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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

FOR ANNUAL REPORT AND TRANSITION REPORTS PURSUANT TO
SECTIONS 13 OR 15(d) OF THE SECURITIES EXCHANGE OF 1934

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

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

For the fiscal year ended December 31, 2004

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) 2000 2^nd Avenue, Detroit, Michigan (Address of principal executive offices)		38-3217752 (I.R.S. Employer Identification No.) 48226-1279 (Zip Code)

313-235-4000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered

Common Stock, without par value, with contingent preferred stock purchase rights		New York and Chicago Stock Exchanges

8.75% Equity Security Units 7.8% Trust Preferred Securities * 7.50% Trust Originated Preferred Securities**		New York Stock Exchange New York Stock Exchange New York Stock Exchange

* Issued by DTE Energy Trust I. DTE Energy fully and unconditionally guarantees the payments of all amounts due on these securities to the extent DTE Energy Trust I has funds available for payment of such distributions.

** Issued by DTE Energy Trust II. DTE Energy fully and unconditionally guarantees the payments of all amounts due on these securities to the extent DTE Energy Trust II has funds available for payment of such distributions.

Securities registered pursuant to Section 12(g) of the Act:

None

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Yes þ No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes þ No o

On June 30, 2004, the aggregate market value of the Registrant’s voting and non-voting common equity held by non-affiliates was approximately $7.0 billion (based on the New York Stock Exchange closing price on such date). There were 174,209,034 shares of common stock outstanding at January 31, 2005.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information in DTE Energy Company’s definitive Proxy Statement for its 2005 Annual Meeting of Common Shareholders to be held April 28, 2005, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, not later than 120 days after the end of the Registrant’s fiscal year covered by this report on Form 10-K, is incorporated herein by reference to Part III (Items 10, 11, 12, 13 and 14) of this Form 10-K.

Definitions


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

Company		DTE Energy Company and subsidiary companies

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

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

Distributed Generation		Electric energy produced at or close to the point of use, in contrast to central station generation that generally produces electricity at large power plants and transmits and distributes power over long distances. Distributed generation includes fuel cells, small gas turbine engines called micro- and mini-turbines, and other devices capable of producing up to two megawatts of power.

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

EPA		United States Environmental Protection Agency

FERC		Federal Energy Regulatory Commission

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

ITC		International Transmission Company (until February 28, 2003, a wholly owned subsidiary of DTE Energy Company)

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

MDEQ		Michigan Department of Environmental Quality

MPSC		Michigan Public Service Commission

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

NRC		Nuclear Regulatory Commission

PSCR		A power supply cost recovery mechanism authorized by the MPSC that allows Detroit Edison to recover through rates its fuel, fuel-related and purchased power expenses. The clause was suspended under Michigan’s restructuring legislation (signed into law June 5, 2000), which lowered and froze electric customer rates. The clause was reinstated by the MPSC effective January 1, 2004.

Section 29 tax credits		Tax credits as authorized under Section 29 of the Internal Revenue Code that are designed to stimulate investment in and development of alternate fuel sources. The amount of a Section 29 tax credit can vary each year as determined by the Internal Revenue Service (Note 13).


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

SFAS		Statement of Financial Accounting Standards

Stranded Costs		Costs incurred by utilities in order to serve customers in a regulated environment that absent special regulatory approval would not otherwise expect to be recoverable if customers switch to alternative energy suppliers.

Synfuels		The fuel produced through a process involving chemically modifying and binding particles of coal. Synfuels are used for power generation and coke production. Synfuel production generates Section 29 tax credits.

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 contemplated, projected, estimated or budgeted in such forward-looking statements. There are many factors that may impact forward-looking statements including, but not limited to, the following:

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

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

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

• nuclear regulations and operations associated with nuclear facilities;

• the higher price of oil and its impact on the value of Section 29 tax credits, and the ability to utilize and/or sell interests in facilities producing such credits;

• implementation of electric and gas Customer Choice programs;

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

• employee relations and the impact of collective bargaining agreements;

• unplanned outages;

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

• the timing and extent of changes in interest rates;

• the level of borrowings;

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

• effects of competition;

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

• contributions to earnings by non-utility businesses;

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

• the ability to recover costs through rate increases;

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

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

• changes in 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; and

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

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

Part I

Items 1. & 2. Business and Properties

General

In 1995, DTE Energy incorporated in the State of Michigan. Our utility operations consist primarily of Detroit Edison and MichCon. We also have numerous non-utility subsidiaries engaged in energy marketing and trading, energy services, and various other electricity, coal and gas related businesses. DTE Energy is an exempt holding company under the Public Utility Holding Company Act (PUHCA) of 1935, except Section 9(a)(2) that relates to the acquisition of securities of public utility companies and Section 33 that relates to the acquisition of foreign (non-U.S.) utility companies.

Detroit Edison is a Michigan corporation organized in 1903 and is a public utility subject to regulation by the Michigan Public Service Commission (MPSC) and the Federal Energy Regulatory Commission (FERC). Detroit Edison is engaged in the generation, purchase, distribution and sale of electricity to 2.1 million customers in southeastern Michigan.

MichCon is a Michigan corporation organized in 1898 and is a public utility subject to regulation by the MPSC. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to 1.2 million customers throughout Michigan.

In February 2003, we sold the International Transmission Company (ITC), a FERC regulated transmission company. See Note 3 for a further discussion of the ITC sale and its presentation as a discontinued operation.

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to such reports are available free of charge through the investor relations page of our website: www.dteenergy.com, as soon as reasonably practicable after they are filed with or furnished to the Securities and Exchange Commission (SEC). The information on our website is not, and shall not be deemed to be, a part of this Form 10-K or any other filing we make with the SEC. Our previously filed reports and statements are also available at the SEC’s website: www.sec.gov.

We have a code of ethics that applies to our chief executive officer and all senior financial officers, including our chief financial officer, controller, assistant controllers, treasurer and assistant treasurers. Our code of ethics is available in the corporate governance section of the investor relations webpage of our website located at www.dteenergy.com. Should we make changes in, or provide waivers from, the provisions of the code of ethics that the SEC requires us to disclose, we intend to disclose these events in the governance section of our investor relations website.

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

Corporate Structure

Through 2004, we operated our businesses through three strategic business units (Energy Resources, Energy Distribution and Energy Gas). Each business unit had utility and non-utility operations. The balance of our business consisted of Corporate & Other. See Note 16 — Segment and Related Information, for financial information by segment for the last three years. In 2005, we expect to realign our business

units to strengthen the Company’s focus on customer relationships and growth within our non-utility businesses. Based on this structure, we will set strategic goals, allocate resources and evaluate performance. Beginning with the first quarter of 2005, we expect to report our segment information based on a new structure as described in Note 1. A discussion of each business unit based on the structure in effect over the past three years follows.

(CORPORATE STRUCTURE FLOW CHART)

ENERGY RESOURCES

Utility – Power Generation

Description

Power Generation comprises our utility power generation business and plants within Detroit Edison. These plants are regulated by numerous federal and state governmental agencies, including the MPSC, the FERC, the NRC, the EPA and the MDEQ. Electricity is generated from Detroit Edison’s numerous fossil plants, its hydroelectric pumped storage plant and its nuclear plant, and is purchased from electricity generators, suppliers and wholesalers. The electricity we produce and purchase is sold to four major classes of customers: residential, commercial, industrial and wholesale, principally throughout Michigan, the Midwest and Ontario, Canada.

Weather, economic factors and electricity prices affect sales levels to customers. Our peak load and highest total system sales generally occur during the third quarter of the year, driven by air conditioning and other cooling-related demands. Power generation sales are made to a diverse base of customers in both type and number; sales levels are not dependent on any small market segment. Customers who elect to purchase their electricity from alternative energy suppliers by participating in the electric Customer Choice program have an unfavorable effect on our financial performance.

Our power is generated from a variety of fuels and is supplemented with market purchases. The following table details our energy supply mix and average cost per unit:


	2004				2003				2002
(in Thousands of MWh)
Power Generated and Purchased
Power Plant Generation
Fossil		39,432	75	%		38,052	72	%		39,017	67	%
Nuclear (Fermi 2)		8,440	16			8,114	16			9,301	16

		47,872	91			46,166	88			48,318	83
Purchased Power		4,650	9			6,354	12			9,807	17

System Output		52,522	100	%		52,520	100	%		58,125	100	%


Average Unit Cost ($/MWh)

Generation (1)	$	12.98			$	12.89			$	12.53

Purchased Power (2)	$	37.06			$	41.73			$	39.16

Overall Average Unit Cost	$	15.11			$	16.38			$	17.02

(1) Represents fuel costs associated with power plants.

(2) Includes amounts associated with hedging activities.

We expect an adequate supply of fuel and purchased power to meet our obligation to serve customers. The effect of lost sales due to the electric Customer Choice program has reduced our need for purchased power and increased our ability to sell power in the wholesale market. We have short and long-term supply contracts for expected fuel and purchased power requirements as detailed in the following table:


	2005
Expected Supply	Contracted			Open
Coal		84	%		16	%
Natural Gas		26	%		74	%
Oil		20	%		80	%
Purchased Power		75	%		25	%

Power Generation’s generating capability is heavily dependent upon the availability of coal. Coal is purchased from various sources in different geographic areas under agreements that vary in both pricing and terms. Detroit Edison expects to obtain the majority of its coal requirements through long-term contracts with the balance to be obtained through short-term agreements and spot purchases. Detroit Edison has contracts with five coal suppliers and several over-the-counter brokers for a total purchase of up to 35 million tons of low-sulfur western coal to be delivered through 2008. Detroit Edison also has contracts with four suppliers for the purchase of approximately 6 million tons of Appalachian coal to be delivered through 2006. These existing long-term coal contracts either have fixed prices or include provisions for price escalation as well as de-escalation. Given the geographic diversity of supply, Detroit Edison believes it can meet the expected generation requirements. We own and lease a fleet of rail cars and have long-term transportation contracts with companies to provide rail and vessel services for delivery of purchased coal to our generating facilities.

We purchase power from other electricity generators, suppliers and wholesalers. These purchases supplement our generation capability to meet customer demand during peak cycles. For example, when high temperatures occur during the summer, we require additional electricity to meet demand. This access to additional power is an efficient and economical way to meet our obligation to customers without increasing capital expenditures to build additional power facilities.

Regulation

Detroit Edison’s Power Generation business is subject to the regulatory jurisdiction of various agencies, including the MPSC, the FERC and the NRC. The MPSC issues orders pertaining to rates, recovery of certain costs, including the costs of generating facilities and regulatory assets, conditions of service, accounting and operating-related matters. Detroit Edison’s MPSC-approved rates charged to customers have historically been designed to allow for the recovery of costs, plus an authorized rate of return on our investments. The FERC regulates Detroit Edison with respect to financing authorization and wholesale electric activities. The NRC has regulatory jurisdiction over all phases of the operation, construction, licensing and decommissioning of Detroit Edison’s Fermi 2 nuclear plant.

Since 1996 there have been several important acts, orders, court rulings and legislative actions in the State of Michigan that affect our Power Generation operations. In 1996, the MPSC began an initiative designed to give all of Michigan’s electric customers access to electricity supplied by other generators and marketers. In 1998, the MPSC authorized the electric Customer Choice program that allowed for a limited number of customers to purchase electricity from suppliers other than their local utility. The local utility would continue to transport the electric supply to the customers’ facilities, thereby retaining distribution margins. The electric Customer Choice program was phased in over a three-year period, with all customers having the option to choose their electric supplier by January 2002.

In 2000, the Michigan Legislature enacted legislation that reduced electric rates by 5% and reaffirmed January 2002 as the date for full implementation of the electric Customer Choice program. This legislation also contained provisions freezing rates through 2003 and preventing rate increases for small business customers through 2004 and for residential customers through 2005. The legislation and an MPSC order issued in 2001 established a methodology to enable Detroit Edison to recover stranded costs related to its generation operations that may not otherwise be recoverable due to electric Customer Choice related lost sales and margins. The legislation also provides for the recovery of the costs associated with the implementation of the electric Customer Choice program. The MPSC has determined that these costs will be treated as regulatory assets. Additionally, the legislation provides for recovery of costs incurred as a result of changes in taxes, laws and other governmental actions including the Clean Air Act.

In 2004, the MPSC issued interim and final rate orders that authorized electric rate increases totaling $374 million, and eliminated transition credits and implemented transition charges for electric Customer Choice customers. The increases were applicable to all customers not subject to a rate cap. The interim order affirmed the resumption of the Power Supply Cost Recovery (PSCR) mechanism for both capped and uncapped customers, which reduced PSCR revenues. The MPSC also authorized the recovery of approximately $385 million in regulatory assets, including stranded costs. The final order addressed numerous issues relating to regulatory assets, including the actual amounts recoverable and the recovery mechanism.

See Note 4 – Regulatory Matters for additional information regarding the 2004 rate orders and our regulatory environment.

Properties

Detroit Edison owns generating properties and facilities that are primarily located in the State of Michigan. Substantially all the net utility properties of Detroit Edison are subject to the lien of its mortgage. Power Generation plants owned and in service as of December 31, 2004 are as follows:


	Location by	Summer Net
	Michigan	Rated Capability (1) (2)
Plant Name	County	(MW)		(%)			Year in Service
Fossil-fueled Steam-Electric
Belle River (3)	St. Clair		1,026		9.3	%	1984 and 1985
Conners Creek	Wayne		215		1.9		1951
Greenwood	St. Clair		785		7.1		1979
Harbor Beach	Huron		103		0.9		1968
Marysville	St. Clair		84		0.7		1943 and 1947
Monroe (4)	Monroe		3,080		27.8		1971, 1973 and 1974
River Rouge	Wayne		510		4.6		1957 and 1958
St. Clair	St. Clair		1,415		12.8		1953, 1954, 1959, 1961 and 1969
Trenton Channel	Wayne		730		6.6		1949 and 1968

			7,948		71.7
Oil or Gas-fueled Peaking Units	Various		1,102		10.0		1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric Fermi 2 (5)	Monroe		1,111		10.0		1988
Hydroelectric Pumped Storage Ludington (6)	Mason		917		8.3		1973

			11,078		100.0	%

(1)	Summer net rated capabilities of generating units in service are based on periodic load tests and are changed depending on operating experience, the physical condition of units, environmental control limitations and customer requirements for steam, which otherwise would be used for electric generation.

