customers have also impacted our accounts receivable. We have taken actions to manage the level of past due receivables, including increasing customer disconnections, contracting with collection agencies and working with Michigan officials and others to increase the share of low-income funding allocated to our customers. The April 2005 MPSC gas rate order provided for an uncollectible true-up mechanism for MichCon. The uncollectible true-up mechanism enables MichCon to recover ninety percent of the difference between the actual uncollectible expense for each year and $37 million after an annual reconciliation proceeding before the MPSC. Our uncollectible accounts expense for the two utilities was approximately $42 million for both the three months ended March 31, 2009 and the corresponding period of 2008 (net of amounts deferred for future recovery under MichCon’s uncollectible true-up mechanism.)

Impact of Regulatory Decisions on Utility Operations — On December 23, 2008, the MPSC issued an order in Detroit Edison’s February 20, 2008 updated rate case filing. The MPSC approved an annual revenue increase of $84 million effective January 14, 2009 or a 2.0 percent average increase in Detroit Edison’s annual revenue requirement for 2009. Included in the approved $84 million increase in revenues was a return on equity of 11 percent on an expected 49 percent equity and 51 percent debt capital structure.

Detroit Edison filed a general rate case on January 26, 2009 based on a twelve months ended June 2008 historical test year. The filing with the MPSC requested a $378 million, or 8.1 percent average increase in Detroit Edison’s annual revenue requirement for the twelve months ended June 30, 2010 projected test year. The requested increase in revenues is required to recover the increased costs associated with environmental compliance, operation and maintenance of the Company’s electric distribution system and generation plants, customer uncollectible accounts, inflation, the capital costs of plant additions and the reduction in territory sales.

See Note 5 of the Notes to Consolidated Financial Statements.

Fluctuations in Market Demand on Coal Supply — Our generating fleet produces approximately 79 percent of its electricity from coal. Coal demand from domestic and international markets over the last several years has resulted in volatility and higher prices which are passed to our customers through the PSCR mechanism. The demand and price volatility have been dampened by the recent economic downturn and any future increase is dependent on the timing and extent of economic recovery. In addition, obtaining environmental permits and finding economically recoverable amounts of new coal have resulted in decreasing coal output from the central Appalachian region, while environmental regulation has increased demand for cleaner burning western coal.

Challenges Associated with Nuclear Fuel — We operate one nuclear facility (Fermi 2) that undergoes a periodic refueling outage approximately every eighteen months. Uranium prices have been rising due to supply concerns. In the future, there may be additional nuclear facilities constructed in the industry that may place additional pressure on uranium supplies and prices. We have a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. We are obligated to pay the DOE a fee of $0.001 per kWh of Fermi 2 electricity generated and sold; this fee is a component of nuclear fuel expense. Delays have occurred in the DOE’s program for the acceptance and disposal of spent nuclear fuel at a permanent repository. We are a party in litigation against the DOE for both past and future costs associated with the DOE’s failure to accept spent nuclear fuel under the timetable set forth in the Federal Nuclear Waste Policy Act of 1982. Until the DOE is able to fulfill its obligation

under the contract, we are responsible for the spent nuclear fuel storage and have begun work on an on-site dry cask storage facility.

NON-UTILITY OPERATIONS

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

Gas Midstream

Gas Midstream owns partnership interests in two interstate transmission pipelines and two natural gas storage fields. The pipeline and storage assets are primarily supported by long-term, fixed-price revenue contracts. We have a partnership interest in Vector Pipeline (Vector), an interstate transmission pipeline, which connects Michigan to Chicago and Ontario. We also hold partnership interests in Millennium Pipeline Company (Millennium), which was placed in service in December 2008. Millennium indirectly connects southern New York State to Upper Midwest/Canadian supply, while providing transportation service into the New York City markets. We have storage assets in Michigan capable of storing up to 87 Bcf in natural gas storage fields located in Southeast Michigan. The Washington 10 and 28 storage facilities are high deliverability storage fields having bi-directional interconnections with Vector and MichCon providing our customers access to the Chicago, Michigan, other Midwest and Ontario market centers. The pipeline and storage business is expanding capacity to serve markets throughout the Midwest and Northeast United States regions.

Unconventional Gas Production

Our Unconventional Gas Production business is engaged in natural gas exploration, development and production within the Barnett shale in north Texas. We continue to develop our position here, with total leasehold acreage of 62,395 (60,553 acres, net of interest of others). We continue to acquire select positions in active development areas in the Barnett shale to optimize our existing portfolio.

In January 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $250 million. The properties sold included 75 Bcfe of proved reserves on approximately 11,000 net acres in the core area of the Barnett shale.

We plan to continue to develop our holdings in the western portion of the Barnett shale and to seek opportunities for additional monetization of select properties within our Barnett shale holdings, when conditions are appropriate. We expect to invest approximately $25 million in 2009. During 2009, we expect to drill 10 to 15 new wells and achieve Barnett shale production of approximately 5 to 6 Bcfe of natural gas, compared with approximately 5 Bcfe in 2008.

As a component of our risk management strategy for our Barnett shale reserves, we hedged a portion of anticipated production from our reserves to secure an attractive investment return. As of March 31, 2009, we have a series of cash flow hedges for approximately 2.7 Bcf of anticipated Barnett gas production through 2010 at an average price of $7.31 per Mcf.

Power and Industrial Projects

Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers; provide coal transportation and marketing; and sell electricity from biomass-fired energy projects. This business segment provides utility-type services using project assets usually located on or near the customers’ premises in the steel, automotive, pulp and paper, airport and other industries.

Services provided include pulverized coal and petroleum coke supply and metallurgical coke supply, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. We own and operate one gas-fired peaking electric generating plant, two biomass-fired electric generating plants and operate

one coal-fired power plant. A third biomass-fired electric generating plant is currently under development with an expected in-service date of January 2010. This business segment also develops, owns and operates landfill gas recovery systems throughout the United States and produces metallurgical coke from three coke batteries. The production of coke from two of the coke batteries generates production tax credits. The business provides coal transportation-related services including fuel, transportation, storage, blending and rail equipment management services. We specialize in minimizing fuel costs and maximizing reliability of supply for energy-intensive customers. Additionally, we participate in coal marketing and the purchase and sale of emissions credits. This business segment performs 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.

Energy Trading

Energy Trading focuses on physical power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio and the optimization of contracted natural gas pipeline transportation and storage, and power transmission and generating capacity positions. Energy Trading also provides natural gas, power and ancillary services to various utilities which may include the management of associated storage and transport contracts on the customers’ behalf. Our customer base is predominantly utilities, local distribution companies, pipelines, 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 the recognition of unrealized gains and losses from changes in the fair value of the derivatives. We utilize forwards, futures, swaps and option contracts to mitigate risk associated with our marketing and trading activity as well as for proprietary trading within defined risk guidelines. Energy Trading also provides commodity risk management services to the other businesses within DTE Energy.

Significant portions of the electric and gas marketing and trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as contracted natural gas pipeline transportation and storage and power generation capacity positions. Most financial instruments are deemed derivatives, whereas proprietary gas inventory, power transmission, 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 could reverse in subsequent periods.

CAPITAL INVESTMENT

We anticipate significant capital investment across all of our business segments during the next five years. Most of our capital expenditures will be concentrated within our utility segments. Our electric utility segment currently expects to invest approximately $6 billion (excluding investments in new base-load generation capacity, if any), including renewable and energy-efficiency related expenditures, increased environmental requirements and reliability enhancement projects during the period of 2009 through 2013. Our gas utility segment currently expects to invest approximately $750 million on system expansion, pipeline safety and reliability enhancement projects through the same period. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment. Due to the economy and credit market conditions, we are continually reviewing our capital expenditure commitments for potential reductions and deferrals and plan to adjust spending as appropriate.

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.

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;

	•		managing cash, capital and liquidity to maintain or improve our financial strength;

	•		improving Electric and Gas Utility customer satisfaction; and

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

We will continue to pursue opportunities to grow our businesses in a disciplined manner if we can secure opportunities that meet our strategic, financial and risk criteria.

RESULTS OF OPERATIONS

The following sections provide a detailed discussion of the operating performance and future outlook of our segments.

Net income attributable to DTE Energy by segment for the three months ended March 31, 2009 and 2008 is as follows:


	Three Months Ended
	March 31
(in Millions)	2009			2008
Net Income:
Electric Utility	$	78		$	41
Gas Utility		61			59
Non-utility Operations:
Gas Midstream		14			8
Unconventional Gas Production		(2	)		82
Power and Industrial Projects		4			10
Energy Trading		40			31

Corporate & Other		(17	)		(31	)

Income (Loss) from Continuing Operations:
Utility		139			100
Non-utility		56			131
Corporate & Other		(17	)		(31	)

		178			200
Discontinued Operations		—			12

Net Income attributable to DTE Energy	$	178		$	212

ELECTRIC UTILITY

Our Electric Utility segment consists of Detroit Edison.

Factors impacting income: Net income increased $37 million in the first quarter of 2009 compared to the same period in 2008 due primarily to lower operation and maintenance expenses and higher gross margin.


	Three Months Ended
	March 31
(in Millions)	2009			2008
Operating Revenues	$	1,118		$	1,153
Fuel and Purchased Power		340			402

Gross Margin		778			751
Operation and Maintenance		316			358
Depreciation and Amortization		188			192
Taxes Other Than Income		60			62

Operating Income		214			139
Other (Income) and Deductions		84			74
Income Tax Provision		52			24

Net Income	$	78		$	41


Operating Income as a Percentage of Operating Revenues		19	%		12	%

Gross margin increased $27 million in the first quarter of 2009 as compared to the same period in 2008. The following table details changes in various gross margin components relative to the comparable prior period:


(in Millions)	Three Months
Weather-related impacts	$	3
Economy		(37	)
April 2008 expiration of show-cause rate decrease		17
December 2008 rate order		18
Securitization bond and tax surcharge rate increase		8
Other, net		18

Increase in gross margin	$	27


(in Thousands of MWh)	2009			2008
Electric Sales
Residential		3,738			3,932
Commercial		4,423			4,362
Industrial		2,637			3,516
Wholesale		704			723
Other		113			109

		11,615			12,642
Interconnection sales (1)		1,035			826

Total Electric Sales		12,650			13,468


Electric Deliveries
Retail and Wholesale		11,615			12,642
Electric Customer Choice		398			398
Electric Customer Choice — Self Generators (2)		(81	)		58

Total Electric Sales and Deliveries		11,932			13,098


(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.


	Three Months Ended
Power Generated and Purchased	March 31
(in Thousands of MWh)	2009			2008
Power Plant Generation
Fossil		9,842			10,240
Nuclear		2,254			2,343

		12,096			12,583
Purchased Power		1,352			1,730

System Output		13,448			14,313
Less Line Loss and Internal Use		(798	)		(845	)

Net System Output		12,650			13,468


Average Unit Cost ($/MWh)
Generation (1)	$	17.30		$	16.60

Purchased Power	$	33.94		$	61.60

Overall Average Unit Cost	$	18.97		$	22.04


(1)		Represents fuel costs associated with power plants.

Operation and maintenance expense decreased $42 million in the first quarter of 2009 compared to the same period in 2008 primarily due to $24 million from continuous improvement initiatives resulting in lower contract labor and outside services expenses and $18 million representing lower corporate support allocations from continuous improvement initiatives and from lower information technology and other staff expenses.

Outlook — We will move forward in our efforts to continue to improve the operating performance and cash flow of Detroit Edison. We continue to resolve outstanding regulatory issues. Many of these issues have been addressed by the legislation signed by the Governor of Michigan in October 2008. Looking forward, additional issues, such as volatility in prices for coal and other commodities, investment returns and changes in discount rate assumptions in benefit plans, health care costs 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 continue to seek opportunities to improve productivity, remove waste and decrease our costs while improving customer satisfaction.

Unfavorable national and regional economic trends have resulted in reduced demand for electricity in our service territory and increases in our uncollectible accounts receivable. The magnitude of these trends will be driven by the impacts of the challenges in the domestic automotive industry and the timing and level of recovery in the national and regional economies. Further automotive and other industrial plant closures, bankruptcies or a federal government mandated restructuring program could have a significant impact on the results of Detroit Edison. We continue to monitor developments in this sector. Due to the economy and credit market conditions, in the near term, we are reviewing our capital expenditure commitments for potential reductions and deferrals and plan to adjust the timing of projects as appropriate.

The following variables, either individually or in combination, could impact our future results:

	•		Instability in capital markets which could impact availability of short and long-term financing or the potential for loss on investments;

	•		Economic conditions within Michigan and corresponding impacts on demand for electricity;

	•		Collectibility of accounts receivable;

	•		Increases in future expense and contributions to pension and other postretirement plans due to declines in asset values resulting from market conditions;

	•		The 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 and distribution system performance;

	•		Weather;

	•		The level of customer participation in the electric Customer Choice program; and

	•		Any current and potential new federal and state environmental, renewable energy and energy efficiency requirements.

GAS UTILITY

Our Gas Utility segment consists of MichCon and Citizens.

Factors impacting income: Net income increased $2 million in the first quarter of 2009 compared to the same period in 2008. Lower operation and maintenance expenses were partially offset by lower gross margin.


	Three Months Ended
	March 31
(in Millions)	2009			2008
Operating Revenues	$	771		$	915
Cost of Gas		513			654

Gross Margin		258			261
Operation and Maintenance		119			123
Depreciation and Amortization		26			24
Taxes Other Than Income		14			14

Operating Income		99			100
Other (Income) and Deductions		13			15
Income Tax Provision		25			26

Net Income	$	61		$	59


Operating Income as a Percentage of Operating Revenues		13	%		11	%

Gross margin decreased $3 million in the first quarter of 2009 as compared to the same period in 2008. This decrease reflects a $12 million unfavorable result from lost gas, $5 million of customer conservation efforts, partially offset by $4 million of higher valued gas received as compensation for transportation of third party gas, $4 million from the uncollectible tracking mechanism and $4 million from higher transportation and storage revenues.


	Three Months Ended
	March 31
	2009		2008
Gas Markets (in Millions)
Gas sales	$	673	$	819
End user transportation		52		51

		725		870
Intermediate transportation		17		19
Storage and other		29		26

	$	771	$	915


Gas Markets (in Bcf)
Gas sales		68		71
End user transportation		42		44

		110		115
Intermediate transportation		144		116

		254		231

Operation and maintenance expense decreased $4 million in the first quarter of 2009 compared to the same period in 2008 primarily due to lower corporate support allocations from continuous improvement initiatives and from lower information technology and other staff expenses.