(2)	Excludes one oil-fueled unit, St. Clair Unit No. 5 (250 MW), in cold standby status.

(3)	The Belle River capability represents Detroit Edison’s entitlement to 81.39% of the capacity and energy of the plant. See Note 6 — Jointly Owned Utility Plant.

(4)	The Monroe Power Plant provided 35% of Detroit Edison’s total 2004 power plant generation.

(5)	Fermi 2 has a design electrical rating (net) of 1,150 MW.

(6)	Represents Detroit Edison’s 49% interest in Ludington with a total capability of 1,872 MW. See Note 6.

Strategy and Competition

We strive to be the preferred electricity supplier in southeast Michigan. We believe that we can accomplish our goal by working with our customers, communities and regulatory agencies to be a reliable low cost supplier of electricity. To control expenses, we optimize our fuel blends thereby taking maximum advantage of low cost, environmentally friendly low-sulfur western coals. To ensure generation reliability, we will continue to make investments in our generating plants that will improve both plant availability and operating efficiencies. Revenues from year to year will vary due to weather conditions, economic factors, regulatory events and other risk factors as discussed in the “RISK FACTORS” section that follows.

Effective January 2002, the electric Customer Choice program expanded in Michigan whereby all of the Company’s electric customers can choose to purchase their electricity from alternative suppliers of generation services. Detroit Edison lost 18% of retail sales in 2004, 12% in 2003 and 5% of such sales in 2002 as a result of customers choosing to purchase power from alternative suppliers. Customers participating in the electric Customer Choice program consist primarily of industrial and commercial customers whose MPSC-authorized full service rates exceed the cost of service. We will continue to utilize the wholesale market to sell the generation made available by the electric Customer Choice program, in order to lower costs for full service customers.

Energy Services

Description

Energy Services has three business lines: Coal-Based Fuels, On-Site Energy Projects and Power Generation.

Coal-Based Fuels

Energy Services’ Coal-Based Fuels operations include producing synthetic fuel from nine synfuel plants and producing coke from three coke battery plants. The production of synfuel from all of the synfuel plants and the production of coke from one of the coke battery plants generate tax credits under Section 29 of the Internal Revenue Code. Section 29 is designed to stimulate investment in and development of alternate fuel sources. We have private letter rulings from the IRS for all of our synfuel plants. Synfuel-related Section 29 tax credits expire in 2007. Section 29 tax credits for two of our three coke batteries expired at the end of 2002 with the third expiring in 2007.

The synthetic fuel process involves chemically modifying and binding particles of coal to produce a fuel that is used for power generation and coke production. The modification involves a three-step process that produces a solid synthetic fuel product. Since 2002, we have sold majority interests in eight of our nine synfuel plants, representing approximately 92 percent of our total production capacity. We anticipate selling a majority interest in our remaining 100% owned synfuel plant in 2005. We continue to consolidate these projects due to our controlling influence.

The coke battery facilities produce coke that is used in blast furnaces within the steel industry. DTE Energy is one of the largest independent producers in the U.S. of coke for the steel industry.


(Dollars in Millions)	2004		2003		2002
Coal-Based Fuels – Tax Credits Generated
Synfuel Plants
Allocated to DTE Energy	$	29	$	228	$	180
Allocated to partners		411		146		66

	$	440	$	374	$	246


Coke Battery Plants:
Allocated to DTE Energy	$	2	$	3	$	57
Allocated to partners		—		—		35

	$	2	$	3	$	92

On-Site Energy Projects

Energy Services owns and/or operates on-site facilities, including pulverized coal injection, power generation, steam production, chilled water, wastewater treatment and compressed air. Many of these facilities deliver utility-type services to industrial, commercial and institutional customers. In 2004, we formed a utility services company that acquired utility-related assets from a large automotive company and entered into long-term agreements to provide utility and energy conservation services to the company. We then sold a 50% interest in the project to an unaffiliated partner. Also in 2004, we

purchased a 50% interest in a company that owns and operates a cogeneration facility serving a tissue mill located in Mobile, Alabama.

Power Generation – Non-Utility

Energy Services operates peaking and gas-fired electric generating plants. We have four electric generating plants in operation, all located in the Great Lakes region. In 2004, we sold two of the three units at our Georgetown plant. We have contracts for the sale of approximately 42% of the 2005 and 2006 output of the remaining units.

Properties

As of December 31, 2004, Coal-Based Fuels owns interests in and operates nine synfuel plants at eight production sites. Additionally, we have interests in three coke battery facilities in the United States, two of which we operate.

Coal-Based Fuels


Facility	Location	% Owned	Industry Served

Synthetic Fuels
DTE Red Mountain, LLC *	Tarrant, AL	1%	Foundry Coke/Steel
DTE Belews Creek, LLC	Belews Creek, NC	1%	Utility
DTE Utah Synfuels, LLC	Price, UT	1%	Industrial/Utility
DTE Indy Coke, LLC	Moundsville, WV	1%	Utility
DTE Clover, LLC	Bledsoe, KY	5%	Utility
DTE Smith Branch, LLC	Pineville, WV	1%	Steel/Export
DTE River Hill, LLC	Karthaus, PA	100%	Utility
DTE Buckeye, LLC (2 plants)	Cheshire, OH	1%	Utility
Coke Battery
EES Coke Battery Co.	River Rouge, MI	51%	Steel
Indiana Harbor Coke Co., LP	East Chicago, IN	5%	Steel
DTE Burns Harbor LLC	Burns Harbor, IN	51%	Steel

* Under the terms of a prior sale agreement, DTE Energy’s ownership interest increases to 51% in 2005.

The following are significant properties owned by On-Site Energy Projects:

On-Site Energy Projects


Facility	Location	% Owned	Type

PCI Enterprises	River Rouge, MI	100%	Pulverized Coal
DTE Sparrows Point	Sparrows Point, MD	100%	Pulverized Coal
DTE Northwind	Detroit, MI	100%	Steam & Chilled Water
DTE Moraine	Moraine, OH	100%	Compressed Air
DTE Tonawanda	Tonawanda, NY	100%	Chilled & Waste Water
Metro Energy	Romulus, MI	50%	Electricity, Hot and Chilled Water
Mobile Energy Services	Mobile, AL	50%	Electric Generation, Electric Distribution, and Steam
DTE Energy Center	Various sites in	50%	Electric Distribution, Chilled Water, Waste Water,
	MI, IN, OH		Lighting, Compressed Air, Mist & Dust Collectors

The Power Generation fleet consists of four natural gas-fired electric generating plants that are all located in the Great Lakes region.

Power Generation


					Capacity
Facility	Location	% Owned			(in MW)

DTE Georgetown	Indianapolis, IN		100	%		80
DTE River Rouge	River Rouge, MI		100	%		240
Crete Energy Ventures	Crete, IL		50	%		320
DTE East China	East China Twp, MI		100	%		320

						960

Strategy and Competition

Our strategy for Energy Services is to continue leveraging our extensive energy-related operating experience and project management capability to develop and grow the on-site energy business. We will continue to evaluate opportunities to sell a majority interest in our remaining synfuel plant in 2005. We also will continue to pursue opportunities to provide asset management and operations services to third parties.

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

We plan to focus on the following areas for growth:

•   Optimizing of our synfuel portfolio;

•   Providing operating services to owners of power plants;

•   Acquiring and developing solid fuel fired power plants;

•   Expanding on-site energy projects; and

•   Developing new tax advantaged opportunities.

Energy Marketing & Trading

Description

Energy Marketing & Trading consists of the wholesale electric and gas marketing and trading operations of DTE Energy Trading, Inc. and DTE-CoEnergy L.L.C. (CoEnergy). Energy Marketing & Trading focuses on physical power marketing and structured transactions for large customers, as well as the enhancement of returns from DTE Energy’s power plants, pipeline and storage assets. In pursuing these goals, Energy Marketing & Trading may enter into forwards, futures, swaps and option contracts.

Strategy and Competition

Our strategy for Energy Marketing & Trading is to deliver value-added services to our customers. We seek to manage this business in a manner consistent with and complementary to the growth of our other business segments. We plan to focus on physical marketing and the optimization of our portfolio of energy assets. We compete with electric and gas marketers, traders, utilities and other energy providers. We have risk management and credit processes to monitor and minimize risk.

Coal Services

Description

Coal Services provides fuel, transportation and equipment management services tailored to the individual requirements of each customer. We specialize in minimizing fuel costs and maximizing reliability of supply for energy-intensive customers. Our external customers include electric utilities, merchant power producers, integrated steel mills and large industrial companies with significant energy requirements. We also operate a number of railcar maintenance and repair facilities serving coal transporters, as well as other industries and rail car types. We participate in the trading of coal and emissions credits as well as coal-to-power tolling transactions. In 2003, we entered into the waste coal recovery business by purchasing a patented technology and constructing our first commercial facility.


Coal Services	2004		2003		2002
Tons of Coal Shipped (in Millions) *		39.9		32.0		28.5

* Includes intercompany transactions

Properties

We lease approximately 2,600 rail cars. We own fixed and mobile rail car maintenance and repair facilities in Nebraska and Indiana. We completed construction of a waste coal recovery facility on the site of a former operating coal mine in Ohio.

Strategy and Competition

We continue to leverage our position as one of the top North American coal marketers and our reputation as an efficient manager of transportation assets. Trends such as railroad and mining consolidation and the financial uncertainty of many mining firms could have an impact on how we compete in the future. 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.

We acquired the rights to a proprietary technology that produces high quality coal products from fine coal slurries that are typically discarded from coal mining operations (waste coal recovery). The technology has the additional benefit of improving the environment by allowing us to restore the land in accordance with reclamation requirements of each state. The technology produces a fine-coal fuel by removing mineral matter, clay-like impurities and oxides from waste material. The fine-coal fuel can be used in power plants, as a feedstock for synthetic fuel production and for other industrial applications. Our first facility in Ohio became operational in late-2003. We have experienced certain complications with our feedstock excavating process. We are working to resolve these complications and increase our production capacity to more than 500,000 tons of fine coal per year. We believe that the waste coal recovery business has the potential to contribute significantly to future earnings and provide significant environmental benefits.

Biomass

Description

Biomass develops, owns and operates landfill gas recovery systems in the U.S. Landfill gas, a byproduct of solid waste decomposition, is composed of approximately equal portions of methane and carbon dioxide. Converting the methane into a renewable energy resource conserves fossil fuels. Some Biomass operations generate Section 29 tax credits that will expire in 2007.

Biomass helps limit potential greenhouse gas emissions by developing and implementing landfill gas recovery systems that capture the gas and use it productively. Such a recovery system eliminates detrimental air emissions by preventing methane from escaping into the atmosphere or migrating off-site and becoming a safety hazard. Landfill gas recovery systems also provide local utilities, industry and consumers with an opportunity to use a competitive, renewable source of energy. Applications for this form of energy include steam and electricity generation, fueling of asphalt plants and brick kilns and for processing into pipeline quality gas. In 2004, Biomass entered into a joint venture with Coal Services to acquire facilities that produce coal mine methane gas.


(Dollars in Millions)
Biomass	2004		2003		2002
Landfill Sites		29		31		30
Gas Produced (in Bcf)		23.2		26.8		27.5
Tax Credits Generated*	$	7.7	$	10.5	$	12.9

*DTE Energy’s portion of total tax credits generated.

Properties

Biomass operates 29 sites located in 12 states and other projects are under development.

Strategy and Competition

Biomass’ strategy capitalizes upon our industry experience of over 20 years. We are evaluating business growth through both development and acquisitions. We compete primarily with fossil fuels such as natural gas and coal. However, we believe the environmental benefits of biomass along with reasonable and economic access to landfill sites provide a platform for future growth.

ENERGY DISTRIBUTION

Utility – Power Distribution

Description

The electric distribution services of Detroit Edison comprise our utility Power Distribution business. This business distributes electricity generated by Energy Resources’ Power Generation business and alternative energy suppliers to Detroit Edison’s 2.1 million customers in southeastern Michigan. This business also shares, with the Gas Distribution segment, the customer service and regulated marketing functions for our utilities. Accordingly, costs associated with these functions, including collections and customer service activities, are shared between Power Distribution and Gas Distribution.

In January 2003, we sold the steam heating business of Detroit Edison to Thermal Ventures II, LP. In February 2003, we sold ITC to an affiliate of Kohlberg, Kravis, Roberts & Co. and Trimaran Capital Partners, LLC. ITC will continue to provide transmission services to the Energy Distribution business at rates that will be recovered from Detroit Edison’s utility customers.

Weather and economic factors affect our sales and revenues. Similar to the Power Generation business, our peak load and highest total system sales generally occur during the third quarter of the year driven by air conditioning and other cooling-related demands. Power Distribution’s sales are not dependent upon a limited number of customers. Although customers participating in the electric Customer Choice program do not impact the total number of Power Distribution customers, they do impact operating revenues. Electric Choice customers currently pay a lower distribution rate than full service customers. Accordingly, customers participating in the electric Customer Choice program unfavorably affect revenues. Detroit Edison filed a

rate restructuring proposal in February 2005 to eliminate this intra class rate subsidy (Note 4). The loss of any one or a few customers is not reasonably likely to have a material adverse effect on Power Distribution.


(in thousands of MWh)	2004		2003		2002
Electric Deliveries
Residential		15,081		15,074		15,958
Commercial		13,425		15,942		18,395
Industrial		11,472		12,254		13,590
Wholesale		2,197		2,241		2,249
Other		401		402		403

		42,576		45,913		50,595
Electric Choice		9,245		6,193		2,967
Electric Choice – Self Generators*		595		1,088		543

Total Electric Deliveries		52,416		53,194		54,105

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

Regulation

Detroit Edison’s Power Distribution is subject to the jurisdiction of the MPSC, which has regulatory authority over rates, conditions of service and other operating-related matters. As previously discussed, Michigan legislation prevents Detroit Edison from increasing rates to residential customers through 2005 and prevented rate increases for small business customers through 2004.

In January 2004, the MPSC issued an order adopting rules governing service quality and reliability standards for electric distribution systems. The reliability standards establish performance levels for service restoration, wire-down relief requests, customer call answer time, customer complaint response, meter reading and new service installations. The order also establishes penalties for delays in service restoration during normal conditions, catastrophic storms and repetitive outages. Detroit Edison is required to file an annual report providing information regarding performance against the measures provided and any penalties incurred.

See Note 4 – Regulatory Matters for additional information regarding the 2004 rate orders and our regulatory environment.

Energy Assistance Programs

Energy assistance programs, funded by the federal government and the State of Michigan, remain critical to Detroit Edison’s ability to control its uncollectible accounts receivable and collections expenses.

Detroit Edison’s uncollectible accounts receivable expense is directly affected by the level of government funded assistance its qualifying customers receive. We are working with the State of Michigan and others to increase the share of funding allocated to our customers to be representative of the number of low-income individuals in our service territory.

Properties

Detroit Edison owns and operates 667 distribution substations with a capacity of approximately 31,381,500 kilovolt-amperes (kVA) and approximately 415,000 line transformers with a capacity of approximately 24,792,000 kVA. Substantially all of the net utility properties of Detroit Edison are subject to the lien of its mortgage. Circuit miles of distribution lines owned and in service as of December 31, 2004 are as follows:


Electric Distribution
	Circuit Miles
Operating Voltage-Kilovolts (kV)	Overhead		Underground
4.8 kV to 13.2 kV		28,060		12,929
24 kV		101		690
40 kV		2,322		326
120 kV		70		13

		30,553		13,958

There are numerous interconnections that allow the interchange of electricity between Detroit Edison and electricity providers external to our service area. These interconnections are generally owned and operated by ITC and connect to neighboring energy companies.

Strategy and Competition

Our strategy focuses on improving reliability, restoration time and the quality of customer service and lowering operating costs by improving operating efficiencies. We also are targeting capital investments in areas that have the greatest impact on reliability improvements with the goal of managing distribution rates charged to utility customers.

The decision to sell ITC was consistent with our strategic view that maximization of shareholder value and high levels of customer service are best achieved with assets that we own, operate and over which we exercise significant control. By FERC order, rates charged by ITC to Detroit Edison were frozen through December 2004. Thereafter, rates became subject to normal FERC regulation. With the MPSC’s November 2004 final rate order, transmission costs are recoverable through Detroit Edison’s PSCR mechanism.

Competition in the regulated electric distribution business is primarily from the on-site generation of industrial customers and from distributed generation applications by industrial and commercial customers. We do not expect significant competition for distribution to any group of customers in the near term.

Distributed Generation

Description

Distributed Generation, primarily consisting of DTE Energy Technologies (Dtech), invests in emerging technologies that complement our existing businesses. We currently have businesses that develop, assemble, market, distribute and service distributed generation products, provide application engineering, and monitor and manage system operations.

In 2004, Dtech revised its strategy to reduce the losses that occurred in the development phase of the business over the past four years. As a result, we closed most of our sales offices and created two regional selling offices, located in Southern California and in Michigan. These offices will concentrate on higher-margin sales. Additionally, Dtech’s organization was reduced and realigned to be more efficient.

Also in 2004, Dtech purchased the assets of the developer and assembler of its continuous duty products ranging from 75kW to 150kW.

The above changes, along with reduction of Dtech’s operating expenses, are expected to improve the financial performance of this business.

Strategy and Competition

Our goal is to become a profitable participant in the emerging distributed generation market, providing one-stop shopping that meets customers’ total energy needs. Our strategy is to increase focus on our proprietary pre-engineered and packaged continuous duty generation products.

Competition in the distributed generation business comes from distributors and manufacturers of stand-by and continuous duty generators. The success of this business depends on the continued development of new products, refinement of existing products, the expansion of customer acceptance of continuous duty distributed generation, and our ability to execute our plans.

ENERGY GAS

Utility – Gas Distribution

Description

Gas Distribution operations primarily consist of MichCon, our gas utility. Gas Distribution provides gas sales and transportation delivery services to 1.2 million residential, commercial and industrial customers located throughout Michigan.

Gas Distribution makes gas sales primarily to residential and small-volume commercial and industrial customers. It provides end user transportation to large-volume commercial and industrial customers and gas Customer Choice customers who purchase natural gas directly from other suppliers and utilize MichCon’s pipeline network to transport the gas to the customers’ facilities. Gas Distribution provides intermediate transportation to producers, brokers and other gas companies that own the natural gas transported, but are not the ultimate consumers. MichCon’s revenues and net income are impacted by weather and are concentrated in the first and fourth quarters of the year due to heating-related demand. MichCon’s operations are not dependent upon a limited number of customers, and the loss of any one or a few customers is not reasonably likely to have a material adverse effect on MichCon.

The following table details sales and deliveries to these customers.


(in Millions)	2004		2003		2002
Gas Revenues
Gas Sales	$	1,435	$	1,242	$	1,135
End-user Transportation		119		136		122
Intermediate Transportation		56		51		48
Other		72		69		64

	$	1,682	$	1,498	$	1,369

(in Bcf)
Gas Deliveries
Gas Sales		173		181		174
End-user Transportation		145		152		171
Intermediate Transportation		536		576		492

		854		909		837

We obtain our natural gas supply from various sources in different geographic areas under agreements that vary in both pricing and terms. Supply under contract represents approximately 58% of the expected 188 Bcf of supply requirements in 2005. We expect to meet the balance of gas supply requirements through open market purchases. We expect that 20% of our 2005 purchases will be under fixed-price contracts, with the remaining 80% acquired at prevailing market prices. As a result of varying demand primarily due to weather, MichCon may use existing gas in inventory to meet unanticipated customer obligations. Given the geographic diversity of supply, coupled with its 124 Bcf of storage capacity, MichCon believes it can meet the supply requirements for customers. MichCon has long-term firm transportation agreements expiring on various dates through 2011 for delivery of purchased natural gas to our distribution system.

Regulation

MichCon is subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to rates, recovery of certain costs, including the costs of regulatory assets, conditions of service, accounting and operating-related matters. MichCon is subject to the requirements of other regulatory agencies with respect to safety, the environment and health.

In the late 1990s, the MPSC began an initiative designed to give all of Michigan’s natural gas customers added choices and the opportunity to benefit from lower gas costs resulting from competition. In 1999, the MPSC approved a comprehensive experimental three-year gas Customer Choice program that allowed an increasing number of customers to purchase natural gas from suppliers other than their local utility. In December 2001, the MPSC issued an order that continued the gas Customer Choice program on a permanent and expanding basis. The permanent gas Customer Choice program was phased in over a three-year period, with all customers having the option to choose their gas supplier by April 2004. Since MichCon continues to transport and deliver the gas to the participating customer premises at prices comparable to margins earned on gas sales, customers switching to other suppliers have little impact on MichCon’s earnings.

Under the December 2001 MPSC order, MichCon returned to a gas cost recovery (GCR) mechanism, effective January 2002. Under this mechanism, MichCon’s gas sales rates include a gas commodity component designed to recover its actual gas costs and therefore does not have a commodity price risk for prudently incurred gas costs.

In September 2003, MichCon filed an application with the MPSC for an increase in service and distribution charges (base rates) for its gas sales and transportation customers. The filing requests an overall increase in base rates of $194 million per year (approximately 7% increase, inclusive of gas costs), beginning January 1, 2005. In September 2004, the MPSC issued an order granting interim rate relief of $35 million annually to MichCon. A final order is expected in the first quarter of 2005.

See Note 4 - Regulatory Matters, for additional information regarding the September 2004 interim rate order and our regulatory environment.

Energy Assistance Programs

Energy assistance programs funded by the federal government and the State of Michigan remain critical to MichCon’s ability to control its uncollectible accounts receivable expenses.

As previously discussed, we are working with the State of Michigan and others to increase the share of funding allocated to our customers to be representative of the number of low-income individuals in our service territory.

Properties

MichCon owns distribution, transmission and storage properties and facilities that are all located in the State of Michigan. At December 31, 2004, MichCon’s distribution system included approximately 18,000 miles of distribution mains, approximately 1,164,000 service lines and approximately 1,275,000 active meters. MichCon owns approximately 2,600 miles of transmission lines that deliver natural gas to the distribution districts and interconnect its storage fields with the sources of supply and the market areas. MichCon owns properties relating to four underground natural gas storage fields with an aggregate working gas storage capacity of approximately 124 Bcf. Substantially all of the net utility properties of MichCon are subject to the lien of its mortgage.

Strategy and Competition

The strategy of the Gas Distribution business is to expand our role as the preferred provider of natural gas in Michigan. As a result of more efficient furnaces and appliances, we expect future sales volumes to remain at current levels or slightly decline. To offset these factors, we plan to expand our gas markets and to continue providing energy-related services that capitalize on our expertise, capabilities and efficient systems.

Competition in the gas business primarily involves other natural gas providers, alternate fuels and energy sources. Natural gas continues to be the preferred space and water-heating fuel. Developers select natural gas in new construction because of the convenience, cleanliness and relative price advantage compared to propane, fuel oil and other alternative fuels.

Gas Production

Description

The Gas Production business is engaged in natural gas exploration, development and production. Gas Production owns one of the industry’s largest Antrim gas reserve bases predominantly located in the northern portion of the lower peninsula of Michigan. Our emphasis is on developing and producing the 335.4 Bcfe of proven reserves we owned as of December 31, 2004. We drilled 79 wells (67.3 net of interest of others) in 2004 with a success rate of 99%. Wells drilled in the Antrim shale have high success rates and low drilling costs, and are therefore considered low risk.

Gas Production is also involved in unconventional drilling opportunities outside of the State of Michigan that leverage our gas production capabilities and the skills and the experience of our other non-utility businesses. During 2004, Gas Production acquired 55,792 leasehold acres (48,857 net of interest of others) in the southern region of the Barnett shale in Texas, an area of increasing production. We currently have 7.9 Bcfe of proven reserves in the Barnett shale as of December 31, 2004. We began drilling 3 new wells (1.7 net of interest of others) in December 2004 and anticipate drilling additional wells, including test wells, in the first half of 2005. Initial results from the test wells are expected in mid-2005. If the results are successful, we could commit from $250 million to $500 million of capital over the next several years to develop these properties.

Properties

Gas Production owns interests in the following producing wells and acreage as of December 31.


	2004				2003				2002
	Gross		Net*		Gross		Net*		Gross		Net*
Producing Wells and Acreage
Producing Wells
Antrim shale		1,878		1,523		1,814		1,471		1,728		1,388
Barnett shale		5		1		—		—		—		—

		1,883		1,524		1,814		1,471		1,728		1,388


Developed Lease Acreage
Antrim shale		266,064		213,959		262,321		212,067		261,823		219,675
Barnett shale		1,262		316		—		—		—		—

		267,326		214,275		262,321		212,067		261,823		219,675


Undeveloped Lease Acreage
Antrim shale		92,328		79,025		94,866		81,133		86,050		69,977
Barnett shale		54,530		48,541		—		—		—		—

		146,858		127,566		94,866		81,133		86,050		69,977

* Excludes the interest of others.

The Antrim shale properties had 22.5 Bcfe of production in 2004. Gas Production expects to maintain its 335.4 Bcfe of proven reserves at December 31, 2004 by developing its acreage, thereby adding new reserves in low risk areas.

If Barnett shale test wells prove successful, Gas Production expects to substantially increase its proven reserves by investing a significant level of capital through 2008 to develop these properties.

Strategy

The Gas Production business is aggressively managing its Michigan gas producing assets to maximize returns on investment and increase earnings. We have operator responsibilities for our Michigan properties with the goal of optimizing the cost of producing reserves and adding additional reserves. During 2005, Gas Production plans to further develop and produce its Antrim shale acreage and wells.

In order to leverage our gas production capabilities and the skills and experience of other non-utility businesses, we plan to continue investing in unconventional drilling opportunities outside of Michigan such as the Barnett shale.

Gas Storage, Pipelines & Processing

Description

The Gas Storage, Pipelines & Processing business has partnership interests in an interstate transmission pipeline, Vector Pipeline (Vector), seven carbon dioxide processing facilities and a 9.7 Bcf natural gas storage field. Additionally, we lease through 2029 a 60.5 Bcf natural gas storage field located in Michigan.