Outlook — Volatile gas prices and deteriorating economic conditions have resulted in continued pressure on receivables and working capital requirements that are partially mitigated by the MPSC’s GCR and uncollectible true-up mechanisms. We will continue to seek opportunities to improve productivity, minimize lost and stolen gas, remove waste and decrease our costs while improving customer satisfaction.

Unfavorable national and regional economic trends have resulted in a decrease in the number of customers in our service territory and increases in our uncollectible accounts receivable. The magnitude of these trends will be driven

by the impacts of the challenges in the domestic automotive industry and the timing and level of recovery in the national and regional economies.

The following variables, either individually or in combination, could impact our future results:

	•		Instability in capital markets which could impact availability of short and long-term financing or the potential for loss investments;

	•		Economic conditions within Michigan and corresponding impacts on demand for gas and levels of lost or stolen gas;

	•		Collectibility of accounts receivable;

	•		Increases in future expense and contributions to pension and other postretirement plans due to declines in asset values resulting from market conditions;

	•		The 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 distribution system performance;

	•		Weather;

	•		Customer conservation;

	•		Volatility in the short-term natural gas storage markets which impact third-party storage revenues;

	•		Extent and timing of any base gas sales; and

	•		Any current and potential new federal and state environmental, renewable energy and energy efficiency requirements.

NON-UTILITY OPERATIONS

Gas Midstream

Our Gas Midstream segment consists of our non-utility gas pipelines and storage businesses.

Factors impacting income: Net income increased $6 million in the first quarter of 2009 compared to the same period in 2008 primarily due to higher revenue from the storage operations and higher earnings from both Vector and Millennium Pipelines.


	Three Months Ended
	March 31
(in Millions)	2009			2008
Operating Revenues	$	22		$	17
Operation and Maintenance		3			4
Depreciation and Amortization		1			2
Taxes Other Than Income		1			1

Operating Income		17			10
Other (Income) and Deductions		(7	)		(4	)
Income Tax Provision		10			6

Net Income	$	14		$	8

Outlook — Our Gas Midstream business expects to continue its steady growth plan. In April 2008, an additional 7 Bcf of storage capacity was placed in service, which was followed by an additional 2 Bcf in April 2009. Vector Pipeline placed into service its Phase 1 expansion for approximately 200 MMcf/day in November 2007. The Vector

Pipeline Phase 2 expansion is currently under construction and will add approximately 100 MMcf/day, with an expected in-service date of November 2009. Both the 2007 and 2009 expansion projects are supported by customers under long-term contracts. Millennium Pipeline was placed in service in December 2008 and currently has nearly 85 percent of its capacity sold to customers under long-term contracts. We are also a 50 percent owner in the proposed Dawn Gateway Pipeline which will provide transport between our Michigan storage facilities and the Dawn Hub in Ontario, Canada.

Unconventional Gas Production

Our Unconventional Gas Production business is engaged in natural gas exploration, development and production primarily within the Barnett shale in northern Texas

In January 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $250 million. The properties sold included 75 Bcf of proved reserves on approximately 11,000 net acres in the core area of the Barnett shale. We recognized a gain of $126 million ($80 million after-tax) on the sale.

Factors impacting income: Net income decreased $84 million in the first quarter of 2009 due to the 2008 gain on the sale of a portion of our Barnett shale properties and lower commodity prices.


	Three Months Ended
	March 31
(in Millions)	2009			2008
Operating Revenues	$	7		$	10
Operation and Maintenance		4			6
Depreciation, Depletion and Amortization		5			2
Taxes Other Than Income		—			—
Other Asset (Gains)		—			(126	)

Operating Income		(2	)		128
Other (Income) and Deductions		1			—
Income Tax Provision		(1	)		46

Net Income (Loss)	$	(2	)	$	82

Operating revenues were lower in the first quarter of 2009 compared to the same period in 2008 as a result of lower commodity prices, despite a 25 percent increase in production.

Operation and maintenance expense were lower due to the ample supply of service companies available and our ability to secure lower prices for oilfield services. For the first quarter of 2009, Barnett shale production was approximately 1.4 Bcfe of natural gas compared with approximately 1.1 Bcfe during the same period in 2008.

Outlook —In the longer-term, we plan to continue to develop our holdings in the western portion of the Barnett shale and to seek opportunities for additional monetization of select properties within our Barnett shale holdings, when conditions are appropriate. Our strategy for 2009 is centered on reducing operating expenses and optimizing production volume. During 2009, we expect to invest approximately $25 million to drill 10 to 15 new wells and achieve Barnett shale production of approximately 5 to 6 Bcfe of natural gas, compared with approximately 5 Bcfe in 2008.

Power and Industrial Projects

Factors impacting income: Net income decreased $6 million in the first quarter of 2009 as compared to the same period in 2008.


	Three Months Ended
	March 31
(in Millions)	2009			2008
Operating Revenues	$	155		$	216
Operation and Maintenance		141			203
Depreciation and Amortization		10			3
Taxes Other Than Income		4			4
Asset (Gains) Losses and Reserves, Net		(3	)		(3	)

Operating Income		3			9
Other (Income) and Deductions		2			(3	)

Income Taxes
Provision (Benefit)		(1	)		4
Production Tax Credits		(3	)		(2	)

		(4	)		2

Net Income Before Noncontrolling Interests		5			10
Attributable to Noncontrolling Interests		1			—

Net Income	$	4		$	10

Operating revenues decreased $61 million in the first quarter of 2009 compared to the same period in 2008. The decrease is attributed primarily to $60 million in our coal transportation services business representing a decrease in coal structured transactions and $24 million of lower coke demand, partially offset by a $19 million increase in coal transportation services.

Operation and maintenance expense decreased $62 million in the first quarter of 2009 compared to the same period in 2008. This decrease is due primarily to $56 million in our coal transportation services business representing a decrease in coal structured transactions and $16 million of lower coke demand, partially offset by $9 million of higher coal transportation services.

Depreciation and amortization expense increased $7 million in the first quarter of 2009 compared to the same period in 2008 due to the classification of our monetization project companies as held for sale in the first quarter of 2008, which resulted in depreciation and amortization not being recognized for those assets during that period.

Outlook — The deterioration in the U.S. economy is expected to continue to negatively impact our customers in the steel industry and we expect a corresponding reduction in demand for metallurgical coke and pulverized coal supplied to these customers in 2009. We supply onsite energy services to the domestic automotive manufacturers who have also been negatively affected by the economic downturn and constriction in the capital and credit markets. Our onsite energy services are delivered in accordance with the terms of long-term contracts and have not been significantly impacted by the financial distress experienced by the automotive manufacturers. Further plant closures, bankruptcies or a federal government mandated restructuring program could have a significant impact on the results of our on-site energy projects. We continue to monitor developments in this sector.

In 2009, we expect our coal transportation services business to positively contribute to the results of this segment as our coal transportation, storage and blending services continue to grow. In 2011, our existing long-term rail transportation contract which gives us a competitive advantage will expire. We will continue to work with suppliers and the railroads to promote secure and competitive access to coal to meet the energy requirements of our customers.

Power and Industrial Projects will continue to leverage its extensive energy-related operating experience and project management capability to develop additional energy projects to serve energy intensive industrial customers that are experiencing capital constraints due to the economic downturn. We will also continue to look for opportunities to acquire energy projects and biomass fired generating projects for advantageous prices.

Energy Trading

Our Energy Trading segment focuses on physical power and gas marketing, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, optimization of contracted natural gas pipelines and storage, and power transmission and generating capacity positions. Energy Trading also provides natural gas, power and ancillary services to various utilities which may include the management of associated storage and transport contracts on the customers’ behalf.

Factors impacting income: Net income increased $9 million in the first quarter of 2009 compared to the same period in 2008. This change was largely due to an increase in mark-to-market gains in our gas strategies.


	Three Months Ended
	March 31
(in Millions)	2009		2008
Operating Revenues	$	204	$	288
Fuel, Purchased Power and Gas		116		219

Gross Margin		88		69
Operation and Maintenance		18		16
Depreciation, Depletion and Amortization		1		1
Taxes Other Than Income		2		1

Operating Income		67		51
Other (Income) and Deductions		2		1
Income Tax Provision		25		19

Net Income	$	40	$	31

Gross margin increased $19 million in the first quarter of 2009 compared to the first quarter of 2008. This increase is primarily attributed to an increase in unrealized margins of $32 million, partially offset by a decrease in realized margins of $13 million.

The $32 million increase in unrealized margins was primarily due to $8 million favorability in our gas trading strategies, $6 million of improvement in our power strategies and favorability of $10 million and $7 million in our gas storage and gas transportation strategies, respectively, due to the absence of first quarter 2008 timing related losses.

The $13 million decrease in realized margins was primarily due to the economically favorable decision to delay previously planned first quarter 2009 withdrawals from gas storage due to the decrease in current prices of natural gas compared to forward prices.

Outlook — Significant portions of the Energy Trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as contracted natural gas pipeline transportation and storage, and power generation capacity positions. Energy Trading also provides power and ancillary services and natural gas to various utilities which may include the management of associated storage and transport contracts on the customers’ behalf. Most financial instruments are deemed derivatives, whereas proprietary gas inventory, power transmission, pipeline transportation and certain 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. Our strategy is to economically manage the price risk of storage with futures, forwards and swaps. This results in gains and losses that are recognized in different interim and annual accounting periods.

See also the “Fair Value” section that follows.

Corporate & Other

Corporate & Other includes various holding company activities and holds certain non-utility debt and energy-related investments.

Factors impacting income: The net loss decreased $14 million in the first quarter of 2009 compared with the same period in 2008 primarily due to a $9 million reduction of costs related to natural gas forward contracts related to the sale of the Antrim shale properties in the second quarter of 2007 and a $2 million reduction in the inter-company interest allocation.

DISCONTINUED OPERATIONS

Synthetic Fuel

Due to the expiration of synfuel production tax credits in 2007, the Synthetic Fuel business ceased operations and was classified as a discontinued operation as of December 31, 2007. The favorable impact of reserve adjustments for the final phase-out percentage of approximately $16 million and other true-ups resulted in net income of $12 million for the first quarter of 2008.

CAPITAL RESOURCES AND LIQUIDITY

Cash Requirements

We use cash to maintain and expand our electric and gas utilities and to grow our non-utility businesses, retire and pay interest on long-term debt and pay dividends. We believe that we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements.

Our strategic direction anticipates base level capital investments and expenditures for existing businesses in 2009 of up to $1.1 billion. The capital needs of our utilities will increase due primarily to environmental related expenditures. We expect over $2.9 billion of future capital expenditures through 2018 to satisfy both existing and proposed new requirements. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment.

We expect non-utility capital spending will approximate $200 million to $300 million annually for the next several years. Capital spending for growth of existing or new businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria.

Due to the economy and credit market conditions, we are continually reviewing our capital expenditure commitments for potential reductions and deferrals and plan to adjust spending as appropriate.


	Three Months Ended
	March 31
(in Millions)	2009			2008
Cash and Cash Equivalents
Cash Flow From (Used For)
Operating activities:
Net income attributable to DTE Energy	$	178		$	212
Depreciation, depletion and amortization		232			225
Deferred income taxes		66			190
Gain on sale of non-utility assets		—			(126	)
Gain on sale of synfuel and other assets, net		(3	)		(20	)
Working capital and other		366			411

		839			892

Investing activities:
Plant and equipment expenditures — utility		(303	)		(277	)
Plant and equipment expenditures — non-utility		(23	)		(52	)
Proceeds from sale of non-utility assets		—			250
Proceeds from sale of synfuels and other assets		30			61
Restricted cash and other investments		40			37

		(256	)		19

Financing activities:
Redemption of long-term debt		(86	)		(79	)
Repurchase of long-term debt		—			(238	)
Short-term borrowings, net		(414	)		(534	)
Issuance of common stock		9			—
Repurchase of common stock		—			(13	)
Dividends on common stock and other		(90	)		(90	)

		(581	)		(954	)

Net Increase (Decrease) in Cash and Cash Equivalents	$	2		$	(43	)

Cash from Operating Activities

A majority of our 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.

Cash from operations in the first quarter of 2009 decreased $53 million from the comparable 2008 period primarily due to changes in working capital items.

Cash from Investing Activities

Cash inflows associated with investing activities are primarily generated from the sale of assets, while cash outflows are primarily generated from plant and equipment expenditures. In any given year, we will look to realize cash from under-performing or non-strategic assets or matured fully valued assets. Capital spending within the utility business is primarily to maintain our generation and distribution infrastructure, comply with environmental regulations and gas pipeline replacements. Capital spending within our non-utility businesses is primarily to maintain our existing facilities and for expansion. The balance of non-utility spending is for growth, which we manage very carefully. We look to make investments that meet strict criteria in terms of strategy, management skills, risks and returns. All new investments are analyzed for their rates of return and cash payback on a risk adjusted basis. We have been disciplined in how we deploy capital and will not make investments unless they meet our criteria. For new business lines, we initially invest based on research and analysis. We start with a limited investment, we evaluate results and either expand or exit the business based on those results. In any given year, the amount of growth capital will be determined by the underlying cash flows of the Company with a clear understanding of any potential impact on our credit ratings.

Net cash used for investing activities was $256 million in the first quarter of 2009 compared to net cash from investing activities of $19 million in 2008. The 2009 change was primarily driven by the sale of a portion of our Barnett shale properties in 2008.

Cash from Financing Activities

We rely on both short-term borrowing and long-term financing as a source of funding for our capital requirements not satisfied by our operations.

Our strategy is to have a targeted debt portfolio blend of fixed and variable interest rates and maturity. We continually evaluate our leverage target, which is currently 50 percent to 52 percent, to ensure it is consistent with our objective to have a strong investment grade debt rating. We have completed a number of refinancings with the effect of extending the average maturity of our long-term debt and strengthening our balance sheet.

Net cash used for financing activities decreased $373 million during the first quarter of 2009 compared to the same period in 2008, primarily due to a decrease in short-term borrowings and a lower level of debt repurchases in 2009.

Outlook

We expect cash flow from operations to increase over the long-term primarily as a result of growth from our utilities and the non-regulated businesses. We 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. Energy 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 and maintaining flexibility in the timing and extent of our long-term capital projects.