Properties


Gas Storage,Pipelines & Processing
Property Classification	% Owned			Description	Location
Pipelines
Vector Pipeline		40	%	348-mile pipeline with 1,000 MMcf per day capacity	Midwest

Processing Plants		90	%	197 MMcf per day capacity	Northern Michigan

Storage
Washington 28		50	%	9.7 Bcf of storage capacity	Washington Twp, MI
Washington 10	Leased			60.5 Bcf of storage capacity	Washington Twp, MI

Strategy and Competition

Gas Storage, Pipelines & Processing focuses on opportunities in the Midwest-to-Northeast region that supply natural gas to meet growing demand. We expect much of the growth in the demand for natural gas in the U.S. to occur within the Mid-Atlantic and New England regions. These regions currently lack the pipeline capacity and gas storage necessary to deliver gas volumes to meet growing demand. Vector is an interstate pipeline that is filling a large portion of that need, and is complemented by Energy Gas’ significant storage capacity. Gas Storage, Pipelines & Processing has interests in seven processing plants that extract carbon dioxide from Antrim gas production making it suitable for transportation to nearby markets. Additionally, we have contract rights in natural gas storage fields, capable of storing up to 70.2 Bcf. We plan to continue identifying asset opportunities related to natural gas storage and transmission and working with other DTE Energy affiliates to secure the market required to support asset investment. One of those opportunities is Millennium Pipeline, which we have a 10.5% interest in. Upon securing market support, the Millennium Pipeline could be in-service in the 2006-2007 timeframe and would be able to transport up to 500 MMcf per day of gas originating from our Michigan storage facilities to the higher value markets in New York.

CORPORATE & OTHER

Description

Corporate & Other includes various corporate support functions such as accounting, legal and information technology. These functions essentially support the entire company and the related costs are fully allocated to the various segments based on services utilized. Additionally, Corporate & Other holds certain non-utility debt and investments in emerging energy technologies, including assets held for sale.

Strategy and Competition

Our energy technology venture fund strategy is to invest in a profitable portfolio of energy technology companies that facilitate the creation of new businesses, and expand growth opportunities for existing DTE Energy businesses. We seek to gain early experience in emerging energy sectors where energy trends and technologies may create potentially profitable opportunities. The investment portfolio consists of direct investments in energy technology companies and venture funds.

ENVIRONMENTAL MATTERS

We are subject to extensive environmental regulation. Additional costs may result as the effects of various chemicals on the environment are studied and governmental regulations are developed and implemented. We expect to continue recovering environmental costs related to utility operations through

rates charged to our customers. Greater details on environmental issues are provided in the following Notes to the Consolidated Financial Statements:


Note		Title

4		Regulatory Matters
5		Nuclear Operations
13		Commitments and Contingencies

Detroit Edison

Detroit Edison is subject to applicable permit requirements, and to potentially increased stringent federal, state and local standards covering, among other things, particulate and gaseous stack emission limitations, the discharge of wastewater into lakes and streams and the handling and disposal of waste material.

Air - The U.S. Environmental Protection Agency (EPA) has ozone transport and acid rain regulations and, in December 2003, proposed additional emission regulations relating to ozone, fine particulate and mercury air pollution. The new rules would lead to additional controls on fossil-fueled power plants to reduce nitrogen oxides, sulfur dioxide and mercury emissions. To comply with existing requirements, Detroit Edison has spent approximately $580 million through December 2004 and estimates that it will spend up to $100 million in 2005. Detroit Edison will incur from $700 million to $1.3 billion of additional future capital expenditures over the next five to eight years to satisfy both the existing and proposed new control requirements.

The EPA initiated enforcement actions against several major electric utilities citing violations of new source provisions of the Clean Air Act. Detroit Edison received and responded to information requests from the EPA on this subject. The EPA has not initiated proceedings against Detroit Edison. In October 2003, the EPA promulgated revised regulations to clarify new source review provisions going forward. Several states and environmental organizations have challenged these regulations and, in December 2003, the Court stayed the implementation of the regulations until the U.S. Court of Appeals D.C. Circuit renders an opinion in the case. We cannot predict the future impact of this issue upon Detroit Edison.

Water - Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of studies to be conducted over the next several years, Detroit Edison may be required to install additional control technologies to reduce the environmental impact of the intakes. Detroit Edison estimates that it will incur up to $50 million over the next five to seven years in additional capital expenditures to comply with these requirements.

Contaminated Sites - Detroit Edison conducted remedial investigations at contaminated sites, including two former manufactured gas plant (MGP) sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is approximately $8 million, which is expected to be incurred over the next several years. As a result of the investigation, Detroit Edison accrued an $8 million liability during 2004.

MichCon and Citizens

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. DTE Enterprises (MichCon and Citizens, a wholly owned gas utility located in Adrian, Michigan) owns, or previously owned, 18 such former MGP sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. Enterprises is remediating eight of the former MGP sites and conducting more extensive investigations at five other former MGP sites. Enterprises received Michigan Department of Environmental Quality (MDEQ) closure of one site and a determination that it is not a

responsible party for three other sites. Enterprises also received a closure from the EPA in 2002 for one site. While we cannot make any assurances, we believe that a cost deferral and rate recovery mechanism approved by the MPSC will prevent these costs from having a material adverse impact on our results of operations.

Other

Our non-utility affiliates are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants. Our non-utility affiliates are substantially in compliance with all environmental requirements.

Various state and federal laws regulate our handling, storage and disposal of waste materials. The EPA and the MDEQ have aggressive programs to manage the clean up of contaminated property. We have extensive land holdings and, from time to time, must investigate claims of improperly disposed contaminants. We anticipate our utility and non-utility companies may periodically be included in various types of environmental proceedings.

RISK FACTORS

There are various risks associated with the operations of DTE Energy’s utility and non-utility businesses. To provide a framework to understand the operating environment of DTE Energy, we are providing a brief explanation of the more significant risks associated with our businesses. Although we have tried to identify and discuss key risk factors, others could emerge in the future. Each of the following risks could affect our performance.

Michigan’s electric Customer Choice program is negatively impacting our financial performance. Even with the Customer Choice-related rate relief received in Detroit Edison’s 2004 rate orders, there continues to be considerable financial risk associated with the Customer Choice program. Choice migration is sensitive to market price, transition charges and electric bundled price increases.

Weather significantly affects our utility operations. Deviations from normal hot and cold weather conditions affect our earnings and cash flow. Mild temperatures can result in decreased utilization of our assets, lowering income and cash flow. Damage due to ice storms, tornadoes, or high winds can damage our infrastructure and require us to perform emergency repairs and incur material unplanned expenses. The expenses of storm restoration efforts may not be recoverable through the regulatory process.

Our electric utility continues to be negatively affected by competition. Deregulation and restructuring in the electric industry has resulted in increased competition and unrecovered costs that have affected and may continue to affect our financial condition, results of operations or cash flows. We are a regulated public utility, and this regulation has hindered our ability to retain customers in a competitive marketplace.

We are subject to rate regulation. We operate in a regulated industry. Our electric and gas rates are set by the MPSC and the FERC and cannot be increased without regulatory authorization. We may be impacted by new regulations or interpretations by the MPSC, the FERC or other regulatory bodies. New legislation, regulations or interpretations could change how our business operates, impact our ability to recover costs through rate increases or require us to incur additional expenses.

Our ability to utilize Section 29 tax credits may be limited. We have generated Section 29 tax credits from our synfuel, coke battery, biomass and gas production operations. We have received favorable private letter rulings on all of our synfuel facilities. All Section 29 tax credits taken after 1997 are subject to audit by the Internal Revenue Service (IRS). If our Section 29 tax credits were disallowed in whole or in part as a result of an IRS audit, there could be additional tax liabilities owed for previously recognized tax credits that could significantly impact our earnings and cash flows. The value of future credits

generated may be affected by new tax legislation. Moreover, Section 29 tax credits related to generation of synfuels expire at the end of 2007. The combination of overall industry audits of Section 29 tax credits, supply and demand for investment in credit producing activities and new tax legislation could have an impact on our earnings and cash flows. We have also provided certain guarantees and indemnities in conjunction with the sales of interests in our synfuel facilities.

In addition, the value of a Section 29 tax credit in a given year is reduced if the “Reference Price” of oil within the year exceeds a threshold price and is eliminated entirely if the Reference Price exceeds a phase-out price. The Reference Price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil, which in recent years has been $3 - $4 lower than the New York Mercantile Exchange (NYMEX) price for light, sweet crude oil.

Adverse changes in our credit ratings may negatively affect us. Increased scrutiny of the energy industry and regulatory changes, as well as changes in our economic performance could result in credit agencies reexamining our credit rating. A credit agency currently has a “negative outlook” on our ratings. While credit ratings reflect the opinions of the credit agencies issuing such ratings and may not necessarily reflect actual performance, a downgrade in our credit rating could restrict or discontinue our ability to access capital markets at attractive rates and increase our borrowing costs. In addition, a reduction in credit rating may require us to post collateral related to various trading contracts, which would impact our liquidity.

Regional and national economic conditions may unfavorably impact us. Our businesses follow the economic cycles of the customers we serve. Should national or regional economic conditions decline, reduced volumes of electricity and gas we supply will result in decreased earnings and cash flow. Economic conditions in our service territory also impact our collections of accounts receivable and financial results.

Environmental laws and liability may be costly. We are subject to numerous environmental regulations. These regulations govern air emissions, water quality, wastewater discharge, and disposal of solid and hazardous waste. Compliance with these regulations can significantly increase capital spending, operating expenses and plant down times. These laws and regulations require us to seek a variety of environmental licenses, permits, inspections and other regulatory approvals. We may also incur liabilities because of our emission of gases that may cause changes in the climate. The regulatory environment is subject to significant change and, therefore, we cannot predict future issues.

Additionally, we may become a responsible party for environmental clean up at sites identified by a regulatory body. We cannot predict with certainty the amount and timing of future expenditures related to environmental matters because of the difficulty of estimating clean up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

Since there can be no assurances that environmental costs may be recovered through the regulatory process, our financial performance may be negatively impacted as a result of environmental matters.

Operation of a nuclear facility subjects us to risk. Ownership of an operating nuclear generating plant subjects Detroit Edison to significant additional risks. These risks among others, include plant security, environmental regulation and remediation, and operational factors that can significantly impact the performance and cost of operating a nuclear facility. While Detroit Edison maintains insurance for various nuclear-related risks, there can be no assurances that such insurance will be sufficient to cover our costs in the event of an accident or business interruption at our nuclear generating plant, which may affect our financial performance.

The supply and price of fuel and other commodities may impact our financial results. We are dependent on coal for much of our electrical generating capacity. Price fluctuation and coal and other fuel supply disruptions could have a negative impact on our ability to profitably generate electricity. Our

access to natural gas supplies is critical to ensure reliability of service for our utility gas customers. We have hedging strategies in place to mitigate negative fluctuations in commodity supply prices but there can be no assurances that our financial performance will not be negatively impacted by price fluctuations. The price of natural gas also impacts the market for distributed generation products and other non-utility businesses that compete with utilities and alternative energy suppliers.

A work interruption may adversely affect us. Unions represent a majority of our employees. A union choosing to strike as a negotiating tactic would have an impact on our business.

Unplanned power plant outages may be costly. Unforeseen maintenance may be required to safely produce electricity or comply with environmental regulations. Our financial performance may be negatively affected if we are unable to recover such increased costs.

Our ability to access capital markets at attractive interest rates is important. Our ability to access capital markets is important to operate our businesses. Heightened concerns about the energy industry, the level of borrowing by other energy companies and the market as a whole could limit our access to capital markets. Changes in interest rates could increase our borrowing costs and negatively impact our financial performance.

We rely on cash flows from subsidiaries. Cash flows from subsidiaries are required to pay interest expenses and dividends on DTE Energy debt and securities. Should a major subsidiary not be able to pay dividends or transfer cash flows to DTE Energy, our ability to pay dividends and interest would be restricted.

Property tax reform may be costly. We are one of the largest payers of property taxes in the State of Michigan. Should the legislature change how schools are financed, we could face increased property taxes on our Michigan facilities.

We may not be fully covered by insurance. While we have a comprehensive insurance program in place to provide coverage for various types of risks, catastrophic damage as a result of acts of God, terrorism, war or a combination of significant unforeseen events could impact our operations and economic losses might not be covered in full by insurance.

Terrorism could affect our business. Damage to downstream infrastructure or our own assets by terrorist groups would impact our operations. We have increased security as a result of recent events and further security increases are expected.

Failure to successfully implement new information systems could interrupt our operations. Our businesses depend on numerous information systems for operations and financial information and billings. We are in the process of launching the first phase of our DTE2 project, a multiyear Company-wide initiative to improve existing processes and implement new core information systems. Failure to successfully implement DTE2 and other new systems could interrupt our operations.

Our participation in energy trading markets subjects us to additional risk. Events in the energy trading industry have increased the level of scrutiny on the energy trading business and the energy industry as a whole. A decline in the confidence in the energy trading market along with stricter credit requirements has led to a decrease in the number of trading entities resulting in decreased liquidity in the energy trading market. Also, in certain situations we may be required to post collateral to support trading operations.

EMPLOYEES

The table below shows our employees as of December 31, 2004:


	Represented		Non-represented		Total
Detroit Edison		3,918		3,920		7,838
MichCon		1,479		797		2,276
Other		264		829		1,093

Total		5,661		5,546		11,207

There are several bargaining units for our represented employees. Approximately 4,500, or approximately 79% of our represented employees are under three year contracts that were ratified in 2004. The contracts of the remaining represented employees expire in 2005.

EXECUTIVE OFFICERS OF DTE ENERGY


				Present
				Position
Name	Age (1)		Present Position	Held Since
Anthony F. Earley, Jr.		55	Chairman of the Board, Chief Executive	8-1-98
			Officer, Chief Operating Officer
Gerard M. Anderson		46	President, DTE Energy	6-23-04
			Group President, Energy Resources	5-31-01
Robert J. Buckler		55	Group President, Energy Distribution	5-31-01
Stephen E. Ewing		60	Group President, Energy Gas	5-31-01
David E. Meador		47	Executive Vice President and Chief Financial Officer	6-23-04
S. Martin Taylor		64	Executive Vice President	6-23-04
Ron A. May		53	Senior Vice President	1-22-04
Bruce D. Peterson		48	Senior Vice President and General Counsel	6-25-02
Susan M. Beale		56	Vice President and Corporate Secretary	12-11-95
Daniel G. Brudzynski		44	Vice President and Controller	2-8-01

(1)	As of December 31, 2004

Under our Bylaws, the officers of DTE Energy are elected annually by the Board of Directors at a meeting held for such purpose, each to serve until the next annual meeting of directors or until their respective successors are chosen and qualified. With the exception of Messrs. Ewing and Peterson, all of the above officers have been employed by DTE Energy in one or more management capacities during the past five years.

Stephen E. Ewing was elected group president for DTE Energy Gas on May 31, 2001. He joined DTE Energy having previously served as president and chief operating officer of MCN Energy and president and chief executive officer of MichCon during the previous five years.

Bruce D. Peterson was elected Senior Vice President and General Counsel on June 25, 2002. Mr. Peterson was a partner with Hunton & Williams in Washington, D.C. prior to joining DTE Energy.

Pursuant to Article VI of our Articles of Incorporation, directors of DTE Energy will not be personally liable to the Company or its shareholders in the performance of their duties to the full extent permitted by law.

Article VII of our Articles of Incorporation provides that each current or former director or officer of DTE Energy, or each current and former employee or agent of the Company or a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise (including the heirs, executors, administrators or estate of such person), shall be indemnified by the Company to the full extent

permitted by the Michigan Business Corporation Act or any other applicable laws as presently or hereafter in effect. In addition, we have entered into indemnification agreements with all of our officers and directors, these agreements set forth procedures for claims for indemnification as well as contractually obligating us to provide indemnification to the maximum extent permitted by law.

We and our directors and officers in their capacities as such are insured against liability for alleged wrongful acts (to the extent defined) under seven insurance policies providing aggregate coverage in the amount of $165 million.

Item 3. Legal Proceedings

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

For additional discussion on legal matters, see the following Notes to the Consolidated Financial Statements:


Note		Title
4		Regulatory Matters
5		Nuclear Operations
13		Commitments and Contingencies

Item 4. Submission of Matters to a Vote of Security Holders

We did not submit any matters to a vote of security holders in the fourth quarter of 2004.

Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is listed on the New York Stock Exchange, which is the principal market for such stock, and the Chicago Stock Exchange. The following table indicates the reported high and low sales prices of our common stock on the Composite Tape of the New York Stock Exchange and dividends paid per share for each quarterly period during the past two years:


						Dividends
						Paid
Calendar	Quarter	High		Low		Per Share
2004
	First	$	42.29	$	37.92	$	0.515
	Second	$	41.58	$	37.88	$	0.515
	Third	$	42.21	$	39.31	$	0.515
	Fourth	$	45.49	$	41.44	$	0.515

2003
	First	$	49.50	$	38.51	$	0.515
	Second	$	44.95	$	38.52	$	0.515
	Third	$	38.98	$	34.00	$	0.515
	Fourth	$	39.76	$	35.12	$	0.515

At December 31, 2004, there were 174,209,034 shares of our common stock outstanding. These shares were held by a total of 99,832 shareholders of record.

Our Bylaws nullify Chapter 7B of the Michigan Business Corporation Act (Act). This Act regulates shareholder rights when an individual’s stock ownership reaches 20% of a Michigan corporation’s outstanding shares. A shareholder seeking control of the Company cannot require our Board of Directors to call a meeting to vote on issues related to corporate control within 10 days, as stipulated by the Act. See Note 8 — Common Stock and Earnings Per Share for information concerning the Shareholders’ Rights Agreement.

The amount of future dividends will depend on our earnings, cash flows, financial condition and other factors that are periodically reviewed by our Board of Directors. Although there can be no assurances, we anticipate paying dividends at the current rate of $0.515 per quarter for the foreseeable future. See Note 9 – Long-Term Debt and Preferred Securities for possible restrictions on the payment of dividends.

All of our equity compensation plans that provide for the annual awarding of stock-based compensation have been approved by shareholders. See Note 15 – Stock Based Compensation for additional detail. See below for information as of December 31, 2004.

Number of

securities

securities to be

remaining available

issued upon

Weighted-average

for future issuance

exercise of

exercise price of

under equity

outstanding options

compensation plans

Plans approved by shareholders

6,706,669

40.57

7,518,702

Item 6. Selected Financial Data

The following selected financial data should be read with the accompanying Management’s Discussion and Analysis and Notes.


	2004			2003			2002			2001 (1)			2000
(in Millions, except per share amounts)
Operating Revenues	$	7,114		$	7,041		$	6,729		$	5,787		$	4,638
Net Income
Utility operations	$	170		$	281		$	418		$	198		$	427
Non-utility operations		283			256			224			166			77
Corporate & Other		(10	)		(57	)		(56	)		(55	)		(36	)

Total from continuing operations		443			480			586			309			468
Discontinued operations (2)		(12	)		68			46			20			—
Cumulative effect of accounting changes (3)		—			(27	)		—			3			—

Net Income	$	431		$	521		$	632		$	332		$	468

Diluted Earnings Per Share
Utility operations	$	0.98		$	1.67		$	2.53		$	1.29		$	2.99
Non-utility operations		1.63			1.52			1.36			1.08			.53
Corporate & Other		(.06	)		(.34	)		(.34	)		(.36	)		(.25	)

Total from continuing operations		2.55			2.85			3.55			2.01			3.27
Discontinued operations (2)		(.06	)		.40			.28			.13			—
Cumulative effect of accounting changes (3)		—			(.16	)		—			.02			—

Diluted Earnings Per Share	$	2.49		$	3.09		$	3.83		$	2.16		$	3.27


Financial Information
Dividends declared per share of common stock	$	2.06		$	2.06		$	2.06		$	2.06		$	2.06
Total assets	$	21,297		$	20,753		$	19,985		$	19,587		$	13,350
Long-term debt, including capital leases	$	7,606		$	7,669		$	7,803		$	7,928		$	4,039
Shareholders’ equity	$	5,548		$	5,287		$	4,565		$	4,589		$	4,009

(1)	Includes the acquisition of the Gas Utility business and other non-utility gas businesses on May 31, 2001.
(2)	Includes discontinued operations associated with International Transmission Company and Southern Missouri Gas Company. See Note 3.
(3)	Includes the changes in accounting for energy trading activities and asset retirement obligations in 2003, and derivative instruments and hedging activities in 2001. See Notes 2 and 12.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

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

A significant portion of our earnings is derived from our utility operations, synthetic fuel business, and energy marketing and trading operations. Earnings in 2004 were $431 million, or $2.49 per diluted share, down from 2003 earnings of $521 million, or $3.09 per diluted share. As discussed in the “RESULTS OF OPERATIONS” section that follows, the comparability of earnings was impacted by discontinued businesses and the adoption of new accounting rules. Excluding discontinued operations and the cumulative effect of accounting changes, earnings from continuing operations in 2004 were $443 million, or $2.55 per diluted share, compared to earnings of $480 million, or $2.85 per diluted share for the same 2003 period. Income reflects reduced contributions from our utility operations, partially offset by increased contributions from our non-utility businesses and Corporate & Other. Significant items that influenced our 2004 financial performance and/or may affect future results are:

• Electric Customer Choice penetration;

• Electric and gas rate orders;

• Higher operating costs;

• Weather;

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

• Growth of non-utility businesses.

Electric Customer Choice Program - Since 2002, Michigan residents and businesses have had the option of participating in the electric Customer Choice program. This program is designed to give all customers added choices and the opportunity to benefit from lower power costs resulting from competition. However, Detroit Edison’s rates are regulated by the Michigan Public Service Commission (MPSC), while alternative suppliers can charge market-based rates. This regulation has hindered Detroit Edison’s ability to retain customers. In addition, the MPSC has maintained regulated rates for certain groups of customers that exceed the cost of service to those customers. This has resulted in high levels of participation in the electric Customer Choice program by those customers that have the highest rates relative to their cost of service, primarily commercial and industrial businesses. As a result, our margins continue to be affected. To address this issue, we filed a revenue neutral rate restructuring proposal in February 2005 designed to adjust rates for each customer class to be reflective of the full costs incurred to service such customers. Under the proposal, Detroit Edison’s commercial and industrial rates would be lowered in 2006, but residential rates would increase over a five-year period beginning in 2007. The number and mix of customers participating in the electric Customer Choice program could be impacted under the rate restructuring.

Lost margins and electricity volumes associated with electric Customer Choice were approximately $237 million and 9,245 gigawatthours (gWh) in 2004. This compares with lost electric Customer Choice margins and volumes of approximately $120 million and 6,193 gWh in 2003. The financial impact of electric Customer Choice was affected by the issuance of electric interim and final rate orders that increased base rates, authorized transition charges and reaffirmed the resumption of the Power Supply Cost Recovery (PSCR) mechanism, as subsequently discussed. Partially offsetting the impact of lost margins on income, we recorded regulatory assets representing stranded costs that we believe are

recoverable under existing Michigan legislation and MPSC orders. There are a number of variables and estimates that impact the level of recoverable stranded costs, including weather, sales mix and transition charges. As a result, our estimate of stranded costs could increase or decrease. As subsequently discussed, the MPSC authorized the recovery of $44 million in stranded costs for the period of January 2002 through February 2004.

Detroit Edison rate orders, along with the rate restructuring proposal, address certain issues with the electric Customer Choice program. However, current regulation continues to hinder our ability to retain certain customers. Accordingly, we will continue working with the MPSC and Michigan legislature to address other issues associated with the electric Customer Choice program.

Electric Rate Orders - In 2000, Public Act (PA) 141 froze electric rates for all residential, commercial and industrial customers through 2003. The legislation also prevented rate increases (or capped rates) for small commercial and industrial customers through 2004 and for residential customers through 2005. The rate freeze and caps apply to base rates as well as rates designed to recover fuel and purchased power costs which has traditionally been a cost pass-through under the power supply cost recovery (PSCR) mechanism.

In 2004, the MPSC issued interim and final rate orders that authorized electric rate increases totaling $374 million, and eliminated transition credits and implemented transition charges for electric Customer Choice customers. The increases were applicable to all customers not subject to a rate cap. The interim order affirmed the resumption of the PSCR mechanism for both capped and uncapped customers, which reduced PSCR revenues by $115 million in 2004. However, the order allowed Detroit Edison to increase base rates for customers still subject to a cap in an equal and offsetting amount to the change in the PSCR factor to maintain the total capped rate levels in effect for these customers. The MPSC also authorized the recovery of approximately $385 million in regulatory assets, including stranded costs.

As a result of rate caps, regulatory asset adjustments and other factors, the rate orders decreased 2004 earnings by $15 million. The impact of the rate orders is expected to increase earnings in 2005 and 2006 as rate caps expire.


Effect of Interim and Final Rate Orders
(in Millions)	2004
Base Rate Increase and Transition Charges	$	154
PSCR Reduction		(115	)

Regulatory Assets
Stranded costs adjustment		(33	)
Regulatory asset deferrals – cessation (1)		(29	)


Pre-Tax Income (Decrease)	$	(23	)


Net Income (Decrease)	$	(15	)

(1)	We ceased recording regulatory assets for costs that are reflected in rates pursuant to the MPSC’s 2004 rate orders.

See Note 4 for a further discussion of the MPSC’s interim and final rate orders.

Gas Interim Rate Order - In September 2003, MichCon filed an application with the MPSC for an increase in service and distribution charges (base rates) for its gas sales and transportation customers. The filing requested an overall increase in base rates of $194 million annually (approximately 7% increase, inclusive of gas costs), beginning January 1, 2005. In September 2004, MichCon received an interim order in this rate case authorizing an increase in base rates of $35 million annually, effective September 22, 2004. The interim rate order increased earnings by approximately $6 million in 2004. MichCon expects a final order from the MPSC in the first quarter of 2005.

Operating Costs - During 2004, we experienced increases in operation and maintenance costs, primarily within our electric and gas utilities. The increases were driven by higher costs associated with pension and postretirement benefits and uncollectible accounts receivable.

Pension and postretirement benefits expense totaled $212 million in 2004, compared to $172 million in 2003. The increase is due to financial market performance, lower discount rates and increased health care trend rates. We have made modifications to the pension and postretirement benefit plans to mitigate the earnings impact of higher costs. Additionally, the recoverability of pension and health care benefits costs were part of our electric and gas rate filings. The MPSC approved a pension tracking mechanism in Detroit Edison’s final rate order that provides for the recovery or refunding of pension costs above or below the amount reflected in base rates. The MPSC also required Detroit Edison to propose a similar tracking mechanism for retiree health care costs. Detroit Edison filed a request with the MPSC in February 2005 seeking authority to implement a tracking mechanism for retiree health care costs.

Both utilities continue to experience high levels of past due receivables, especially within our Energy Gas operations. The increase is attributable to economic conditions, high natural gas prices and the lack of adequate levels of assistance for low-income customers. As a result of these factors, our allowance for doubtful accounts expense for the two utilities increased to $105 million in 2004 compared to $76 million for the corresponding 2003 period. We are taking aggressive actions to reduce the level of past due receivables, including customer disconnections, contracting with collection agencies and working with the State of Michigan and others to increase the share of low-income funding allocated to our customers.

In MichCon’s current gas rate filing, we addressed numerous operating cost issues, including uncollectible accounts receivable expense. The MPSC Staff supports a provision proposed by MichCon that would allow MichCon to recover or refund 90% of uncollectible accounts receivable expense above or below the amount that is reflected in base rates. We support the MPSC Staff’s recommendation and believe the provision would significantly reduce our risk of high uncollectible gas accounts receivable.