Recent distress in the financial markets has had an adverse impact on financial market activities, including extreme volatility in security prices and severely diminished liquidity and credit availability. Pursuant to the failures of large financial institutions, the credit situation rapidly evolved into a global crisis resulting in a number of international bank failures and declines in various stock indexes, and large reductions in the market value of equities and

commodities worldwide. The crisis has led to increased volatility in the markets for both financial and physical assets, as the failures of large financial institutions resulted in sharply reduced trading volumes and activity. The effects of the credit situation will continue to be monitored.

Short-term borrowings, principally in the form of commercial paper, provide us with the liquidity needed on a daily basis. Our commercial paper program is supported by our unsecured credit facilities. Beginning late in the third quarter of 2008, access to the commercial paper markets was sharply reduced and, as a result, we drew against our unsecured credit lines to supplement other sources of funds to meet our short-term liquidity needs. Since December 31, 2008, we have benefited from substantially improved liquidity and pricing in the commercial paper market. As a result, we repaid all of our back-up credit facility draws during the first quarter of 2009.

Approximately $1.2 billion of our total credit arrangements of $2.1 billion had expiration dates between June and December 2009, with the remainder expiring in October 2010. In April 2009 we completed an early renewal of $975 million of our syndicated revolving credit facilities before their scheduled expiration in October 2009. The new $1 billion two-year facility will expire in 2011 and has similar covenants to the prior facility. A new two-year $50 million credit facility was completed in April 2009. Other credit facilities totaling approximately $150 million will also expire in 2009 and we are evaluating the need for replacement.

As a result of losses experienced in the 2008 financial markets, our benefit plan assets experienced negative returns, which will result in higher benefit costs and contributions in 2009 and potentially in future years relative to the recent past.

While the impact of continued market volatility and turmoil in the credit markets cannot be predicted, we believe we have sufficient operating flexibility, cash resources and funding sources to maintain adequate amounts of liquidity and to meet our future operating cash and capital expenditure needs. However, virtually all of our businesses are capital intensive, or require access to capital, and the inability to access adequate capital could adversely impact earnings and cash flows.

Credit Ratings

As part of the normal course of business, Detroit Edison, MichCon and various non-utility subsidiaries of the Company routinely enter into physical or financially settled contracts for the purchase and sale of electricity, natural gas, coal, capacity, storage and other energy-related products and services. Certain of these contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit in the event that the credit rating of DTE Energy is downgraded below investment grade. Certain of these contracts for Detroit Edison and MichCon contain similar provisions in the event that the credit rating of the particular utility is downgraded below investment grade. The amount of such collateral which could be requested fluctuates based upon commodity prices and the provisions and maturities of the underlying transactions and could be substantial. Also, upon a downgrade below investment grade, we could have restricted access to the commercial paper market and if the parent is downgraded below investment grade our non-utility businesses, especially the Energy Trading and Power and Industrial Projects segments, could be required to restrict operations due to a lack of available liquidity. While we currently do not anticipate such a downgrade, we cannot predict the outcome of current or future credit rating agency reviews. Our current credit ratings, as determined by three nationally recognized credit rating agencies, are considered investment grade.

CRITICAL ACCOUNTING ESTIMATES

Asset Impairments — Goodwill

Certain of our reporting units have goodwill or allocated goodwill resulting from purchase business combinations. In accordance with SFAS No. 142, Goodwill and Other Intangible Assets, we perform an impairment test for each of our reporting units with goodwill annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In performing Step 1 of the impairment test, we compare the fair value of the reporting unit to its carrying value including goodwill. If the carrying value including goodwill were to exceed the fair value of a reporting unit, Step 2 of the test would be performed. Step 2 of the impairment test requires the carrying value of goodwill to be reduced to its fair value, if lower, as of the test date.

For Step 1 of the test, we estimate the reporting unit’s fair value using standard valuation techniques, including techniques which use estimates of projected future results and cash flows to be generated by the reporting unit. Such techniques generally include a terminal value that utilizes an earnings multiple approach, which incorporates the current market values of comparable entities. These cash flow valuations involve a number of estimates that require broad assumptions and significant judgment by management regarding future performance. We also employ market-based valuation techniques to test the reasonableness of the indications of value for the reporting units determined under the cash flow technique.

We performed our annual impairment test on October 1, 2008 and determined that the estimated fair value of each reporting unit exceeded its carrying value, and no impairment existed. In the period from October 1, 2008 to March 31, 2009, DTE Energy’s stock price declined by 31 percent and at March 31, 2009 was approximately 26 percent below its book value per share of $37.29. We deemed the duration and severity of the decline in DTE Energy’s stock price to be a triggering event to test for potential goodwill impairment for the first quarter.

A first quarter interim test was performed for all reporting units with allocated goodwill as of February 28, 2009. The results of the test and key estimates that were incorporated are as follows.

As of February 28, 2009 Valuation Date
($ in millions)


			Fair Value			Discount			Terminal
Reporting Unit	Goodwill		Reduction % (a)			Rate			Multiple (b)		Valuation Methodology (c)
Electric Utility	$	1,206		17	%		7	%		7.0x	DCF, assuming stock sale
Gas Utilities		772		6	%		7	%		9.0x	DCF, assuming stock sale
Energy Services		28		55	%		14	%		4.5x	DCF, assuming asset sale
Coal Services		4		15	%		11	%		5.5x	DCF, assuming asset sale
Gas Midstream		7		59	%		10	%		7.5x	DCF, assuming asset sale
Energy Trading		17		100	%		n/a			n/a	Economic value of trading portfolio
Unconventional Gas Production		2		56	%		14	%		n/a	Blended — DCF, transaction multiples

	$	2,036


(a)		Percentage by which the fair value of the reporting unit would need to decline to equal its carrying value.

(b)		Multiple of enterprise value (sum of debt plus equity value) to earnings before interest, taxes, depreciation and amortization (EBITDA)

(c)		Discounted cash flows (“DCF”) incorporated 2009-2013 projected cash flows plus a calculated terminal value.

For the first quarter interim test, we updated projected future results, cash flows and discount rates to reflect recent regulatory actions and negative impacts from the deterioration in the regional and national economy. Terminal values that utilize an earnings multiple approach were updated to incorporate the current market values of comparable entities. As compared to the annual test performed in the fourth quarter of 2008, the valuations were negatively impacted by current market factors with particular downward pressure on market multiples. We also compared the aggregate fair value of our reporting units to our overall market capitalization. The implied premium of the aggregate fair value over market capitalization is likely attributable to factors such as (1) an acquisition control premium (the price in excess of a stock’s market price that investors typically pay to gain control of an entity), and (2) the market’s apparent discounting of DTE Energy’s stock price due to uncertainty regarding the current regulatory and automotive industry environment and DTE Energy’s diverse non-utility business portfolio. All reporting units passed Step 1 of the impairment test.

The excess of fair value over carrying value for our Gas Utilities reporting unit narrowed considerably since the fourth quarter 2008 test, largely due to declines in the market values and resulting market multiples of comparable entities referenced in our valuation. Further declines in market multiples, negative regulatory actions or other disruptions in cash flows for the Gas Utility reporting unit could result in an impairment charge in the foreseeable future. For example, at the current discount rate and holding all other variables constant, a 0.5x decrease in the terminal multiple would lower the fair value by approximately $130 million. At the lower fair value, the Gas Utility reporting unit would likely fail Step 1 of the test potentially resulting in a charge for impairment of goodwill following completion of the Step 2 analysis.

We will continue to monitor our estimates and assumptions regarding estimated future cash flows, including the impact of movements in market indicators in future quarters and will update our impairment analyses if a triggering event occurs. While we believe our assumptions are reasonable, actual results may differ from our projections. To the extent projected results or 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.

FAIR VALUE

SFAS No. 133, as amended, requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value, as Derivative assets or liabilities. Contracts we typically classify as derivative instruments include power, gas, certain coal and oil forwards, futures, options and swaps, and foreign currency contracts. Items we do not generally account for as derivatives include proprietary gas inventory, gas storage and transportation arrangements, and gas and oil reserves. See Note 3 of the Notes to Consolidated Financial Statements.

As a result of adherence to generally accepted accounting principles, the tables below do not include the expected earnings impacts of non-derivative gas storage, transportation and power contracts. Consequently, gains and losses from these positions may not match with the related physical and financial hedging instruments in some reporting periods, resulting in volatility in DTE Energy’s reported period-by-period earnings; however, the financial impact of this timing difference will reverse at the time of physical delivery and/or settlement.

The Company manages its mark-to-market (MTM) risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, it records and manages the energy purchase and sale obligations under its contracts in separate components based on the commodity (e.g. electricity or gas), the product (e.g. electricity for delivery during peak or off-peak hours), the delivery location (e.g. by region), the risk profile (e.g. forward or option), and the delivery period (e.g. by month and year). The following tables contain the four categories of activities represented by their operating characteristics and key risks:

	•		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.

	•		Structured Contracts — Represents derivative activity transacted by originating substantially hedged positions with wholesale energy marketers, producers, end users, utilities, retail aggregators and alternative energy suppliers.

	•		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.

	•		Other — Includes derivative activity associated with our Unconventional Gas reserves. A portion of the price risk associated with anticipated production from the Barnett natural gas reserves has been mitigated through 2010. Changes in the value of the hedges are recorded as Derivative assets or liabilities, with an offset in Other comprehensive income to the extent that the hedges are deemed effective. The amounts shown in the following tables exclude the value of the underlying gas reserves including changes therein. Other also includes derivative activity at Detroit Edison related to Financial Transmission Rights (FTR) and forward contracts related to emissions. Changes in the value of derivative contracts at Detroit Edison are recorded as Derivative assets or liabilities, with an offset to Regulatory assets or liabilities as the settlement value of these contracts will be included in the PSCR mechanism when realized.

The following tables provide details on changes in our MTM net asset (or liability) position for the three months ended March 31, 2009:


	Economic			Structured			Proprietary
(in Millions)	Hedges			Contracts			Trading			Other			Total
MTM at December 31, 2008	$	18		$	(222	)	$	22		$	9		$	(173	)

Reclassify to realized upon settlement		(3	)		(12	)		(21	)		(2	)		(38	)
Changes in fair value recorded to income		2			52			9			—			63
Amortization of option premiums		—			—			10			—			10

Amounts recorded to income		(1	)		40			(2	)		(2	)		35
Changes in fair value recorded in regulatory liabilities		—			—			—			(13	)		(13	)
Amounts recorded in other comprehensive income		—			—			—			5			5
Change in collateral held by (for) others		14			21			22			—			57
Option premiums and other		—			—			(65	)		—			(65	)

MTM at March 31, 2009	$	31		$	(161	)	$	(23	)	$	(1	)	$	(154	)

A substantial portion of the Company’s price risk related to its Antrim shale gas exploration and production business was mitigated by financial contracts that hedged our price risk exposure through 2013. The contracts were retained when the Antrim business was sold and offsetting financial contracts were put into place to effectively settle these positions. The contracts will require payments through 2013. These contracts represent a significant portion of the above net mark-to-market liability.

The following table provides a current and noncurrent analysis of Derivative assets and liabilities, as reflected on the Consolidated Statements of Financial Position as of March 31, 2009. Amounts that relate to contracts that become due within twelve months are classified as current and all remaining amounts are classified as noncurrent.


	Economic			Structured			Proprietary									Assets
(in Millions)	Hedges			Contracts			Trading			Eliminations			Other			(Liabilities)
Current assets	$	35		$	222		$	29		$	(11	)	$	6		$	281
Noncurrent assets		9			164			5			(3	)		2			177

Total MTM assets		44			386			34			(14	)		8			458


Current liabilities		(8	)		(252	)		(46	)		11			(9	)		(304	)
Noncurrent liabilities		(5	)		(295	)		(11	)		3			—			(308	)

Total MTM liabilities		(13	)		(547	)		(57	)		14			(9	)		(612	)


Total MTM net assets (liabilities)	$	31		$	(161	)	$	(23	)	$	—		$	(1	)	$	(154	)

The table below shows the maturity of our MTM positions:


										2012
(in Millions)										and			Total Fair
Source of Fair Value	2009			2010			2011			Beyond			Value
Economic Hedges	$	14		$	—		$	1		$	16		$	31
Structured Contracts		(13	)		(48	)		(39	)		(61	)		(161	)
Proprietary Trading		(24	)		(6	)		1			6			(23	)
Other		2			(3	)		—			—			(1	)

Total	$	(21	)	$	(57	)	$	(37	)	$	(39	)	$	(154	)

Part I — Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Price Risk

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

The Electric and Gas utility businesses have risks in conjunction with the anticipated purchases of coal, natural gas, uranium, electricity, and base metals to meet their service obligations. Further, changes in the price of electricity can impact the level of exposure of Customer Choice programs and uncollectible expenses at the Electric Utility. In addition, changes in the price of natural gas can impact the valuation of lost and stolen gas, storage sales revenue and uncollectible expenses at the Gas Utility. However, the Company does not bear significant exposure to earnings risk as such changes are included in regulatory rate-recovery mechanisms. Regulatory rate-recovery occurs in the form of PSCR and GCR mechanisms (see Note 1 of the Notes to Consolidated Financial Statements) and tracking mechanisms to mitigate some losses from customer migration due to electric Customer Choice programs and uncollectible accounts receivable at MichCon. The Company is exposed to short-term cash flow or liquidity risk as a result of the time differential between actual cash settlements and regulatory rate recovery.

Our Power and Industrial Projects business segment is subject to crude oil, electricity, natural gas, coal and coal-based product price risk and other risks associated with the weakened U.S. economy. To the extent that commodity price risk has not been mitigated through the use of long-term contracts, we manage this exposure using forward energy, capacity and futures contracts.

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

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

Our Gas Midstream business segment has limited exposure to natural gas price fluctuations. The Gas Midstream business unit manages its exposure through the sale of long-term storage and transportation contracts.

Credit Risk

Bankruptcies

We purchase and sell electricity, gas, coal, coke and other energy products from and to numerous companies operating in the steel, automotive, energy, retail, financial 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 may have a material effect on our financial statements.

Our utilities and certain non-utility businesses provide services to the domestic automotive industry, including General Motors Corporation (GM), Ford Motor Company (Ford) and Chrysler LLC (Chrysler) and many of their vendors and suppliers. GM and Chrysler have received loans from the U.S. Government to provide them with the working capital necessary to continue to operate in the short term. Chrysler filed for bankruptcy protection on April 30, 2009. We will fully reserve invoiced and unbilled accounts receivable outstanding as of the date of the filing of approximately $10 million. In the event of a bankruptcy filing by GM, we will fully reserve invoiced and unbilled accounts receivable. Based on average monthly revenues and typical billing and payment cycles, we estimate that we may have pre-petition accounts receivable at risk of approximately $30 million for GM. The actual amounts to be reserved will be dependent on the timing of the bankruptcy filing within the billing cycle and whether any

amounts are past due. Currently, GM has been paying amounts owed in a timely manner and its account is substantially current. Closing of GM or Chrysler plants or other facilities that operate within Detroit Edison’s service territory will also negatively impact our operating revenues in future periods. In 2008, GM and Chrysler represented 3 percent and 2 percent of our annual electric sales volumes, respectively. GM and Chrysler have an immaterial impact to MichCon’s revenues.

Our Power and Industrial Projects segment has long-term contracts with GM to provide onsite energy services at certain of its manufacturing and administrative facilities. The long-term contracts provide for full recovery of our investment in the event of early termination. At March 31, 2009, the book value of long-lived assets used in the servicing of these facilities was approximately $76 million. Certain of these long-lived assets have been funded by non-recourse financing totaling approximately $58 million at March 31, 2009. As of December 31, 2008, we performed an impairment analysis on these assets in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Based on our undiscounted cash flow projections, we determined that we did not have an impairment at December 31, 2008. In the first quarter 2009, we reviewed the assumptions used in our impairment analysis and have concluded that we did not have a trigger to reassess for impairment as of March 31, 2009. Our assumptions and conclusions may change and we could have impairment losses if any of the facilities that we service are closed and/or the terms of the contracts are not honored by GM or the contracts are rejected through a bankruptcy process.

Our Power and Industrial Projects segment also has an equity investment of approximately $52 million in an entity which provides on-site energy services to Chrysler manufacturing facilities. Chrysler’s performance under the long-term contracts for services is guaranteed by Daimler North America Corporation (Daimler), a subsidiary of Daimler AG. The long-term contracts and the supporting Daimler guarantee provide for full recovery of our investment in the event of early termination or default. We believe that we will recover our investment in the event of facility closures, a Chrysler default or if the long-term contracts are rejected through the bankruptcy process.

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.

Trading Activities

We are exposed to credit risk through trading activities. Credit risk is the potential loss that may result if our trading counterparties fail to meet their contractual obligations. We utilize both external and internally generated credit assessments when determining the credit quality of our trading counterparties. The following table displays the credit quality of our trading counterparties as of March 31, 2009:


	Credit Exposure
	before Cash		Cash			Net Credit
(in Millions)	Collateral		Collateral			Exposure
Investment Grade (1)
A- and Greater	$	339	$	(20	)	$	319
BBB+ and BBB		251		—			251
BBB-		36		—			36

Total Investment Grade		626		(20	)		606

Non-investment grade (2)		24		—			24
Internally Rated — investment grade (3)		170		(8	)		162
Internally Rated — non-investment grade (4)		22		(7	)		15

Total	$	842	$	(35	)	$	807


(1)		This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s Investor Service (Moody’s) and BBB- assigned by Standard & Poor’s Rating Group (Standard & Poor’s). The five largest counterparty exposures combined for this category represented approximately 24 percent of the total gross credit exposure.


(2)		This category includes counterparties with credit ratings that are below investment grade. The five largest counterparty exposures combined for this category represented approximately three percent of the total gross credit exposure.

(3)		This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, but are considered investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately 15 percent of the total gross credit exposure.

(4)		This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, and are considered non-investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately three percent of the total gross credit exposure.

Interest Rate Risk

DTE Energy is subject to interest rate risk in connection with the issuance of debt and preferred securities. In order to manage interest costs, we may use treasury locks and interest rate swap agreements. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). As of March 31, 2009, we had a floating rate debt-to-total debt ratio of approximately 7 percent (excluding securitized debt).

Foreign Currency Risk

We have foreign currency exchange risk arising from market price fluctuations associated with fixed priced contracts. These contracts are denominated in Canadian dollars and are primarily for the purchase and sale of power as well as for long-term transportation capacity. To limit our exposure to foreign currency fluctuations, we have entered into a series of currency forward contracts through January 2013. 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 on the fair values of our commodity contracts, long-term debt instruments and foreign currency forward contracts. The sensitivity analysis involved increasing and decreasing forward rates at March 31, 2009 by a hypothetical 10 percent and calculating the resulting change in the fair values. The results of the sensitivity analysis calculations follow:


(in Millions)	Assuming a 10%			Assuming a 10%
Activity	increase in rates			decrease in rates			Change in the fair value of
Coal Contracts	$	1		$	(1	)	Commodity contracts
Gas Contracts	$	(4	)	$	3		Commodity contracts
Oil Contracts	$	1		$	(1	)	Commodity contracts
Power Contracts	$	(2	)	$	2		Commodity contracts
Interest Rate Risk	$	(306	)	$	334		Long-term debt
Foreign Currency Risk	$	2		$	(2	)	Forward contracts
Discount Rates	$	—		$	—		Commodity contracts

Part I — Item 4.

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 DTE Energy’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of March 31, 2009, 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 providing reasonable assurance 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 provide reasonable assurance 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 attained.

(b) Changes in internal control over financial reporting

There have been no changes in the Company’s internal control over financial reporting during the quarter ended March 31, 2009 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part I — Item 1.

DTE Energy Company
Consolidated Statements of Operations (Unaudited)


	Three Months Ended
	March 31
(in Millions, Except per Share Amounts)	2009			2008
Operating Revenues	$	2,255		$	2,570


Operating Expenses
Fuel, purchased power and gas		960			1,266
Operation and maintenance		591			699
Depreciation, depletion and amortization		232			226
Taxes other than income		80			80
Gain on sale of non-utility assets		—			(126	)
Other asset (gains) and losses, reserves and impairments, net		(3	)		(4	)

		1,860			2,141


Operating Income		395			429


Other (Income) and Deductions
Interest expense		132			124
Interest income		(3	)		(4	)
Other income		(24	)		(22	)
Other expenses		14			14

		119			112


Income Before Income Taxes		276			317

Income Tax Provision		97			116


Income from Continuing Operations		179			201

Discontinued Operations Income, net of taxes		—			12


Net Income		179			213

Less: Attributable to the Noncontrolling Interests
From continuing operations		1			1


Net Income Attributable to DTE Energy Company	$	178		$	212


Basic Earnings per Common Share
Income from continuing operations	$	1.09		$	1.22
Discontinued operations		—			.08

Total	$	1.09		$	1.30


Diluted Earnings per Common Share
Income from continuing operations	$	1.09		$	1.22
Discontinued operations		—			.07

Total	$	1.09		$	1.29


Weighted Average Common Shares Outstanding
Basic		163			163
Diluted		163			163
Dividends Declared per Common Share	$	.53		$	.53

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Consolidated Statements of Financial Position (Unaudited)


	March 31			December 31
(in Millions)	2009			2008
ASSETS
Current Assets
Cash and cash equivalents	$	88		$	86
Restricted cash		22			86
Accounts receivable (less allowance for doubtful accounts of $269 and $265, respectively)
Customer		1,499			1,666
Other		163			166
Inventories
Fuel and gas		233			333
Materials and supplies		199			206
Deferred income taxes		199			227
Derivative assets		281			316
Other		182			242

		2,866			3,328


Investments
Nuclear decommissioning trust funds		657			685
Other		600			595

		1,257			1,280


Property
Property, plant and equipment		20,211			20,065
Less accumulated depreciation and depletion		(7,887	)		(7,834	)

		12,324			12,231


Other Assets
Goodwill		2,037			2,037
Regulatory assets		4,218			4,231
Securitized regulatory assets		969			1,001
Intangible assets		59			70
Notes receivable		119			115
Derivative assets		177			140
Other		162			157

		7,741			7,751


Total Assets	$	24,188		$	24,590

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Consolidated Statements of Financial Position (Unaudited)


	March 31			December 31
(in Millions, Except Shares)	2009			2008
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	727		$	899
Accrued interest		144			119
Dividends payable		87			86
Short-term borrowings		330			744
Gas inventory equalization		220			—
Current portion long-term debt, including capital leases		518			362
Derivative liabilities		304			285
Other		503			518

		2,833			3,013


Long-Term Debt (net of current portion)
Mortgage bonds, notes and other		6,288			6,458
Securitization bonds		861			932
Trust preferred-linked securities		289			289
Capital lease obligations		57			62

		7,495			7,741


Other Liabilities
Deferred income taxes		1,993			1,958
Regulatory liabilities		1,208			1,202
Asset retirement obligations		1,357			1,340
Unamortized investment tax credit		94			96
Derivative liabilities		308			344
Liabilities from transportation and storage contracts		107			111
Accrued pension liability		819			871
Accrued postretirement liability		1,406			1,434
Nuclear decommissioning		112			114
Other		304			328

		7,708			7,798


Commitments and Contingencies (Notes 5 and 9)

Shareholders’ Equity
Common stock, without par value, 400,000,000 shares authorized, 163,876,686 and 163,019,596 shares issued and outstanding, respectively		3,192			3,175
Retained earnings		3,076			2,985
Accumulated other comprehensive loss		(157	)		(165	)

Total DTE Energy Company Shareholders’ Equity		6,111			5,995
Noncontrolling Interest		41			43

Total Shareholders’ Equity		6,152			6,038

Total Liabilities and Shareholders’ Equity	$	24,188		$	24,590

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Consolidated Statements of Cash Flows (Unaudited)


	Three Months Ended
	March 31
(in Millions)	2009			2008
Operating Activities
Net income attributable to DTE Energy	$	178		$	212
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		232			225
Deferred income taxes		66			190
Gain on sale of non-utility assets		—			(126	)
Other asset (gains), losses and reserves, net		(3	)		(4	)
Gain on sale of interests in synfuel projects		—			(16	)
Contributions from synfuel partners		—			22
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		366			389

Net cash from operating activities		839			892


Investing Activities
Plant and equipment expenditures — utility		(303	)		(277	)
Plant and equipment expenditures — non-utility		(23	)		(52	)
Proceeds from sale of interests in synfuel projects		—			82
Refunds to synfuel partners		—			(31	)
Proceeds from sale of non-utility assets		—			250
Proceeds from sale of other assets, net		30			10
Restricted cash for debt redemptions		64			57
Proceeds from sale of nuclear decommissioning trust fund assets		113			52
Investment in nuclear decommissioning trust funds		(113	)		(61	)
Other investments		(24	)		(11	)

Net cash from (used) for investing activities		(256	)		19


Financing Activities
Redemption of long-term debt		(86	)		(79	)
Repurchase of long-term debt		—			(238	)
Short-term borrowings, net		(414	)		(534	)
Issuance of common stock		9			—
Repurchase of common stock		—			(13	)
Dividends on common stock		(86	)		(86	)
Other		(4	)		(4	)

Net cash used for financing activities		(581	)		(954	)


Net Increase (Decrease) in Cash and Cash Equivalents		2			(43	)
Cash and Cash Equivalents Reclassified to Assets Held for Sale		—			(3	)
Cash and Cash Equivalents at Beginning of Period		86			123

Cash and Cash Equivalents at End of Period	$	88		$	77

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Consolidated Statements of Changes in Shareholders’ Equity and
Comprehensive Income (Unaudited)


								Accumulated
								Other
	Common Stock				Retained			Comprehensive			Noncontrolling
(Dollars in Millions, Shares in Thousands)	Shares		Amount		Earnings			Loss			Interest			Total

Balance, December 31, 2008		163,020	$	3,175	$	2,985		$	(165	)	$	43		$	6,038

Net income		—		—		178			—			1			179
Benefit obligations, net of tax		—		—		—			3			—			3
Dividends declared on common stock		—		—		(87	)		—			—			(87	)
Issuance of common stock		272		9		—			—			—			9
Net change in unrealized losses on derivatives, net of tax		—		—		—			2			—			2
Net change in unrealized losses on investments, net of tax		—		—		—			3						3
Stock-based compensation and other		585		8		—			—			(3	)		5

Balance, March 31, 2009		163,877	$	3,192	$	3,076		$	(157	)	$	41		$	6,152

The following table displays other comprehensive income for the three-month periods ended March 31:


(in Millions)	2009			2008
Net income attributable to DTE Energy	$	178		$	212

Other comprehensive income (loss), net of tax:
Benefit obligations, net of taxes of $1 and $-, respectively		3			—
Net unrealized gains (losses) on derivatives:
Gains (losses) during the period, net of taxes of $2 and $(2), respectively		3			(4	)
Amounts reclassified to income, net of taxes of $- and $-, respectively		(1	)		—

		2			(4	)

Net unrealized gains (losses) on investments:
Gains (losses) during the period, net of taxes of $1 and $(2), respectively		3			(4	)


Comprehensive income	$	186		$	204

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Notes to Consolidated Financial Statements (Unaudited)

NOTE 1 — GENERAL

The Company is a diversified energy company. It is 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. The Company also operates four energy-related non-utility segments with operations throughout the United States.

These Consolidated Financial Statements should be read in conjunction with the Notes to Consolidated Financial Statements included in the 2008 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 management to use estimates and assumptions that impact reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from the Company’s estimates.

The Consolidated Financial Statements are unaudited, but in our opinion include all adjustments necessary for a fair presentation of such financial statements. All adjustments are of a normal recurring nature, except as otherwise disclosed in these Consolidated Financial Statements and Notes to Consolidated Financial Statements. 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 ending December 31, 2009.

Certain prior year amounts have been reclassified to reflect current year classifications.

Asset Retirement Obligations

The Company records asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and FASB Interpretation Number (FIN) 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. The Company has a legal retirement obligation for the decommissioning costs for its Fermi 1 and Fermi 2 nuclear plants. To a lesser extent, the Company has legal retirement obligations for gas production facilities, gas gathering facilities and various other operations. The Company has conditional retirement obligations for gas pipeline retirement costs and disposal of asbestos at certain of its power plants. To a lesser extent, the Company has conditional retirement obligations at certain service centers, compressor and gate stations, and disposal costs for PCB contained within transformers and circuit breakers. The Company recognizes such obligations as liabilities at fair market value when they are incurred, which generally is at the time the associated assets are placed in service. Fair value is measured using expected future cash outflows discounted at our credit-adjusted risk-free rate.