To partially address this issue of rising costs, we continue to employ the DTE Energy Operating System, which is the application of tools and practices to obtain operating efficiencies and enhance operating performance. We are targeting over $100 million in savings during 2005 through the application of Operating System principles.

Weather - Earnings in our electric and gas utilities are seasonal and sensitive to weather. Electric utility earnings are dependent on hot summer weather, while the gas utility’s results are driven by cold winter weather. We experienced both milder summer and winter weather during 2004, which negatively impacted sales demand. The lower demand reduced current year earnings by $27 million compared to 2003.

Additionally, we occasionally experience various types of storms that damage our electric distribution infrastructure resulting in power outages. The impact of storms on our current year earnings was significantly lower than in 2003, which was affected by several catastrophic wind and ice storms, as well as by the August 2003 blackout. Restoration and other costs associated with storm-related power outages lowered 2004 pretax earnings by $48 million compared to $72 million in 2003.

Synthetic Fuel Operations - We operate nine synthetic fuel production plants at eight locations. Since 2002, we have sold majority interests in eight of the nine plants, representing approximately 92% of our total production capacity. Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applicable Internal Revenue Service (IRS) rules. Section 29 of the Internal Revenue Code provides tax credits for the production and sale of solid synthetic fuel produced from coal. Synfuel-related tax credits expire in December 2007.

Operating expenses associated with synfuel projects exceed operating revenues and therefore generate operating losses, which have been more than offset by the resulting Section 29 tax credits. In order to

recognize Section 29 tax credits, a taxpayer must have sufficient taxable income in the year the tax credit is generated. Once earned, the tax credits are utilized subject to certain limitations but can be carried forward indefinitely. We have not had sufficient taxable income to fully utilize tax credits earned in prior periods. As of December 2004, we had $483 million in tax credit carry-forwards. In order to optimize income and cash flow from our synfuel operations, we have sold majority interests in eight of our nine facilities and intend to sell a majority interest in the remaining plant during 2005, representing 99% of our production capacity. When we sell an interest in a synfuel project, we recognize the gain from such sale as the facility produces and sells synfuel and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectability is reasonably assured. Gain recognition is dependent on the synfuel production qualifying for Section 29 tax credits and the value of such credits as subsequently discussed. In substance, we are receiving synfuel gains and reduced operating losses in exchange for tax credits associated with the projects sold. Sales of interests in synfuel projects allow us to accelerate cash flow while maintaining a stable income base.

The value of a Section 29 tax credit can vary each year and is adjusted annually by an inflation factor as published by the IRS in April of the following year. Additionally, the value of the tax credit in a given year is reduced if the “Reference Price” of oil within the year exceeds a threshold price and is eliminated entirely if the Reference Price exceeds a phase-out price. The Reference Price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil, which in recent years has been $3 — $4 lower than the New York Mercantile Exchange (NYMEX) price for light, sweet crude oil. The actual or estimated Reference Price and beginning and ending phase-out prices per barrel of oil for 2003, 2004 and 2005 are as follows:


			Beginning Phase-Out		Ending Phase-Out
	Reference Price		Price		Price
2003 (actual)	$	27.56	$	50.14	$	62.94
2004 (estimated)	$	37.61	$	51.34	$	64.45
2005 (estimated)	Not Available		$	52.37	$	65.74

Numerous recent events have significantly increased domestic crude oil prices, including terrorism, storm-related supply disruptions and strong worldwide demand. As of February 1, 2005, the NYMEX closing price of a barrel of oil to be delivered in March 2005 was $47.12, which is comparable to a $43.47 Reference Price (assuming that such price was to continue for an entire year). For 2005 and later years, if the Reference Price falls within or exceeds the phase-out range, the availability of tax credits in that year would be reduced or eliminated, respectively.

As previously discussed, until the gain recognition criteria is met, gains from selling interests in synfuel facilities will be deferred. It is possible that gains will be deferred in the first, second and/or third quarters of each year until there is persuasive evidence that no tax credit phase out will occur for the applicable calendar year. This could result in shifting earnings from earlier quarters to later quarters of a calendar year.

As discussed in Notes 12 and 13, we have entered into derivative and other contracts to economically hedge approximately 65% of our 2005 synfuel cash flow exposure related to the risk of an increase in oil prices. We are continuing to evaluate the current volatility in oil prices and alternatives available to mitigate our unhedged exposure to oil prices as part of our synfuel-related risk management strategy.

Assuming no synfuel tax credit phase out in future years, we expect cash flow from our synfuel business to total approximately $1.6 billion between 2005 and 2008. The source of synfuel cash flow includes cash from operations, asset sales, and the utilization of Section 29 tax credits carried forward from synfuel production prior to 2004.

Non-utility Growth - During 2004, we continued to experience growth in our non-utility businesses with income reaching $283 million compared to $256 million in 2003. The improvement primarily reflects increased contributions in our Energy Marketing & Trading segment, primarily due to a one-time contract gain. Additionally, non-utility growth in 2004 is attributable to increased earnings from our synfuels, coke

batteries and on-site energy projects. Also affecting the year over year comparison are asset gains, losses and impairments during 2004 and 2003 as subsequently discussed.

Outlook - We made significant progress during the past year on our 2004 corporate priorities, which included:

• Successful rate case outcomes;

• Addressing structural issues with the electric Customer Choice program;

• Continuing sell-down of synfuel portfolio;

• Continuing non-utility growth momentum; and

• Maintaining cash and balance sheet strength.

Our long-term strategy has not changed and in 2005 we will focus on maintaining a strong utility base, pursuing a unique growth strategy focused on value creation in targeted markets, maintaining a strong balance sheet and paying an attractive dividend. The impact of the rate orders is expected to increase utility earnings in 2005 and 2006 as rate caps expire.

Our financial performance will be dependent on successfully redeploying an expected $1.65 billion of cash flow through 2008, primarily associated with proceeds from the sale of interests in synfuel facilities. Our objective for cash redeployment is to strengthen the balance sheet and coverage ratios, as well as replace the value of synfuels that is currently inherent in our share price. We will first use our cash to reduce parent company debt. Secondly, we will continue to pursue growth investments that meet our strict risk-return and value creation criteria. Lastly, share repurchases will be used to build share value if adequate investment opportunities are not available.

RESULTS OF OPERATIONS

We had earnings of $431 million in 2004, or $2.49 per diluted share, compared to earnings of $521 million, or $3.09 per diluted share in 2003 and earnings of $632 million, or $3.83 per diluted share in 2002. As subsequently discussed, the comparability of earnings was impacted by our two discontinued businesses, International Transmission Company and Southern Missouri Gas Company, and the adoption of two new accounting rules in 2003. Excluding discontinued operations and the cumulative effect of accounting changes, our earnings from continuing operations in 2004 were $443 million, or $2.55 per diluted share, compared to earnings of $480 million, or $2.85 per diluted share in 2003 and earnings of $586 million, or $3.55 per diluted share in 2002. The following sections provide a detailed discussion of our segments, operating performance and future outlook.

Segment Performance & Outlook – Through 2004, we operated our businesses through three strategic business units (Energy Resources, Energy Distribution and Energy Gas). Each business unit had utility and non-utility operations. The balance of our business consisted of Corporate & Other. This resulted in the following reportable segments. In 2005, we expect to realign our business units as discussed in Note 1.


(in Millions, except per share data)	2004		2003			2002
Net Income (Loss)
Energy Resources
Utility — Power Generation	$	62	$	235		$	241

Non-utility
Energy Services		188		199			182
Energy Marketing & Trading		92		45			25
Other		1		(2	)		7

Total Non-utility		281		242			214

		343		477			455


Energy Distribution
Utility — Power Distribution		88		17			111


(in Millions, except per share data)	2004			2003			2002
Non-utility		(19	)		(15	)		(16	)

		69			2			95


Energy Gas
Utility — Gas Distribution		20			29			66
Non-utility		21			29			26

		41			58			92

Corporate & Other		(10	)		(57	)		(56	)


Income from Continuing Operations
Utility		170			281			418
Non-utility		283			256			224
Corporate & Other		(10	)		(57	)		(56	)

		443			480			586
Discontinued Operations		(12	)		68			46
Cumulative Effect of Accounting Changes.		—			(27	)		—

Net Income	$	431		$	521		$	632


Diluted Earnings Per Share
Utility	$	.98		$	1.67		$	2.53
Non-utility		1.63			1.52			1.36
Corporate & Other		(.06	)		(.34	)		(.34	)

Income from Continuing Operations		2.55			2.85			3.55
Discontinued Operations		(.06	)		.40			.28
Cumulative Effect of Accounting Changes.		—			(.16	)		—

Net Income	$	2.49		$	3.09		$	3.83

ENERGY RESOURCES

Utility — Power Generation

The power generation plants of Detroit Edison comprise our regulated power generation business. Detroit Edison’s numerous fossil plants, its hydroelectric pumped storage plant and its nuclear plant generate electricity. The generated electricity, supplemented with purchased power, is sold principally throughout Michigan and the Midwest to residential, commercial, industrial and wholesale customers.

Factors impacting income: Power Generation earnings decreased $173 million in 2004 and $6 million in 2003, compared to the prior year. As subsequently discussed, these results primarily reflect reduced gross margins and increased operation and maintenance expenses.


(in Millions)	2004			2003			2002
Operating Revenues	$	2,210		$	2,448		$	2,711
Fuel and Purchased Power		868			920			1,048

Gross Margin		1,342			1,528			1,663
Operation and Maintenance		672			628			626
Depreciation and Amortization		272			224			331
Taxes Other Than Income		147			157			156
Operating Income		251			519			550
Other (Income) and Deductions		166			149			189
Income Tax Provision		23			135			120

Net Income	$	62		$	235		$	241


Operating Income as a Percent of Operating Revenues		11	%		21	%		20	%

Gross margins declined $186 million during 2004 and $135 million in 2003. The declines were due primarily to lost margins from retail customers choosing to purchase power from alternative suppliers under the electric Customer Choice program as well as reduced cooling demand resulting from mild summer weather. As a result of electric Customer Choice penetration, Detroit Edison lost 18% of retail sales in 2004, compared to 12% of such sales during 2003. The loss of retail sales under the electric Customer Choice program also resulted in lower purchase power requirements, as well as excess power capacity that was sold in the wholesale market. Under the 2004 interim and final rate orders previously discussed, revenues from selling excess power reduce the level of recoverable fuel and purchased power costs and therefore do not impact margins associated with uncapped customers. The rate orders also lowered PSCR revenues, which were partially offset by increased base rate and transition charge revenues.

Weather in 2004 was 3% milder than 2003, resulting in lost margins of $25 million. Weather in 2003 was also milder than the prior year, resulting in lost margins of $114 million. The decline in margins and revenues in 2004 was also due to the allocation of a smaller portion of Detroit Edison’s billings to Power Generation.

(BAR CHART)

Operating revenues and fuel and purchased power costs decreased in 2004 and 2003 reflecting a $1.27 per megawatt hour (MWh) (8%) decline in fuel and purchased power costs during 2004 and a $.64 per MWh (4%) decline during 2003. Fuel and purchased power costs are a pass-through with the reinstatement of the PSCR in 2004, and therefore do not affect margins or earnings associated with uncapped customers. The decrease in fuel and purchased power costs is attributable to lower priced purchases and the use of a more favorable power supply mix driven by higher generation output. The favorable mix is due to lower purchases, driven by lost sales under the electric Customer Choice program. The comparison was also

affected by higher costs associated with substitute power purchased to meet customer demand during the August 2003 blackout. We were required to purchase additional power during the 36-day period it took for our generation fleet to return to pre-blackout capacity.


	2004		2003		2002
Electric Sales and Use
(in Thousands of MWh)
Retail		40,379		43,672		48,346
Wholesale and Other		8,569		5,600		6,128

		48,948		49,272		54,474
Internal Use and Line Loss		3,574		3,248		3,651

		52,522		52,520		58,125


Power Generated and Purchased
(in Thousands of MWh)
Power Plant Generation
Fossil		39,432	75	%		38,052	72	%		39,017	67	%
Nuclear (Fermi 2)		8,440	16			8,114	16			9,301	16

		47,872	91			46,166	88			48,318	83
Purchased Power		4,650	9			6,354	12			9,807	17

System Output		52,522	100	%		52,520	100	%		58,125	100	%


Average Unit Cost ($/MWh)

Generation (1)	$	12.98			$	12.89			$	12.53

Purchased Power (2)	$	37.06			$	41.73			$	39.16

Overall Average Unit Cost	$	15.11			$	16.38			$	17.02

(1)		Represents fuel costs associated with power plants.

(2)		Includes amounts associated with hedging activities.

Operation and maintenance expense increased $44 million in 2004 and $2 million in 2003. The 2004 increase reflects costs associated with maintaining our generation fleet, including costs of scheduled and forced plant outages. Additionally, the increase in 2004 is due to incremental costs associated with the implementation of our DTE2 project, a Company-wide initiative to improve existing processes and to implement new core information systems, including finance, human resources, supply chain and work management. Operation and maintenance expense in both years includes higher employee pension and health care benefit costs due to financial market performance, discount rates and health care trend rates. Expenses in 2003 were also affected by $5 million in costs associated with the August 2003 blackout.

Depreciation and amortization expense increased $48 million in 2004 and decreased $107 million in 2003. The variations reflect the income effect of recording regulatory assets, which lowered depreciation and amortization expenses. The regulatory asset deferrals totaled $107 million in 2004 and $153 million in 2003, representing net stranded costs and other costs we believe are recoverable under PA 141.