For the Company’s regulated operations, timing differences arise in the expense recognition of legal asset retirement costs that the Company is currently recovering in rates. The Company defers such differences under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

A reconciliation of the asset retirement obligations for the three months ended March 31, 2009 follows:


(in Millions)
Asset retirement obligations at January 1, 2009	$	1,361
Accretion		22
Liabilities settled		(2	)
Revision in estimated cash flows		(4	)

Asset retirement obligations at March 31, 2009		1,377
Less amount included in current liabilities		20

	$	1,357

Approximately $1.2 billion of the asset retirement obligations represent nuclear decommissioning liabilities that are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear power plant.

Goodwill

We performed our annual goodwill impairment test on October 1, 2008 and determined that the estimated fair value of our reporting units exceeded their carrying value, and no impairment existed. In the period from October 1, 2008 to March 31, 2009, DTE Energy’s stock price declined by 31 percent and at March 31, 2009 was approximately 26 percent below its book value per share of $37.29. We deemed the lengthening duration and severity of the decline in DTE Energy’s stock price to be a triggering event to test for potential goodwill impairment for the first quarter. In performing Step 1 of the impairment test, we compared the fair value of the reporting unit to its carrying value including goodwill. If the carrying value including goodwill were to exceed the fair value of a reporting unit, Step 2 of the test would be performed. Step 2 of the impairment test requires the carrying value of goodwill to be reduced to its fair value, if lower, as of the test date. All reporting units passed Step 1 of the impairment test.

Intangible Assets

The Company has certain intangible assets relating to non-utility contracts and emission allowances. The Company amortizes intangible assets on a straight-line basis over the expected period of benefit, ranging from 4 to 30 years. The gross carrying amount and accumulated amortization of intangible assets at March 31, 2009 were $74 million and $16 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2008 were $85 million and $15 million, respectively. Amortization expense of intangible assets is estimated to be $7 million annually for the years 2009 through 2013.

Retirement Benefits and Trusteed Assets

The following details the components of net periodic benefit costs for pension benefits and other postretirement benefits for the three months ended March 31:


							Other Postretirement
	Pension Benefits						Benefits
(in Millions)	2009			2008			2009			2008
Service cost	$	13		$	15		$	16		$	15
Interest cost		51			48			34			30
Expected return on plan assets		(64	)		(65	)		(14	)		(18	)
Amortization of:
Net actuarial loss		13			8			17			10
Prior service cost		1			1			(2	)		(1	)
Net transition liability		—			—			1			—

Net periodic benefit cost	$	14		$	7		$	52		$	36

The Company expects to contribute $250 million to its pension plans during 2009, including a $50 million contribution made to the plans in the first quarter of 2009.

The Company expects to contribute $130 million to its postretirement medical and life insurance benefit plans during 2009, including approximately $40 million of contributions made to the plans in the first quarter of 2009.

Income Taxes

The Company has $18 million of unrecognized tax benefits at March 31, 2009 that, if recognized, would favorably impact its effective tax rate. The Company’s uncertain tax positions have not changed significantly since December 31, 2008. During the next twelve months, it is reasonably possible that the Company will settle certain federal and state examinations and audits. Furthermore, the statutes of limitations will expire for the Company’s tax returns in various states. Therefore the Company believes that it is reasonably possible that there will be a decrease in unrecognized tax benefits of $5 million to $9 million within the next twelve months.

Stock-Based Compensation

The Company’s stock incentive program permits the grant of incentive stock options, non-qualifying stock options, stock awards, performance shares and performance units. Participants in the Plan include the Company’s employees and members of its Board of Directors.

The Company recorded stock-based compensation expense of $1 million and $8 million, with an associated tax benefit of $0.4 million and $2 million for the three months ended March 31, 2009 and 2008, respectively. Compensation cost capitalized in property, plant and equipment was $0.2 million and $0.4 million during the three months ended March 31, 2009 and 2008, respectively.

Stock Options

The following table summarizes our stock option activity for the three months ended March 31, 2009:


						(in Millions)
				Weighted		Aggregate
	Number of			Average		Intrinsic
	Options			Exercise Price		Value
Options outstanding at January 1, 2009		5,013,699		$	42.45
Granted		812,500		$	27.75
Exercised		(6,995	)	$	27.62
Forfeited or expired		(114,540	)	$	41.30

Options outstanding at March 31, 2009		5,704,664		$	40.40	$	2.5

Options exercisable at March 31, 2009		4,226,648		$	42.43	$	2.5

As of March 31, 2009, the weighted average remaining contractual life for the exercisable shares was 4.85 years. As of March 31, 2009, 1,478,016 options were non-vested. During the three months ended March 31, 2009, 581,706 options vested.

The weighted average grant date fair value of options granted during the first quarter of 2009 was $4.41 per share. The intrinsic value of options exercised for the three months ended March 31, 2009 was $0.04 million. Total option expense recognized was $1.5 million and $2 million for the three months ended March 31, 2009 and 2008, respectively.

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


	Three Months Ended
	March 31, 2009			March 31, 2008
Risk-free interest rate		2.04	%		3.23	%
Dividend yield		4.98	%		5.07	%
Expected volatility		27.88	%		20.34	%
Expected life	6 years			6 years

Stock Awards

The following summarizes stock awards activity for the three months ended March 31, 2009:


				Weighted Average
	Restricted			Grant Date
	Stock			Fair Value
Balance at January 1, 2009		931,722		$	45.31
Grants		510,810		$	28.62
Forfeitures		(3,890	)	$	40.67
Vested and issued		(253,247	)	$	42.85

Balance at March 31, 2009		1,185,395		$	38.66

Performance Share Awards

The following summarizes performance share activity for the three months ended March 31, 2009:


	Performance Shares
Balance at January 1, 2009		1,321,501
Grants		564,340
Forfeitures		(11,451	)
Payouts		(390,656	)

Balance at March 31, 2009		1,483,734

Unrecognized Compensation Cost

As of March 31, 2009, the Company had $48 million of total unrecognized compensation cost related to non-vested stock incentive plan arrangements. These costs are expected to be recognized over a weighted-average period of 1.73 years.

Offsetting Amounts Related to Certain Contracts

Consistent with FSP FIN 39-1, Amendment of FASB Interpretation No. 39, the Company offset the fair value of derivative instruments with cash collateral received or paid for those derivative instruments executed with the same counterparty under a master netting agreement, which reduces both the Company’s total assets and total liabilities. As of March 31, 2009, the total cash collateral posted, net of cash collateral received, was $60 million. In accordance with FSP FIN 39-1, derivative assets and derivative liabilities are shown net of collateral of $68 million and $111 million, respectively. At March 31, 2009, amounts not related to unrealized derivative positions totaling $22 million and $5 million were included in accounts receivable and accounts payable, respectively.

Consolidated Statements of Cash Flows

The following provides detail of the changes in assets and liabilities that are reported in the Consolidated Statements of Cash Flows, and supplementary cash information:


	Three Months Ended
	March 31
(in Millions)	2009			2008
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	119		$	99
Accrued GCR revenue		7			(81	)
Inventories		106			149
Accrued/prepaid pensions		(52	)		(4	)
Accounts payable		(113	)		(127	)
Accrued PSCR refund		75			52
Income taxes payable		31			6
Derivative assets and liabilities		(18	)		15
Gas inventory equalization		220			336
Postretirement obligation		(28	)		(39	)
Other assets		124			58
Other liabilities		(105	)		(75	)

	$	366		$	389

In connection with maintaining certain traded risk management positions, the Company may be required to post cash collateral with its clearing agent. As a result, the Company entered into a demand financing agreement for up to $50 million with its clearing agent in lieu of posting additional cash collateral (a non-cash transaction). There was $41 million outstanding under this facility at March 31, 2009 and $26 million outstanding as of December 31, 2008.

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

Fair Value Accounting

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 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. Effective January 1, 2008, the Company adopted SFAS No. 157. As permitted by FASB Staff Position FAS No. 157-2, the Company elected to defer the effective date of SFAS No. 157 as it pertains to measurement and disclosures about the fair value of non-financial assets and liabilities made on a nonrecurring basis. The Company has adopted the recognition provisions as of January 1, 2009. See Note 3 for further disclosures.

In April 2009, the FASB issued three FSPs intended to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities. The FSPs are effective for interim and annual periods ending after June 15, 2009, with certain early adoption provisions permitted for periods ending after March 15, 2009.

	•		FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments, expands the fair value disclosures required for all financial instruments within the scope of SFAS No. 107 to interim periods.

	•		FSP FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, which applies to all assets and liabilities, i.e., financial and nonfinancial, reemphasizes that the objective of fair value remains unchanged (i.e., an exit price notion). The FSP provides application guidance on measuring fair value when the volume and level of activity has significantly decreased and identifying transactions that are not orderly. The FSP also emphasizes that an entity cannot presume that an observable transaction price is not orderly even when there has been a significant decline in the volume and level of activity.

•

FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments, is intended to bring greater consistency to the timing of impairment recognition, and provide greater clarity to investors about the credit and noncredit components of impaired debt securities that are not expected to be sold.

The Company will adopt these FSPs in the second quarter of 2009. The adoption of these FSPs will not have a material impact on DTE Energy’s consolidated financial statements.

Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities

In June 2008, the FASB issued FSP EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities. This FSP addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (EPS) under the two-class method described in paragraphs 60 and 61 of SFAS No. 128, Earnings Per Share. Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. Stock awards granted by the Company under its stock-based compensation plan qualify as a participating security. This FSP is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008 and will be applied retrospectively. The Company adopted the requirements of the FSP effective January 1, 2009. See Note 6 for further disclosure.

Disclosures about Derivative Instruments and Guarantees

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133. This statement requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows.

SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. Comparative disclosures for earlier periods at initial adoption are encouraged but not required. The Company adopted SFAS No. 161 effective January 1, 2009. See Note 3.

Noncontrolling Interests in Consolidated Financial Statements

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51. This Statement establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 is effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2008. This Statement shall be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, except for the presentation and disclosure requirements which shall be applied retrospectively for all periods presented. The Company adopted SFAS No. 160 as of January 1, 2009. Adoption of SFAS No. 160 did not have a material effect on the Company’s consolidated financial statements.

NOTE 3 —FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS AND FAIR VALUE

Financial and Other Derivative Instruments

The Company complies with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. Under SFAS No. 133, all derivatives are recognized on the Consolidated Statement of Financial Position at their fair value unless they qualify for certain scope exceptions, including normal purchases and normal sales exception. Further, derivatives that qualify and are designated for hedge accounting are classified

as either hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge), or as hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge). For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the value of the underlying exposure is deferred in Accumulated other comprehensive income and later reclassified into earnings when the underlying transaction occurs. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For derivatives that do not qualify or are not designated for hedge accounting, changes in the fair value are recognized in earnings each period.

The Company’s primary market risk exposure is associated with commodity prices, credit, interest rates and foreign currency. The Company has risk management policies to monitor and manage market risks. The Company uses derivative instruments to manage some of the exposure. The Company uses derivative instruments for trading purposes in its Energy Trading segment and the coal marketing activities of its Power and Industrial Projects segment. Contracts the Company typically classifies as derivative instruments include power, gas, certain coal and oil forwards, futures, options and swaps, and foreign currency contracts. Items it does not generally account for as derivatives include proprietary gas inventory, gas storage and transportation arrangements, and gas and oil reserves. The fair value of all derivatives is included in Derivative assets or liabilities on the Consolidated Statements of Financial Position.

Utility Operations

Detroit Edison — Detroit Edison generates, purchases, distributes and sells electricity. Detroit Edison uses forward energy and capacity contracts to manage changes in the price of electricity and fuel. Substantially all of these derivatives meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. Other derivative contracts are recoverable through the PSCR mechanism when realized. This results in the deferral of unrealized gains and losses as Regulatory assets or liabilities, until realized.

MichCon — MichCon purchases, stores, transports and distributes natural gas and sells storage and transportation capacity. MichCon has fixed-priced contracts for portions of its expected gas supply requirements through 2012. These gas-supply contracts are designated and qualify for the normal purchases and sales exemption and are therefore accounted for under the accrual method. MichCon may also sell forward storage and transportation capacity contracts. Forward firm transportation and storage contracts are not derivatives and are therefore accounted for under the accrual method.

Non-Utility Operations

Power and Industrial Projects — Business units within this segment manage and operate on-site energy and pulverized coal projects, coke batteries, landfill gas recovery and power generation assets. These businesses utilize fixed-priced contracts in the marketing and management of their assets. These contracts are generally not derivatives and are therefore accounted for under the accrual method. The segment also engages in coal marketing which includes the marketing and trading of physical coal and coal financial instruments, and forward contracts for the purchase and sale of emissions allowances. Certain of these physical and financial coal contracts and contracts for the purchase and sale of emission allowances are derivatives and are accounted for by recording changes in fair value to earnings, specifically as a component of Operating revenues.

Unconventional Gas Production — The Unconventional Gas Production business is engaged in unconventional gas project development and production. The Company uses derivative contracts to manage changes in the price of natural gas. These derivatives are designated as cash flow hedges. Amounts recorded in other comprehensive loss will be reclassified to earnings, specifically as a component of Operating revenues, as the related production affects earnings through 2010. Management estimates reclassifying an after-tax gain of approximately $4 million to earnings within the next twelve months.

Energy Trading — Commodity Price Risk — Energy Trading markets and trades wholesale electricity and natural gas physical products and energy financial instruments, and provides risk management services utilizing energy commodity derivative instruments. Forwards, futures, options and swap agreements are used to manage exposure to the risk of market price and volume fluctuations in its operations. These derivatives are accounted for by recording

changes in fair value to earnings, specifically as a component of Operating revenues, unless certain hedge accounting criteria are met.

Energy Trading — Foreign Currency Risk — Energy Trading has foreign currency forward contracts to hedge fixed Canadian dollar commitments existing under power purchase and sale contracts and gas transportation contracts. The Company enters into these contracts to mitigate price volatility with respect to fluctuations of the Canadian dollar relative to the U.S. dollar. These derivatives are accounted for by recording changes in fair value to earnings, specifically as a component of Operating revenues, unless certain hedge accounting criteria are met.

Gas Midstream — These business units are primarily engaged in services related to the transportation, and storage of natural gas. These businesses utilize fixed-priced contracts in their marketing and management of their businesses. Generally these contracts are not derivatives and are therefore accounted for under the accrual method.

The Company manages its MTM risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, it records and manages the energy purchase and sale obligations under its contracts in separate components based on the commodity (e.g. electricity or gas), the product (e.g. electricity for delivery during peak or off-peak hours), the delivery location (e.g. by region), the risk profile (e.g. forward or option), and the delivery period (e.g. by month and year). The following describe the four categories of activities represented by their operating characteristics and key risks:

	•		Economic Hedges — Represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas 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.

	•		Structured Contracts — Represents derivative activity transacted by originating substantially hedged positions with wholesale energy marketers, producers, end users, utilities, retail aggregators and alternative energy suppliers.

	•		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.

	•		Other — Includes derivative activity associated with our Unconventional Gas reserves. A portion of the price risk associated with anticipated production from the Barnett natural gas reserves has been mitigated through 2010. Changes in the value of the hedges are recorded as Derivative assets or liabilities, with an offset in Other comprehensive income to the extent that the hedges are deemed effective. Other also includes derivative activity at Detroit Edison related to Financial Transmission Rights (FTR) and forward contracts related to emissions. Changes in the value of derivative contracts at Detroit Edison are recorded as Derivative assets or liabilities, with an offset to Regulatory Liabilities or Assets as the settlement value of these contracts will be included in the PSCR mechanism when realized.

Effective January 1, 2009, the Company adopted SFAS No. 161. This Statement requires enhanced disclosures about an entity’s derivative and hedging activities.

The following represents the fair value of derivative instruments as of March 31, 2009:


	Balance Sheet			Balance Sheet
(in Millions)	Location	Fair Value		Location	Fair Value
Derivatives designated as hedging instruments under SFAS No. 133

Commodity Contracts:
Natural Gas	Derivative assets	$	8	Derivative liabilities	$	—


Derivatives not designated as hedging instruments under SFAS No. 133

Foreign exchange contracts	Derivative assets	$	91	Derivative liabilities	$	(72	)
Commodity Contracts:
Electricity	Derivative assets		1,927	Derivative liabilities		(1,899	)
Natural Gas	Derivative assets		2,391	Derivative liabilities		(2,638	)
Coal	Derivative assets		72	Derivative liabilities		(66	)
Oil	Derivative assets		20	Derivative liabilities		(25	)
Emissions	Derivative assets		5	Derivative liabilities		(11	)

Total derivatives not designated as hedging instruments under SFAS No. 133		$	4,506		$	(4,711	)


Total derivatives:
Current		$	3,177		$	(3,197	)
Noncurrent			1,337			(1,514	)

Total derivatives		$	4,514		$	(4,711	)


Reconciliation of derivative instruments to
Consolidated Statement of Financial Position:	Current			Noncurrent			Current			Noncurrent
Total fair value of derivatives	$	3,177		$	1,337		$	(3,197	)	$	(1,514	)
Counterparty netting		(2,847	)		(1,141	)		2,847			1,141
Collateral adjustments		(49	)		(19	)		46			65

Total derivatives as reported	$	281		$	177		$	(304	)	$	(308	)

The effect of derivative instruments on the Consolidated Statement of Operations for the three months ended March 31, 2009 is as follows:

Location of Gain

Gain (Loss)

(Loss) Recognized

Recognized in

in Income on

Income on

Gain (Loss)

Location of

Derivative

Recognized

Gain (Loss)

(Ineffective

(in Millions)

in OCI on

Reclassified from

Portion and Amount

Derivatives in SFAS No. 133

Derivative

Accumulated OCI

Excluded from

Cash Flow Hedging

(Effective Portion)

into Income

Effectiveness

Relationships

⁽¹⁾

(Effective Portion)

Testing)

Commodity Contracts:

Natural Gas

Operating Revenue

)

Operating Revenue

—


⁽¹⁾		Gain (loss) reported after taxes.


(in Millions)	Location of Gain	Gain (Loss)
Derivatives Not Designated	(Loss) Recognized	Recognized in
As Hedging Instruments	in Income On	Income on
Under SFAS No. 133	Derivative	Derivative

Foreign exchange contracts	Operating Revenue	$	6

Commodity Contracts:
Electricity	Operating Revenue		(1	)
Natural Gas	Operating Revenue		31
Coal	Operating Revenue		(6	)
Oil	Operating Revenue		1
Emissions	Operating Revenue		6

Total		$	37

The effect of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statement of Financial Position as of March 31, 2009 is as follows:


	Location of Gain	Gain (Loss)
	(Loss) Recognized	Recognized in
	in Regulatory	Regulatory Assets
	Assets / Liabilities	/ Liabilities on
	On Derivative	Derivative

FTR and Emissions	Regulatory Asset	$	(9	)
	Regulatory Liability		(4	)

Total		$	(13	)

The following represents the cumulative gross volume of derivative contracts outstanding as of March 31, 2009:


Commodity	Number of Units
Electricity (MWh)		63,104,026
Natural Gas (MMBtu)		561,165,345
Coal (Tons)		517,791
Oil (bbl)		178,760
Foreign Exchange ($ CAD)		32,283,059
Emissions (Tons)		31,005

Various non-utility subsidiaries of the Company have entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade. Certain of these provisions (known as “hard triggers”) state specific circumstances under which the Company can be asked to post collateral upon the occurrence of a credit downgrade, while other provisions (known as “soft triggers”) are not as specific. For contracts with soft triggers, it is difficult to estimate the amount of collateral which may be requested by counterparties and/or which the Company may ultimately be required to post.

The amount of such collateral which could be requested fluctuates based on commodity prices (primarily gas, power and coal) and the provisions and maturities of the underlying transactions. As of March 31, 2009, the value of the transactions for which the Company would have been exposed to collateral requests had DTE Energy’s credit rating been below investment grade on such date was approximately $390 million. In circumstances where an entity is downgraded below investment grade and collateral requests are made as a result, the requesting parties often agree to accept less than the full amount of their exposure to the downgraded entity.

Fair Value

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants’ use in pricing assets or liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The Company makes certain assumptions it believes that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and its counterparties is incorporated in the valuation of assets and liabilities through the use of credit reserves, the impact of which is immaterial for the three months ended March 31, 2009. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

SFAS No. 157 establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. SFAS No. 157 requires that assets and liabilities be classified in their entirety based on the lowest level of input that is significant to the fair value measurement in its entirety. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The Company classifies fair value balances based on the fair value hierarchy defined by SFAS No. 157 as follows:

	•		Level 1 — Consists of unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access as of the reporting date.

	•		Level 2 — Consists of inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

	•		Level 3 — Consists of unobservable inputs for assets or liabilities whose fair value is estimated based on internally developed models or methodologies using inputs that are generally less readily observable and supported by little, if any, market activity at the measurement date. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of March 31, 2009:


										Netting			Net Balance at
(in Millions)	Level 1			Level 2			Level 3			Adjustments⁽²⁾			March 31, 2009
Assets:
Cash equivalents	$	37		$	—		$	—		$	—		$	37
Nuclear decommissioning trusts and Other Investments ⁽¹⁾		472			299			1			—			772
Derivative assets		2,146			1,624			744			(4,056	)		458

Total	$	2,655		$	1,923		$	745		$	(4,056	)	$	1,267


Liabilities:
Derivative liabilities	$	(2,185	)	$	(1,617	)	$	(909	)	$	4,099		$	(612	)

Total	$	(2,185	)	$	(1,617	)	$	(909	)	$	4,099		$	(612	)

Net Assets (Liabilities) at March 31, 2009	$	470		$	306		$	(164	)	$	43		$	655


⁽¹⁾		Excludes cash surrender value of life insurance investments.

⁽²⁾		Amounts represent the impact of master netting agreements that allow the Company to net gain and loss positions and cash collateral held or placed with the same counterparties.

The following table presents the fair value reconciliation of Level 3 derivative assets and liabilities measured at fair value on a recurring basis for the three months ended March 31, 2009 and 2008:


(in Millions)	2009			2008
Liability balance as of January 1⁽¹⁾	$	(183	)	$	(366	)
Changes in fair value recorded in income		229			(231	)
Changes in fair value recorded in regulatory assets/liabilities		(4	)		—
Changes in fair value recorded in other comprehensive income		5			(6	)
Purchases, issuances and settlements		(48	)		26
Transfers in/out of Level 3		(163	)		—

Liability balance as of March 31	$	(164	)	$	(577	)

The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at March 31, 2009 and 2008	$	206		$	(231	)


(1)		Balance as of January 1, 2008 includes a cumulative effect adjustment which represents an increase to the beginning retained earnings related to Level 3 derivatives upon adoption of SFAS No. 157.

Net gains of $229 million related to Level 3 derivative assets and liabilities are reported in Operating revenues for the three months ended March 31, 2009 consistent with the Company’s accounting policy. Net losses of $166 million related to Level 1 and Level 2 derivative assets and liabilities, and the impact of netting, are also reported in Operating revenues for the three months ended March 31, 2009. Changes in fair value for Level 3 derivatives increased largely as a result of declining commodity prices. Net losses of $231 million related to Level 3 derivative assets and liabilities are reported in Operating revenues for the three months ended March 31, 2008 consistent with the Company’s accounting policy. Net gains of $245 million related to Level 1 and Level 2 derivative assets and liabilities, and the impact of netting, are also reported in Operating revenues for the three months ended March 31, 2008. Transfers in/out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level or for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. Transfers in/out of Level 3 are reflected as if they had occurred at the beginning of the period. Transfers out of Level 3 in the current period reflect increased reliance on broker quotes for certain gas transactions.

Cash Equivalents

Cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value table are comprised of investments in money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized as Level 1 in the fair value hierarchy.

Nuclear Decommissioning Trusts and Other Investments

The nuclear decommissioning trust fund investments have been established to satisfy Detroit Edison’s nuclear decommissioning obligations. The nuclear decommissioning trusts and other fund investments hold debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices on actively traded markets. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued using quoted prices in actively traded markets. Non-exchange-traded fixed income securities are valued based upon quotations available from brokers or pricing services. For non-exchange traded fixed income securities, the trustees receive prices from pricing services. A primary price source is identified by asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustees challenge an assigned price and determine that another price source is considered to be preferable. DTE Energy has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, DTE Energy selectively corroborates the fair values of securities by comparison of market-based price sources.

Derivative Assets and Liabilities

Derivative assets and liabilities are comprised of physical and financial derivative contracts, including futures, forwards, options and swaps that are both exchange-traded and over-the-counter traded contracts. Various inputs are used to value derivatives depending on the type of contract and availability of market data. Exchange-traded derivative contracts are valued using quoted prices in active markets. DTE Energy considers the following criteria in determining whether a market is considered active: frequency in which pricing information is updated, variability in pricing between sources or over time and the availability of public information. Other derivative contracts are valued based upon a variety of inputs including commodity market prices, broker quotes, interest rates, credit ratings, default rates, market-based seasonality and basis differential factors. DTE Energy monitors the prices that are supplied by brokers and pricing services and may use a supplemental price source or change the primary price source of an index if prices become unavailable or another price source is determined to be more representative of fair value. DTE Energy has obtained an understanding of how these prices are derived. Additionally, DTE Energy selectively corroborates the fair value of its transactions by comparison of market-based price sources. Mathematical valuation models are used for derivatives for which external market data is not readily observable, such as contracts which extend beyond the actively traded reporting period. Derivative instruments are principally used in the Company’s Energy Trading segment.

NOTE 4 — DISPOSALS AND DISCONTINUED OPERATIONS

Sale of Interest in Barnett Shale Properties

In January 2008, the Company sold a portion of its Barnett shale properties for gross proceeds of approximately $250 million. The Company recognized a gain of $126 million ($80 million after-tax) on the sale.

Synthetic Fuel Business

Due to the expiration of synfuel production tax credits in 2007, the Synthetic Fuel business ceased operations and was classified as a discontinued operation as of December 31, 2007. The favorable impact of reserve adjustments for the final phase-out percentage of approximately $16 million, other true-ups and related tax impacts resulted in net income of $12 million for the first quarter of 2008.

The Company has provided certain guarantees and indemnities in conjunction with the sales of interests in its synfuel facilities. The guarantees cover potential commercial, environmental, oil price and tax-related obligations and will survive until 90 days after expiration of all applicable statutes of limitations. The Company estimates that its maximum potential liability under these guarantees at March 31, 2009 is $2.9 billion.

NOTE 5 — REGULATORY MATTERS

2009 Electric Rate Case Filing

The requested $378 million increase in revenues is required to recover the increased costs associated with environmental compliance, operation and maintenance of the Company’s electric distribution system and generation plants, customer uncollectible accounts, inflation, the capital costs of plant additions and the reduction in territory sales.

In addition, Detroit Edison’s filing made, among other requests, the following proposals:

	•		Continued progress toward correcting the existing rate structure to more accurately reflect the actual cost of providing service to business customers;

	•		Continued application of an adjustment mechanism to enable the Company to address the costs associated with retail electric customers migrating to and from Detroit Edison’s full service retail electric tariff service;

	•		Application of an uncollectible expense true-up mechanism based on the $87 million expense level of uncollectible expenses that occurred during the 12 month period ended June 2008;

	•		Continued application of the storm restoration expense recovery mechanism and modification to the line clearance expense recovery mechanism; and

	•		Implementation of a revenue decoupling mechanism.

The October 2008 Michigan legislation establishes a twelve month deadline for the MPSC to complete a rate case and allows a utility to self-implement rate changes six months after a rate filing if the MPSC has not issued a rate order and subject to certain limitations.

Cost-Based Tariffs for Schools

In January 2009, Detroit Edison filed a required application that included two new cost-based tariffs for schools, universities and community colleges. The filing is in compliance with Public Act 286 which required utilities to file tariffs that ensure that eligible educational institutions are charged retail electric rates that reflect the actual cost of providing service to those customers. In February 2009, an MPSC order consolidated this proceeding with the January 26, 2009 electric rate case filing.

Renewable Energy Plan

In March 2009, Detroit Edison filed its Renewable Energy Plan with the MPSC as required under 2008 PA 295. The Renewable Energy Plan application requests authority to recover approximately $35 million of additional revenue in 2009. The proposed revenue increase is necessary in order to properly implement Detroit Edison’s 20-year renewable energy plan to achieve compliance with 2008 PA 295, to deliver new, cleaner, renewable electric generation demanded by customers, to further diversify Detroit Edison’s and Michigan’s sources of electric supply, and to further Michigan’s and the United States’ goal of increasing energy independence. The Company expects an order in the proceeding in June 2009, with customer surcharges beginning in September 2009.