Other income and deductions expense increased $17 million in 2004 and decreased $40 million in 2003. The 2004 increase is primarily due to lower income associated with recording a return on regulatory assets, as well as costs associated with addressing the structural issues of PA 141. The 2003 decrease is attributable to lower interest expenses and increased interest income. Interest expense reflects lower borrowing levels and rates, and interest income includes the accrual of carrying charges on environmental-related regulatory assets.

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

As previously discussed, we expect cash flows and operating performance will continue to be at risk due to the electric Customer Choice program until the issues associated with this program are addressed. We will accrue as regulatory assets our unrecovered generation-related fixed costs (stranded costs) due to electric Customer Choice that we believe are recoverable under Michigan legislation and MPSC orders. We have addressed certain issues of the electric Customer Choice program in our February 2005 rate restructuring proposal. We cannot predict the outcome of these matters.

In conjunction with the sale of the transmission assets of ITC in February 2003, the Federal Energy Regulatory Commission (FERC) froze ITC’s transmission rates through December 2004. It is expected that annual rate adjustments pursuant to a formulistic pricing mechanism beginning in January 2005 will result in an estimated increase in Detroit Edison’s transmission expense of $50 million annually. Additionally, in a proceeding before the FERC, several Midwest utilities seek to recover transmission revenues lost as a result of a FERC order modifying the pricing of transmission service in the Midwest. Detroit Edison estimates that its potential obligation as a result of this proceeding could be $2.2 million per month from December 2004 through March 2005 and $1 million per month from April 2005 through March 2006. Detroit Edison is expected to incur an additional $15 million in 2005 for charges related to the implementation of Midwest Independent Transmission Operator’s open market. As previously discussed, Detroit Edison received rate orders in 2004 that allow for the recovery of increased transmission expenses through the PSCR mechanism.

See Note 4 – Regulatory Matters.

Energy Services

Energy Services is comprised of Coal-Based Fuels, On-Site Energy Projects and non-utility Power Generation. Coal-Based Fuels operations include producing synthetic fuel from nine synfuel plants and producing coke from three coke battery plants. The production of synthetic fuel from all of our synfuel plants and the production of coke from one of our coke batteries generate tax credits under Section 29 of the Internal Revenue Code. On-Site Energy Projects include pulverized coal injection, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. Power Generation owns and operates four gas-fired peaking electric generating plants and manages and operates two additional gas-fired power plants under contract. Additionally, Power Generation develops, operates and acquires coal and gas-fired generation.

Factors impacting income: Energy Services earnings decreased $11 million in 2004 and increased $17 million in 2003, compared to the prior year. As subsequently discussed, these results primarily reflect higher gains recognized from selling majority interests in our synfuel plants, varying levels of Section 29 tax credits, a gain from contract termination, uncollectible accounts written-off and losses on synfuel hedges.


(in Millions)	2004			2003			2002
Operating Revenues
Coal-Based Fuels	$	980		$	850		$	559
On-Site Energy Projects		96			70			63
Power Generation – Non-utility		13			9			23

		1,089			929			645
Operation and Maintenance Fuel and purchased power		1,188			1,049			708
Depreciation and Amortization Fuel and purchased power		82			84			81
Taxes other than Income		15			18			15
Gain on Sale of Interests in Synfuel Projects		(219	)		(83	)		(40	)

Operating Income (Loss)		23			(139	)		(119	)
Other (Income) and Deductions		(17	)		2			4
Minority Interest		(212	)		(91	)		(37	)
Income Taxes
Provision (Benefit)		95			(19	)		(30	)
Section 29 Tax Credits		(31	)		(230	)		(238	)

		64			(249	)		(268	)

Net Income	$	188		$	199		$	182

Operating revenues increased $160 million in 2004 and $284 million in 2003 reflecting higher synfuel, coal and coke sales, as well as increased revenues from our on-site energy projects.

The improvement in synfuel revenues results from increased production due to additional sales of project interests in 2004 and 2003, reflecting our strategy to produce synfuel primarily from plants in which we had sold interests in order to optimize income and cash flow. As previously discussed, operating expenses associated with synfuel projects exceed operating revenues and therefore generate operating losses, which have been more than offset by the resulting Section 29 tax credits. When we sell an interest in a synfuel project, we recognize the gain from such sale as the facility produces and sells synfuel and when there is persuasive evidence that the sales proceeds to the Company have become fixed or determinable and collectability is reasonably assured. In substance, we are receiving synfuel gains and reduced operating losses in exchange for tax credits associated with the projects sold.

(BAR CHART)

Coal marketing revenues in 2004 have also been affected by our strategy to produce synfuel primarily from plants in which we had sold interests. This strategy resulted in the reduction of synfuel production levels. We were contractually obligated to supply coal to customers at certain sites that did not produce synfuel as a result of our current production strategy. To meet our obligations to provide coal under long-term contracts with customers, we acquired coal that was resold to customers. The coal was sold at prices higher than the prices at which synfuel would have been sold to these customers.

Revenues from coke sales were higher in 2004, due to higher coke sales volumes combined with higher market prices, due to limited supplies of coke in the U.S.

Revenues from on-site energy projects increased in 2004, reflecting the completion of new long-term utility services contracts with a large automotive company and a large manufacturer of paper products. Revenues in 2004 include a $9 million pre-tax fee generated in conjunction with the development of a related energy project, 50% of which was sold to an unaffiliated partner.

Operation and maintenance expense increased $139 million in 2004 and $341 million in 2003, reflecting costs associated with synfuel production and coke operations. Partially offsetting the higher synfuel operating costs in 2004 was the recording of insurance proceeds associated with an accident at one of our coke batteries. Operation and maintenance expense in 2003 was affected by a $30 million pre-tax gain from the termination of a tolling agreement at one of our generation facilities, substantially offset by the establishment of a $28 million pre-tax reserve for receivables associated with a large customer that filed for bankruptcy.

Gains on sale of interests in synfuel projects increased $136 million in 2004 and $43 million in 2003. The improvements are due to additional sales of majority interests in our synfuel projects. To hedge our exposure to the risk of an increase in oil prices that could reduce synfuel sales proceeds, we entered into derivative and other contracts covering approximately 65% of our 2005 synfuel cash flow exposure. The derivative contracts are accounted for under the mark to market method with changes in their fair value recorded as an adjustment to synfuel gains. We recorded a mark to market loss during the 2004 fourth quarter, which reduced 2004 synfuel gains by $12 million pre-tax. See Note 12 for further discussion.

Minority interest increased $121 million in 2004 and $54 million in 2003, reflecting our partners’ share of operating losses associated with synfuel operations. The sale of interests in our synfuel facilities during 2004 and 2003 resulted in allocating a larger percentage of such losses to our partners.

Income taxes increased $313 million in 2004 and $19 million in 2003, reflecting higher taxable earnings and a decline in the level of Section 29 tax credits due to the sale of interests in synfuel facilities.

Outlook - Energy Services will continue leveraging its extensive energy-related operating experience and project management capability to develop and grow the on-site energy business. We expect solid earnings from our on-site energy business in 2005 as a result of executing long-term utility services contracts in 2004.

Energy Marketing & Trading

Energy Marketing & Trading consists of the electric and gas marketing and trading operations of DTE Energy Trading and CoEnergy. DTE Energy Trading focuses on physical power marketing and structured transactions, as well as the enhancement of returns from DTE Energy’s power plants. CoEnergy focuses on physical gas marketing and the optimization of DTE Energy’s owned and contracted natural gas pipelines and gas storage capacity. To this end, both companies enter into derivative financial instruments as part of their marketing and hedging strategies, including forwards, futures, swaps and option contracts. Most of the derivative financial instruments are accounted for under the mark to market method, which results in earnings recognition of unrealized gains and losses from changes in the fair value of the derivatives.

Factors impacting income: Energy Marketing & Trading’s earnings increased $47 million in 2004, consisting of a $4 million improvement at DTE Energy Trading and a $43 million improvement at CoEnergy. Earnings increased $20 million in 2003, of which $18 million was attributable to DTE Energy Trading and $2 million to CoEnergy.

DTE Energy Trading’s earnings improvement in 2004 and 2003 was primarily due to realized margins associated with short-term physical trading and origination activities.


(in Millions)	2004			2003			2002
DTE Energy Trading
Margins – Gains (Losses)
Realized (1)	$	83		$	82		$	38
Unrealized (2):
Proprietary Trading (3)		(7	)		(7	)		—
Structured Contracts (4)		3			(2	)		13
Economic Hedges (5)		1			—			—

Total Unrealized Margins		(3	)		(9	)		13

Total Margins		80			73			51
Operating and Other Costs		29			28			29
Income Tax Provision		15			13			8

Net Income	$	36		$	32		$	14


CoEnergy
Margins – Gains (Losses) (7)
Realized (1)	$	(42	)	$	168		$	32
Unrealized (2):
Proprietary Trading (3)		—			4			9
Structured Contracts (4)		(1	)		(1	)		22
Economic Hedges (5)		68			(138	)		(93	)
Gas in Inventory (6)		—			—			74

Total Unrealized Margins		67			(135	)		12

Total Margins		25			33			44
Gain from Contract Modification / Termination		(74	)		—			—
Operating and Other Costs		12			13			27
Income Tax Provision		31			7			6

Net Income	$	56		$	13		$	11

Total Energy Marketing & Trading Net Income	$	92		$	45		$	25

(1)		Realized margins include the settlement of all derivative and non-derivative contracts, as well as the amortization of deferred assets and liabilities.

(2)		Unrealized margins include mark-to-market gains and losses on derivative contracts, net of gains and losses reclassified to realized. See “Fair Value of Contracts” section that follows.

(3)		“Proprietary Trading” represents the net unrealized effect of actively traded positions entered into to take advantage of market price movements.

(4)		“Structured Contracts” represent the net unrealized effect of derivative transactions entered into with the intent to capture profits by originating substantially hedged positions with wholesale energy marketers, utilities, retail aggregators and alternative energy suppliers.

(5)		“Economic Hedges” represent the net unrealized effect of derivative activity associated with assets owned or contracted for by DTE Energy, including forward sales of gas production and trades associated with transportation and storage capacity.

(6)		Gas in inventory margins represent gains associated with fair value accounting in 2002. CoEnergy changed its method of accounting for inventory in January 2003 (Note 2).

(7)		Excludes the impact on margins from the modification of a transportation agreement with an interstate pipeline company.

CoEnergy’s earnings in 2004 and 2003 were affected by varying gains and losses on economic hedge contracts related to storage assets. As subsequently discussed in the “Outlook” section, the unrealized gains and losses of economic hedge contracts are required to be recognized under mark-to-market accounting, while the offsetting unrealized losses and gains on the underlying asset positions are not recognized.

CoEnergy’s earnings in 2004 reflect a $74 million one-time pre-tax gain from modifying a future purchase commitment under a transportation agreement and terminating a related long-term gas exchange (storage) agreement with an interstate pipeline company. Under the gas exchange agreement, we received gas from the customer during the summer injection period and redelivered the gas during the winter heating season.

The realized and unrealized margins comparison for both DTE Energy Trading and CoEnergy was affected by our decision in late 2003 to monetize certain in-the-money derivative contracts while simultaneously entering into replacement at-the-market contracts. The monetizations were completed in conjunction with implementing a series of initiatives to improve cash flow and fully utilize Section 29 tax

credits. Although the monetizations did not impact earnings, they had the effect of decreasing realized margins and increasing unrealized margins on economic hedges in 2004, and having the opposite effect on margins in 2003.

Outlook – Energy Marketing & Trading will seek to manage its business in a manner consistent with, and complementary to, the growth of our other business segments. Gas storage and transportation capacity enhances our ability to provide reliable and custom-tailored bundled services to large-volume end users and utilities. This capacity, coupled with the synergies from DTE Energy’s other businesses, positions the segment to add value.

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

Non-utility — Other

Our other non-utility businesses include our Coal Services and Biomass units. Coal Services provides fuel, transportation and rail equipment management services. We specialize in minimizing fuel costs and maximizing reliability of supply for energy-intensive customers. Additionally, we participate in coal trading and coal-to-power tolling transactions, as well as the purchase and sale of emissions credits. Coal Services has formed a subsidiary, DTE PepTec Inc., which uses proprietary technology to produce high quality coal products from fine coal slurries typically discarded from coal mining operations. Biomass develops, owns and operates landfill recovery systems in the U.S. Gas produced from many of these landfill sites qualifies for Section 29 tax credits.

Factors impacting income: Earnings increased $3 million in 2004 and declined $9 million in 2003. The 2004 increase reflects higher sales from coal and emissions credits, partially offset by increased costs associated with our waste coal operations. The 2003 decline reflects reduced marketing and tolling income as well as an increase in operating costs associated with ramping up the DTE PepTec business. Our first waste coal facility in Ohio became operational in late 2003.




(Dollars in Millions)	2004		2003		2002
Coal Services
Tons of coal shipped (in millions)		39.9		32.0		28.5

Biomass
Gas Produced (in Bcf)		23.2		26.8		27.5
Tax Credits Generated (1)	$	7.7	$	10.5	$	12.9

(1)

DTE Energy’s portion of total tax credits generated.

Outlook – We expect to continue to grow our Coal Services and Biomass units. We believe a substantial market could exist for the use of DTE PepTec Inc. technology and we continue to modify and prove out this technology. Coal Services and Biomass have formed a new subsidiary to enter the coal mine methane business. We purchased coal mine methane assets in Illinois at the end of 2004, and expect to reconfigure equipment and restart operations by mid-2005.

The Section 29 tax credits generated by Biomass are subject to the same phase out risk if domestic crude oil prices reach certain levels, as detailed in the synthetic fuel operations discussion. See Note 13.

ENERGY DISTRIBUTION

Utility — Power Distribution

Power Distribution operations include the electric distribution services of Detroit Edison. Power Distribution distributes electricity generated and purchased by Energy Resources and alternative energy suppliers to Detroit Edison’s 2.1 million customers.