Energy Optimization Plans

In March 2009, Detroit Edison and MichCon filed Energy Optimization Plans with the MPSC as required under 2008 PA 295. The Energy Optimization Plan applications are designed to help each customer class reduce their electric and gas usage by: (1) building customer awareness of energy efficiency options and (2) offering a diverse set of programs and participation options that result in energy savings for each customer class. Detroit Edison’s Energy Optimization Plan application proposes energy optimization expenditures for the period 2009-2011 of $134 million and further requests approval of surcharges that are designed to recover these costs. MichCon’s Energy Optimization Plan application proposes energy optimization expenditures for the period 2009-2011 of $55 million and further requests approval of surcharges that are designed to recover these costs. The Company expects orders in these proceedings in June 2009 with customer surcharges beginning in June 2009.

Power Supply Cost Recovery Proceedings

2008 Plan Year — In September 2007, Detroit Edison filed its 2008 PSCR plan case seeking approval of a levelized PSCR factor of 9.23 mills/kWh above the amount included in base rates for all PSCR customers. Also included in the filing was a request for approval of the Company’s emission compliance strategy which included pre-purchases of emission allowances as well as a request for pre-approval of a contract for capacity and energy associated with a renewable (wind) energy project. On January 31, 2008, Detroit Edison filed a revised PSCR plan case seeking approval of a levelized PSCR factor of 11.22 mills/kWh above the amount included in base rates for all PSCR customers. The revised filing supports a 2008 power supply expense forecast of $1.4 billion and includes $43 million for the recovery of a projected 2007 PSCR under-collection. On July 29, 2008, the MPSC issued a temporary order approving Detroit Edison’s request to increase the PSCR factor to 11.22 mills/kWh. In January 2009, the MPSC approved the Company’s 2008 PSCR plan and authorized the Company to charge a maximum PSCR factor of 11.22 mills/kWh for 2008. The Company filed its 2008 PSCR reconciliation case in March 2009. The filing requests recovery of a $19 million PSCR under-collection. In addition, the filing requests authorization to refund its total 2005 PSCR under-collection surcharge at year-end 2008 of $10 million, including interest, to all commercial and industrial customers. Included in the 2008 PSCR reconciliation filing was the Company’s 2008 pension expense mechanism reconciliation that reflects a $50 million over-collection.

2009 Plan Year — In September 2008, Detroit Edison filed its 2009 PSCR plan case seeking approval of a levelized PSCR factor of 17.67 mills/kWh above the amount included in base rates for residential customers and a levelized PSCR factor of 17.29 mills/kWh above the amount included in base rates for commercial and industrial customers. The Company is supporting a total power supply expense forecast of $1.73 billion. The plan also includes approximately $69 million for the recovery of its projected 2008 PSCR under-collection from all customers and approximately $12 million for the refund of its 2005 PSCR reconciliation surcharge over-collection to commercial and industrial customers only. Also included in the filing is a request for approval of the Company’s expense associated with the use of urea in the selective catalytic reduction units at Monroe power plant as well as a request

for approval of a contract for capacity and energy associated with a renewable (wind) energy project. The Company’s PSCR Plan will allow the Company to recover its reasonably and prudently incurred power supply expense including, fuel costs, purchased and net interchange power costs, nitrogen oxide and sulfur dioxide emission allowance costs, transmission costs and MISO costs. The Company self-implemented a PSCR factor of 11.64 mills/kWh above the amount included in base rates for residential customers and a PSCR factor of 11.22 mills/kWh above the amount included in base rates for commercial and industrial customers on bills rendered in January 2009. Subsequently, as a result of the December 23, 2008 MPSC order in the 2007 Detroit Edison Rate case, the Company implemented a PSCR factor of 3.18 mills/kWh below the amount included in base rates for residential customers and a PSCR factor of 3.60 mills/kWh below the amount included in base rates for commercial and industrial customers for bills rendered effective January 14, 2009.

Uncollectible Expense True-Up Mechanism (UETM) and Report of Safety and Training-Related Expenditures

2007 UETM — In March 2008, MichCon filed an application with the MPSC for approval of its UETM for 2007 requesting approximately $34 million consisting of $33 million of costs related to 2007 uncollectible expense and associated carrying charges and $1 million of under-collections for the 2005 UETM. The March 2008 application included a report of MichCon’s 2007 annual safety and training-related expenses, which showed no refund was necessary because actual expenditures exceeded the amount included in base rates. An MPSC order was issued in December 2008 approving the collection of $34 million requested in the March 2008 filing. MichCon was authorized to implement the new UETM monthly surcharge for service rendered on and after January 1, 2009.

2008 UETM — In March 2009, MichCon filed an application with the MPSC for approval of its UETM for 2008 requesting approximately $87 million consisting of $83 million of costs related to 2008 uncollectible expense and associated carrying charges and $4 million of under-collections for the 2006 UETM. The March 2009 application included a report of MichCon’s 2008 annual safety and training-related expenses, which showed no refund was necessary because actual expenditures exceeded the amount included in base rates. An order is expected in this case in the fourth quarter of 2009.

Gas Cost Recovery Proceedings

2009-2010 Plan Year — In December 2008, MichCon filed its GCR plan case for the 2009-2010 GCR Plan year. MichCon filed for a maximum GCR factor of $8.46 per Mcf, adjustable by a contingent mechanism. In April 2009, MichCon, MPSC Staff and Intervenors filed a partial settlement agreement in the case establishing the fixed price purchase guidelines MichCon filed in its case were reasonable and prudent for MichCon to use until an MPSC order was issued establishing otherwise. An MPSC order in this case is expected in 2009.

2009 Proposed Base Gas Sale — In July 2008, MichCon filed an application with the MPSC requesting permission to sell an additional 4 Bcf of base gas that will become available for sale as a result of better than expected operations at its storage fields. In February 2009, a settlement agreement was filed with the MPSC, which will allow MichCon to sell and retain the profits of 2 Bcf of base gas, with the remaining 2 Bcf to be used for the benefit of GCR/GCC customers as colder-than-normal weather protection. The settlement also included a provision that MichCon is subject to moratorium on a general rate case filing until June 2009. An MPSC order was issued March 5, 2009 approving the settlement.

Other

In July 2007, the State of Michigan Court of Appeals published its decision with respect to an appeal by Detroit Edison and others of certain provisions of a November 2004 MPSC order, including reversing the MPSC’s denial of recovery of merger control premium costs. In its published decision, the Court of Appeals held that Detroit Edison is entitled to recover its allocated share of the merger control premium and remanded this matter to the MPSC for further proceedings to establish the precise amount and timing of this recovery. Detroit Edison has filed a supplement to its April 2007 rate case to address the recovery of the merger control premium costs. In September 2007, the Court of Appeals remanded to the MPSC, for reconsideration, the MichCon recovery of merger control premium costs. Other parties filed requests for leave to appeal to the Michigan Supreme Court from the Court of Appeals decision and in September 2008, the Michigan Supreme Court granted the requests to address the merger

control premium as well as the recovery of transmission costs through the PSCR. On May 1, 2009, the Michigan Supreme Court issued an order reversing the Court of Appeals decision with respect to recovery of the merger control premium, and reinstated the MPSC’s decision excluding the control premium costs from Detroit Edison’s general rates. The Court affirmed the lower court’s decision upholding the right of Detroit Edison to recover electric transmission costs through the Company’s PSCR clause.

The Company is 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 6 — COMMON STOCK AND EARNINGS PER SHARE

The Company reports both basic and diluted earnings per share. The calculation of diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period from the exercise of stock options. Effective January 1, 2009, the Company adopted FSP EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities. The adoption of this FSP had the effect of reducing previously reported 2008 amounts for basic and diluted earnings per share by $.01. A reconciliation of both calculations is presented in the following table as of March 31:


(in Millions, except per share amounts)	2009		2008
Basic Earnings per Common Share
Net income attributable to DTE Energy	$	178	$	212


Average number of common shares outstanding		163		163

Weighted average net restricted shares outstanding		1		1


Dividends paid to common shares	$	86	$	86
Dividends paid to net restricted shares		—		—

Total distributed earnings	$	86	$	86

Total undistributed earnings	$	92	$	126


Distributed (dividends per common share)	$	.53	$	.53
Undistributed		.56		.77

Total Basic Earnings per Common Share	$	1.09	$	1.30


Diluted Earnings per Common Share
Net income attributable to DTE Energy	$	178	$	212


Average number of common shares outstanding		163		162
Average incremental shares from assumed exercise of options		—		—

Common shares for dilutive calculation		163		163

Weighted average net restricted shares outstanding		1		1


Dividends paid to common shares	$	86	$	86
Dividends paid to net restricted shares		—		—

Total distributed earnings	$	86	$	86

Total undistributed earnings	$	92	$	126


Distributed (dividends per common share)	$	.53	$	.53
Undistributed		.56		.76

Total Diluted Earnings per Common Share	$	1.09	$	1.29

Options to purchase approximately 4 million and 3 million shares of common stock as of March 31, 2009 and 2008, respectively, were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares, thus making these options anti-dilutive.

NOTE 7 — LONG-TERM DEBT

Debt Issuances

In 2009, the Company has issued or remarketed the following long-term debt:

(in Millions)


Company	Month Issued	Type	Interest Rate			Maturity		Amount

Detroit Edison	April	Tax-Exempt Revenue bonds (1)(2)		6.00	%		2036	$	69

								$	69


(1)		Detroit Edison Tax-Exempt Revenue Bonds are issued by a public body that loans the proceeds to Detroit Edison on terms substantially mirroring the Revenue Bonds.

(2)		Proceeds were used to refund existing Tax-Exempt Revenue Bonds.

Debt Retirements and Redemptions

In 2009, the following debt has been retired, through optional redemption or payment at maturity:

(in Millions)

Company

Month Retired

Type

Interest Rate

Maturity

Amount

Detroit Edison

April

Tax-Exempt Revenue bonds (1)

Variable

2036

DTE Energy

April

Senior Notes

6.65%

2009

200

269


(1)		These Tax-Exempt Revenue Bonds were redeemed with the proceeds from the issuance of new Detroit Edison Tax-Exempt Revenue Bonds.

NOTE 8 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

DTE Energy and its wholly-owned subsidiaries, Detroit Edison and MichCon, have entered into revolving credit facilities with similar terms. The five-year credit facilities are with a syndicate of banks and may be used for general corporate borrowings, but are intended to provide liquidity support for each of the companies’ commercial paper programs. Borrowings under the facilities are available at prevailing short-term interest rates. Additionally, DTE Energy, Detroit Edison and MichCon had various other bank loans and facilities. The above agreements require the Company to maintain a debt to total capitalization ratio of no more than 0.65 to 1. DTE Energy, Detroit Edison and MichCon are in compliance with this financial covenant. The availability under these combined facilities at March 31, 2009 is shown in the following table:


(in Millions)	DTE Energy		Detroit Edison		MichCon		Total
Five-year unsecured revolving facility, expiring October 2010	$	675	$	69	$	181	$	925
Five-year unsecured revolving facility, expiring October 2009		525		206		244		975
Unsecured bank loan facility, expiring June 2009		—		75		—		75
Unsecured bank loan facility, expiring July 2009		—		—		50		50
Secured floating rate note, maturing September 2009		—		—		20		20
One-year unsecured letter of credit facility, expiring in November 2009		30		—		—		30

Total credit facilities at March 31, 2009		1,230		350		495		2,075


(in Millions)	DTE Energy		Detroit Edison		MichCon		Total
Amounts outstanding at March 31, 2009:
Commercial paper issuances		75		—		110		185
Borrowings		—		75		70		145
Letters of credit		332		—		—		332

		407		75		180		662

Net availability at March 31, 2009	$	823	$	275	$	315	$	1,413

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $16 million which are used for various corporate purposes.

In April 2009, the Company completed an early renewal of $975 million of its syndicated revolving credit facilities before their scheduled expiration in October 2009. The new $1 billion two-year facility will expire in April 2011 and has similar covenants to the prior facility. A new two-year $50 million credit facility was completed in April 2009.

In conjunction with maintaining certain exchange traded risk management positions, the Company may be required to post cash collateral with its clearing agent. The Company has a demand financing agreement for up to $50 million with its clearing agent. The amount outstanding under this agreement was $41 million and $26 million at March 31, 2009 and December 31, 2008, respectively.

NOTE 9 — 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. Since 2005, EPA and the State of Michigan 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 $1.4 billion through 2008. The Company estimates Detroit Edison’s future undiscounted capital expenditures at up to approximately $100 million in 2009 and up to approximately $2.3 billion of additional capital expenditures through 2019 based on current regulations.

Water — In response to an EPA regulation, 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 water intakes. Initially, it was estimated that Detroit Edison could incur up to approximately $55 million over the four to six years subsequent to 2008 in additional capital expenditures to comply with these requirements. However, a January 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation that may result in a delay in compliance dates. The decision also raised the possibility that Detroit Edison may have to install cooling towers at some facilities at a cost substantially greater than was initially estimated for other mitigative technologies. In 2008, the Supreme Court agreed to review the remanded cost-benefit analysis provision of the rule. In April 2009, the Supreme Court ruled that a cost-benefit analysis is a permissible provision of the rule. Concurrently, the EPA continues to develop a revised rule, which is expected to be published later in 2009.

Contaminated Sites — Detroit Edison conducted remedial investigations at contaminated sites, including three 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 expected to be incurred over the next several years. At March 31, 2009 and December 31, 2008, the Company had $11 million and $12 million, respectively, accrued for remediation.

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, the Company is also in the process of cleaning up other contaminated sites. Cleanup activities associated with these sites will be conducted over the next several years.

The MPSC has established a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites. Accordingly, Gas Utility recognizes a liability and corresponding regulatory asset for estimated investigation and remediation costs at former MGP sites. As of March 31, 2009 and December 31, 2008, the Company had approximately $36 million and $38 million, respectively, accrued for remediation.

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, the Company anticipates 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.

Non-Utility

The Company’s non-utility affiliates are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants. The Company is in the process of installing new environmental equipment at our coke battery facility in Michigan. The Company expects the projects to be completed by the first half of 2009. The Michigan coke battery facility received and responded to information requests from the EPA resulting in the issuance of a notice of violation regarding potential maximum achievable control technologies and new source review violations. The EPA is in the process of reviewing the Company’s position of demonstrated compliance and has not initiated escalated enforcement. At this time, the Company cannot predict the impact of this issue. Furthermore, the Company is in the process of settling historical air violations at its coke battery facility located in Pennsylvania. At this time, the Company cannot predict the impact of this settlement. The Company is investigating wastewater treatment technologies for the coke battery facility located in Pennsylvania. This investigation may result in capital expenditures to meet regulatory requirements. The Company’s non-utility affiliates are substantially in compliance with all environmental requirements, other than as noted above.

Guarantees

In certain limited circumstances, the Company enters into contractual guarantees. The Company may guarantee another entity’s obligation in the event it fails to perform. The Company may provide guarantees in certain indemnification agreements. Finally, the Company may provide indirect guarantees for the indebtedness of others. Below are the details of specific material guarantees the Company currently provides.

Millennium Pipeline Project Guarantee

The Company owns a 26 percent equity interest in the Millennium Pipeline Project (Millennium). Millennium is accounted for under the equity method. Millennium began commercial operations in December 2008.

On August 29, 2007, Millennium entered into a borrowing facility to finance the construction costs of the project. The total facility amounts to $800 million and is guaranteed by the project partners, based upon their respective ownership percentages. The facility expires on August 29, 2010 and was fully drawn as of March 31, 2009.

The Company has agreed to guarantee 26 percent of the borrowing facility and in the event of default by Millennium the maximum potential amount of future payments under this guarantee is approximately $210 million. The guarantee includes DTE Energy’s revolving credit facility’s covenant and default provisions by reference. Related to this facility, the Company has also agreed to guarantee 26 percent of Millennium’s forward-starting interest rate swaps with a notional amount of $420 million. The Company’s exposure on the forward-starting interest rate swaps varies with changes in Treasury rates and credit swap spreads and was approximately $22 million at March 31, 2009. Because

the Company is unable to accurately anticipate changes in Treasury rates and credit swap spreads, it is unable to estimate its maximum exposure under its share of Millennium’s forward-starting interest rate swaps. An incremental 0.25 percent decrease in the forward interest rate swap rates will increase its exposure by approximately $4 million. There are no recourse provisions or collateral that would enable the Company to recover any amounts paid under the guarantees, other than its share of project assets.

Other Guarantees

In January 2003, the Company sold the steam heating business of Detroit Edison to Thermal Ventures II, LP. Under the terms of sale, Detroit Edison guaranteed bank loans of $13 million that Thermal Ventures II, LP used for capital improvements to the steam heating system. At March 31, 2009, the Company had reserves of $13 million related to the bank loan guarantee.

The Company’s other guarantees are not individually material with maximum potential payments totaling $10 million at March 31, 2009.

The Company is periodically required to obtain performance surety bonds in support of obligations to various governmental entities and other companies in connection with its operations. As of March 31, 2009, the Company had approximately $12 million of performance bonds outstanding. In the event that such bonds are called for nonperformance, the Company would be obligated to reimburse the issuer of the performance bond. The Company is released from the performance bonds as the contractual performance is completed and does not believe that a material amount of any currently outstanding performance bonds will be called.

Labor Contracts

There are several bargaining units for our union employees. The majority of our union employees are under contracts that expire in October 2010.

Purchase Commitments

Detroit Edison has an Energy Purchase Agreement to purchase electricity from the Greater Detroit Resource Recovery Authority (GDRRA). The term of the Energy Purchase Agreement for the purchase of electricity runs through June 2024. The Company estimates electric purchase commitments from 2009 through 2024 will not exceed $300 million in the aggregate.

As of March 31, 2009, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments and energy trading contracts. The Company estimates that these commitments will be approximately $5.9 billion from 2009 through 2051. The Company also estimates that 2009 capital expenditures will be approximately $1.1 billion. The Company has made certain commitments in connection with expected capital expenditures.

Bankruptcies

The Company purchases and sells electricity, gas, coal, coke and other energy products from and to numerous companies operating in the steel, automotive, energy, retail, financial and other industries. Certain of its customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. The Company regularly reviews contingent matters relating to these customers and its purchase and sale contracts and records provisions for amounts considered at risk of probable loss. The Company believes its previously accrued amounts are adequate for probable loss. The final resolution of these matters may have a material effect on its consolidated financial statements.

The Company’s utilities and certain non-utility businesses provide services to the domestic automotive industry, including General Motors Corporation (GM), Ford Motor Company (Ford) and Chrysler LLC (Chrysler) and many of their vendors and suppliers. GM and Chrysler have received loans from the U.S. Government to provide them with the working capital necessary to continue to operate in the short term. Chrysler filed for bankruptcy protection

on April 30, 2009. We will fully reserve invoiced and unbilled accounts receivable outstanding as of the date of filing of approximately $10 million. In the event of a bankruptcy filing by GM, the Company will fully reserve invoiced and unbilled accounts receivable. Based on average monthly revenues and typical billing and payment cycles, the Company estimates that it may have pre-petition accounts receivable at risk of approximately $30 million for GM. The actual amounts to be reserved will be dependent on the timing of the bankruptcy filing within the billing cycle and whether any amounts are past due. Currently, GM has been paying amounts owed in a timely manner and its account is substantially current. Closing of GM or Chrysler plants or other facilities that operate within Detroit Edison’s service territory will also negatively impact the Company’s operating revenues in future periods. In 2008, GM and Chrysler represented 3 percent and 2 percent of its annual electric sales volumes, respectively. GM and Chrysler have an immaterial impact to MichCon’s revenues.

The Company’s Power and Industrial Projects segment has long-term contracts with GM to provide onsite energy services at certain of its manufacturing and administrative facilities. The long-term contracts provide for full recovery of its investment in the event of early termination. At March 31, 2009, the book value of long-lived assets used in the servicing of these facilities was approximately $76 million. Certain of these long-lived assets have been funded by non-recourse financing totaling approximately $58 million at March 31, 2009. As of December 31, 2008, the Company performed an impairment analysis on these assets in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Based on its undiscounted cash flow projections, the Company determined that it did not have an impairment at December 31, 2008. In the first quarter 2009, the Company reviewed the assumptions used in its impairment analysis and has concluded that it did not have a trigger to reassess for impairment as of March 31, 2009. The Company’s assumptions and conclusions may change and it could have impairment losses if any of the facilities that it services are closed and/or the terms of the contracts are not honored by GM or the contracts are rejected through the bankruptcy process.

The Company’s Power and Industrial Projects segment also has an equity investment of approximately $52 million in an entity which provides on-site services to Chrysler manufacturing facilities. Chrysler’s performance under the long-term contracts for services is guaranteed by Daimler North America Corporation (Daimler), a subsidiary of Daimler AG. The long-term contracts and the supporting Daimler guarantee provide for full recovery of the Company’s investment in the event of early termination or default. The Company believes that it will recover its investment in the event of facility closures, a Chrysler default or if the long-term contracts are rejected through the bankruptcy process.

Other Contingencies

The Company is 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, additional environmental reviews and investigations, audits, inquiries from various regulators, and pending judicial matters. The Company cannot predict the final disposition of such proceedings. The Company regularly reviews legal matters and records provisions for claims it can estimate and are considered probable of loss. The resolution of these pending proceedings is not expected to have a material effect on the Company’s operations or financial statements in the periods they are resolved.

See Note 3 and 5 for a discussion of contingencies related to derivatives and regulatory matters.

NOTE 10 — SEGMENT INFORMATION

The Company sets strategic goals, allocates resources and evaluates performance based on the following structure:

Electric Utility

•

The Company’s Electric Utility segment consists of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.2 million residential, commercial and industrial customers in southeastern Michigan.

Gas Utility

•

The Gas Utility segment consists of MichCon and Citizens. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.2 million residential, commercial and industrial customers throughout Michigan. MichCon also has subsidiaries involved in the gathering, processing and transmission of natural gas in northern Michigan. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.

Non-Utility Operations

	•		Gas Midstream consists of gas pipelines and storage businesses;

	•		Unconventional Gas Production is engaged in unconventional gas project development and production;

	•		Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers, biomass energy projects and coal transportation and marketing; and

	•		Energy Trading primarily consists of energy marketing and trading operations.

Corporate & Other, includes various holding company activities, holds certain non-utility debt and energy-related investments.

The income tax provisions or benefits of DTE Energy’s subsidiaries are determined on an individual company basis and recognize the tax benefit of production tax credits and net operating losses. The subsidiaries record income tax payable to or receivable from DTE Energy resulting from the inclusion of its taxable income or loss in DTE Energy’s consolidated federal tax return.

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 following segments:


	Three Months Ended
	March 31
(in Millions)	2009			2008
Electric Utility	$	6		$	4
Gas Utility		1			—
Gas Midstream		2			3
Power and Industrial Projects		4			6
Energy Trading		32			32
Corporate & Other		(23	)		(25	)

	$	22		$	20

Financial data of the business segments follows:


	Three Months Ended
	March 31
(in Millions)	2009			2008
Operating Revenues
Electric Utility	$	1,118		$	1,153
Gas Utility		771			915
Non-utility Operations:
Gas Midstream		22			17
Unconventional Gas Production		7			10
Power and Industrial Projects		155			216
Energy Trading		204			288

		388			531


Corporate & Other		—			(9	)
Reconciliation & Eliminations		(22	)		(20	)

Total From Continuing Operations	$	2,255		$	2,570


Net Income (Loss) by Segment:
Electric Utility	$	78		$	41
Gas Utility		61			59
Non-utility Operations:
Gas Midstream		14			8
Unconventional Gas Production (1)		(2	)		82
Power and Industrial Projects		4			10
Energy Trading		40			31

Corporate & Other		(17	)		(31	)

Income (Loss) from Continuing Operations
Utility		139			100
Non-utility		56			131
Corporate & Other		(17	)		(31	)

		178			200


Discontinued Operations (Note 4)		—			12

Net Income attributable to DTE Energy	$	178		$	212


(1)		Net income of the Unconventional Gas Production segment in 2008 reflects the gain on the sale of a portion of the Barnett shale properties.

Part II — Other Information

Item 1. — Legal Proceedings

We were aware of attempts by an individual named Scott Edwards, the Legal Director of Waterkeeper Alliance, to prosecute criminal charges in Canada against the Company for alleged violations of the Canadian Fisheries Act. The charges were filed on February 6, 2007. Although the Company believed the claims of Mr. Edwards in this matter were without legal merit, the fines under the relevant Canadian statute could have been significant if liability had been established. On April 28, 2009, the charges were withdrawn by Mr. Edwards and the prosecution has terminated.

EES Coke Battery, LLC (EES Coke), which is an indirect wholly owned subsidiary of the Company, has settled a suit that The City of Detroit Water and Sewer Department (DWSD) filed in the U.S. District Court for the Eastern District Court of Michigan alleging that certain constituents of waste water discharged by EES Coke into DWSD’s sewer system exceeded the permitted amounts. The Consent Order entered by the Court on March 12, 2009 requires EES Coke to pay fines for past exceedances and to reimburse DWSD for certain costs in an aggregate amount of $200,000. EES Coke has made certain capital improvements designed to prevent exceedances of the permitted amounts in the future.

Item 1A. — Risk Factors

In addition to the other information set forth in this report, the risk factors discussed in Part 1, Item 1A. Risk Factors in the Company’s 2008 Form 10-K, which could materially affect the Company’s businesses, financial condition, future operating results and/ or cash flows should be carefully considered. 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.

Item 2. — 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 Securities Exchange Act of 1934 during the three months ended March 31, 2009:


					Total Number of		Maximum Dollar
					Shares Purchased		Value that May Yet
	Total Number		Average		as Part of Publicly		Be Purchased Under
	of Shares		Price Paid		Announced Plans		the Plans or
Period	Purchased		Per Share		or Programs		Programs (1)
01/01/09 - 01/31/09		—	$	—		—	$	822,895,623
02/01/09 - 02/28/09		—	$	—		—	$	822,895,623
03/01/09 - 03/31/09		—	$	—		—	$	822,895,623

Total		—	$	—		—


(1)		In May 2007, the DTE Energy Board of Directors authorized the repurchase of up to $850 million of common stock through 2009. Through March 31, 2009, no repurchases of common stock were made under this authorization. This authorization provides management with flexibility to pursue share repurchases from time to time, and will depend on actual and future asset monetization, cash flows and investment opportunities.

Item 6. — Exhibits


Exhibit
Number		Description

Exhibits filed herewith:

12-42		Computation of Ratio of Earnings to Fixed Charges

31-49		Chief Executive Officer Section 302 Form 10-Q Certification

31-50		Chief Financial Officer Section 302 Form 10-Q Certification

Exhibits incorporated by reference:

4-254		Supplemental Indenture, dated as of March 15, 2009 to Mortgage and Deed of Trust dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as trustee (Exhibit 4-263 to Detroit Edison’s Form 10-Q for the quarter ended March 31, 2009). (2009 Series BT)

4-255		Twenty-Ninth Supplemental Indenture, dated as of March 15, 2009 to the Collateral Trust Indenture dated as of June 30, 1993 and between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as trustee (Exhibit 4-264 to Detroit Edison’s Form 10-Q for the quarter ended March 31, 2009). (2009 Series BT 6.00% Senior Notes due 2036)

10-73		Form of DTE Energy Company (DTE Energy) Two-Year Credit Agreement, dated as of April 29, 2009, by and among DTE Energy, the lenders party thereto, Citibank, N.A., as Administrative Agent, and Barclays Capital, The Bank of Nova Scotia and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.1 to Form 8-K dated April 29, 2009).

10-74		Form of The Detroit Edison Company (Detroit Edison) Two-Year Credit Agreement, dated as of April 29, 2009, by and among Detroit Edison, the lenders party thereto, Barclays Capital, as Administrative Agent, and Citibank, N.A., JPMorgan Chase Bank, N.A. and The Royal Bank of Scotland plc, as Co-Syndication Agents (Exhibit 10.1 to Form 8-K dated April 29, 2009).

10-75		Form of Michigan Consolidated Gas Company (MichCon) Two-Year Credit Agreement, dated as of April 29, 2009, by and among MichCon, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Barclays Capital, Citibank, N.A. and Bank of America, N.A., as Co-Syndication Agents (Exhibit 10.2 to Form 8-K dated April 29, 2009).

Exhibits furnished herewith:

32-49		Chief Executive Officer Section 906 Form 10-Q Certification

32-50		Chief Financial Officer Section 906 Form 10-Q Certification

SIGNATURE

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


	DTE ENERGY COMPANY (Registrant)
Date: May 5, 2009	/s/ PETER B. OLEKSIAK
	Peter B. Oleksiak
	Vice President and Controller and Chief Accounting Officer