Factors impacting income: Power Distribution earnings increased $71 million during 2004 and decreased $94 million in 2003, compared to the prior year. As subsequently discussed, these results primarily reflect varying operating revenues and operation and maintenance expenses as well as a non-recurring loss recorded in 2003.




	2004			2003			2002
(in Millions)
Operating Revenues	$	1,358		$	1,247		$	1,343
Fuel and Purchased Power		17			19			26
Operation and Maintenance		723			724			649
Depreciation and Amortization		251			249			246
Taxes Other Than Income		101			100			117

Operating Income		266			155			305
Other (Income) and Deductions		137			128			136
Income Tax Provision		41			10			58

Net Income	$	88		$	17		$	111


Operating Income as a Percent of Operating Revenues		20	%		12	%		23	%


	2004		2003		2002
Electric Deliveries
(in Thousands of MWh)
Residential		15,081		15,074		15,958
Commercial		13,425		15,942		18,395
Industrial		11,472		12,254		13,590
Wholesale		2,197		2,241		2,249
Other		401		402		403

		42,576		45,913		50,595
Electric Choice		9,245		6,193		2,967
Electric Choice – Self Generations*		595		1,088		543

Total Electric Deliveries		52,416		53,194		54,105

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

Operating revenues increased $111 million in 2004, primarily due to an increase in base rates resulting from the interim and final rate orders. The 2004 improvement is also attributable to residential sales growth and the allocation of a higher portion of Detroit Edison’s billings to Power Distribution, partially offset by the effects of milder weather. Operating revenues decreased $96 million in 2003, reflecting mild summer weather and the impact of slower economic conditions.

Operation and maintenance expense decreased $1 million in 2004 and increased $75 million in 2003. The operation and maintenance expense comparability was affected by 2003 restoration costs associated with three catastrophic storms and the August 2003 blackout. Both years were also affected by an increase in

reserves for uncollectible accounts receivable, reflecting high past due amounts attributable to economic conditions, and an increase in employee benefit costs. Additionally, the comparisons were affected by incremental costs associated with our DTE2 project implementation, a $22 million pre-tax loss in 2003 from the sale of our steam heating business, and the accrual of refunds in 2004 and 2003 associated with transmission services.

(BAR CHART)

Outlook – Operating results are expected to vary as a result of external factors such as weather, changes in economic conditions and the severity and frequency of storms.

We experienced numerous catastrophic storms over the past few years. The effect of the storms on annual earnings was partially offset by storm insurance. We have been unable to obtain storm insurance at economical rates and as a result, we do not anticipate having insurance coverage at levels that would significantly offset unplanned expenses from ice storms, tornadoes, or high winds that damage our distribution infrastructure.

Non-Utility

Non-utility Energy Distribution operations consist of DTE Energy Technologies, which assembles, markets, distributes and services distributed generation products, provides application engineering, and monitors and manages on-site generation system operations.

Factors impacting income: Non-utility results declined $4 million in 2004 and improved $1 million in 2003. The 2004 decrease includes an impairment charge for an “other than temporary” decline in the fair value of an investment in a joint venture that supplied certain distributed generation equipment and materials to DTE Energy Technologies.

Outlook – DTE Energy Technologies will focus on sales of proprietary pre-engineered and packaged continuous generation products in key applications. This will likely result in near-term revenue decline, but we anticipate gross profit margins will improve. Combined with continuing cost reductions and resumption of sales growth, we believe these actions will lead to improved financial performance in 2005.

ENERGY GAS

Utility — Gas Distribution

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

Factors impacting income: Gas Distribution’s earnings declined $9 million in 2004 and $37 million in 2003, compared to the prior year. As subsequently discussed, results primarily reflect varying gross margins, higher operation and maintenance expenses and a non-recurring loss recorded in 2003.




	2004			2003			2002
(in Millions)
Operating Revenues	$	1,682		$	1,498		$	1,369
Cost of Gas		1,071			909			774

Gross Margins		611			589			595
Operation and Maintenance		400			371			297
Depreciation and Amortization		103			101			104
Taxes Other Than Income		49			52			51

Operating Income		59			65			143
Other (Income) and Deductions		48			36			41
Income Tax Provision (Benefit)		(9	)		—			36

Net Income	$	20		$	29		$	66


Operating Income as a Percent of Operating Revenues		4	%		4	%		10	%

Gross margins increased $22 million in 2004 and decreased $6 million in 2003, compared to the prior year. The improvement in 2004 reflects the impact of interim rate relief and additional margin from the acceleration of several midstream services contracts. Partially offsetting these improvements were lower sales and end user transportation deliveries due to milder weather. The gross margin comparison was also affected by a $26.5 million pre-tax reserve recorded in 2003 for the potential disallowance in gas costs pursuant to an MPSC order in MichCon’s 2002 gas cost recovery (GCR) plan case (Note 4). Operating revenues and cost of gas increased significantly in 2004 and 2003 reflecting higher gas prices, which are recoverable from customers through the GCR mechanism.




	2004		2003		2002
Gas Markets (in Millions)
Gas sales	$	1,435	$	1,242	$	1,135
End user transportation		119		136		122

		1,554		1,378		1,257
Intermediate transportation		56		51		48
Other		72		69		64

	$	1,682	$	1,498	$	1,369


Gas Markets (in Bcf)
Gas sales		173		181		174
End user transportation		145		152		171

		318		333		345
Intermediate transportation		536		576		492

		854		909		837

Operation and maintenance expense increased $29 million in 2004 and $74 million in 2003, reflecting higher reserves for uncollectible accounts receivable and pension and health care costs. The increase in uncollectible accounts expense reflects high past due amounts attributable to an increase in gas prices, continued weak economic conditions and a lack of adequate public assistance for low-income customers.

(BAR CHART)

Other income and deductions expense increased $12 million in 2004 and decreased $5 million in 2003, reflecting a 2003 gain on sale of interests in a series of real estate partnerships.

Income taxes in 2004 and 2003 were impacted by lower earnings and favorably affected by an increase in the amortization of tax benefits previously deferred in accordance with MPSC regulations.

Outlook – Operating results are expected to vary as a result of external factors such as regulatory proceedings, weather and changes in economic conditions. Higher gas prices and economic conditions have resulted in an increase in past due receivables. We believe our allowance for doubtful accounts is based on reasonable estimates. However, failure to make continued progress in collecting past due receivables would unfavorably affect operating results. Energy assistance programs funded by the federal government and the State of Michigan remain critical to MichCon’s ability to control uncollectible accounts receivable expenses. We are working with the State of Michigan and others to increase the share of funding allocated to our customers to be representative of the number of low-income individuals in our service territory.

As a result of the continued increase in operating costs, MichCon filed a rate case in September 2003 to increase rates by $194 million annually to address future operating costs and other issues. MichCon received an interim order in this rate case in September 2004 increasing rates by $35 million annually. The MPSC Staff has recommended a provision that would allow MichCon to recover or refund 90% of uncollectible accounts receivable expense above or below the amount that is reflected in base rates. See Note 4 – Regulatory Matters.

Non-utility

Non-utility operations include the Gas Production business and the Gas Storage, Pipelines & Processing business. Our Gas Production business produces gas from proven reserves in northern Michigan and sells the gas to the Energy Marketing & Trading segment. Gas Storage, Pipelines & Processing has a partnership interest in an interstate transmission pipeline, seven carbon dioxide processing facilities and a natural gas storage field, as well as lease rights to another natural gas storage field. The assets of these businesses are well integrated with other DTE Energy entities.

Factors impacting income: Earnings decreased $8 million in 2004 and increased $3 million in 2003. The decline in 2004 is due to gains recorded in 2003 from selling our 16% pipeline interest in the Portland Natural Gas Transmission System, as well as from selling certain gas properties. Excluding those gains, income increased $2 million reflecting the acquisition of an additional 15% ownership in the Vector

Pipeline in late 2003, increased sales of transportation capacity by Vector Pipeline and increased storage sales throughout 2004.

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

We expect to continue developing our gas production properties in northern Michigan and leverage our experience in this area by pursuing investment opportunities in unconventional gas production outside of Michigan. During 2004, we acquired approximately 50,000 leasehold acres in the southern region of the Barnett shale in Texas, an area of increasing production. We began drilling test wells in December 2004 and anticipate drilling a significant number of additional test wells in the first half of 2005. Initial results from the test wells are expected in mid-2005. If the results are successful, we could commit up to $350 million of capital over the next several years to develop these properties.

CORPORATE & OTHER

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

Factors impacting income: Corporate & Other results improved $47 million in 2004, compared to a $1 million decline in 2003. The 2004 improvement was affected by a $14 million net of tax gain from the sale of 3.5 million shares of Plug Power stock (Note 1), as well as lower Michigan Single Business Taxes, resulting from tax saving initiatives. Results for 2003 include a $15 million cash contribution to the DTE Energy Foundation, funded with proceeds received from the sale of ITC. Corporate & Other also benefited from lower financing costs and increased intercompany interest income in both periods.

DISCONTINUED OPERATIONS

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

International Transmission Company - In February 2003, we sold ITC, our electric transmission business, to affiliates of Kohlberg Kravis Roberts & Co. and Trimaran Capital Partners, LLC. Accordingly, we classified ITC as a discontinued operation. The sale generated a preliminary net of tax gain of $63 million in 2003. The gain was net of transaction costs, the portion of the gain that was refundable to customers and the write off of approximately $44 million of allocated goodwill. The gain was lowered to $58 million in 2004 under the MPSC’s November 2004 final rate order that resulted in a revision of the applicable transaction costs and customer refund. We had income from discontinued operations of $5 million in 2003.

See Note 3 for further discussion.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES

As required by U.S. generally accepted accounting principles, on January 1, 2003, we adopted new accounting rules for asset retirement obligations and energy trading activities. The cumulative effect of

adopting these new accounting rules reduced 2003 earnings by $27 million. See Note 2 for further discussion.

CAPITAL RESOURCES AND LIQUIDITY

DTE Energy and its subsidiaries require cash to operate and cash is provided by both internally and externally generated sources. We manage our liquidity and capital resources to maintain financial flexibility to meet our current and future cash flow needs.

Cash Requirements

We use cash to maintain and expand our electric and gas utilities and to grow our non-utility businesses, in addition to retiring and paying interest on long-term debt and paying dividends. Our strategic direction anticipates base level capital investments and expenditures for existing businesses in 2005 of up to $1.1 billion. The capital needs of our utilities will increase due primarily to environmental related expenditures.

Capital spending for general corporate purposes will increase in 2005, primarily as a result of DTE2 and environmental spending. We began implementing the DTE2 project in 2003. The Company expects the project to incrementally cost approximately $150 million to $175 million.

The EPA ozone transport regulations and final new air quality standards relating to ozone and particulate air pollution will continue to impact us. Detroit Edison estimates that it will spend approximately $100 million in 2005 and incur up to an additional $1.3 billion of future capital expenditures over the next five to eight years to satisfy both existing and proposed new control requirements. The full recovery of $550 million of environmental expenditures was authorized in the MPSC’s November 2004 final rate order.

Non-utility capital spending will approximate $100 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.

Debt maturing in 2005, excluding securitization debt, totals approximately $410 million.

We believe that we will have sufficient internal and external capital resources to fund anticipated capital requirements.



(in Millions)	2004			2003			2002
Cash and Cash Equivalents
Cash Flow From (Used For)
Operating activities:
Net income	$	431		$	521		$	632
Depreciation, depletion and amortization		744			691			759
Deferred income taxes		129			(220	)		(208	)
Gain on sale of ITC, synfuel and other assets, net.		(236	)		(228	)		(40	)
Working capital and other		(73	)		186			(147	)

		995			950			996

Investing activities:
Plant and equipment expenditures – utility		(815	)		(679	)		(794	)
Plant and equipment expenditures – non-utility		(89	)		(72	)		(190	)
Investment in joint ventures		(36	)		(34	)		(21	)
Proceeds from sale of ITC, synfuels and other assets		325			758			41
Restricted cash and other investments		(66	)		37			(151	)

		(681	)		10			(1,115	)

Financing activities:
Issuance of long-term debt and common stock		777			571			1,403
Redemption of long-term debt		(759	)		(1,208	)		(793	)
Short-term borrowings, net		33			(44	)		(267	)
Dividends on common stock and other		(363	)		(358	)		(359	)

		(312	)		(1,039	)		(16	)

Net Increase (Decrease) in Cash and Cash Equivalents	$	2		$	(79	)	$	(135	)

Cash from Operating Activities

A majority of the Company’s operating cash flow is provided by our two utilities, which are significantly influenced by factors such as weather, electric Customer Choice sales loss, regulatory deferrals, regulatory outcomes, economic conditions and operating costs.

Our non-utility businesses also provide sources of cash flow to the enterprise and reflect a range of operating profiles. The profiles vary from our synthetic fuels business, which we believe will provide over $1.6 billion in cash through 2008, to new start-ups. These new start-ups include our unconventional gas and waste coal recovery businesses, which we are growing and, if successful, could require significant investments.

Although DTE Energy’s overall earnings were $431 million in 2004, cash from operations totaling $995 million was up $45 million from the comparable 2003 period. The operating cash flow comparison reflects an increase of over $300 million in net income, after adjusting for non-cash items (depreciation, depletion, amortization, deferred taxes and gains), substantially offset by a $259 million increase in working capital and other requirements. A portion of this improvement is attributable to the change in our strategy to primarily produce synfuel from plants in which we have sold interests. As previously discussed, synfuel projects generate operating losses, which have been more than offset by tax credits that we have been unable to fully utilize, thereby negatively affecting operating cash flow. Cash for working capital primarily reflects higher income tax payments of $172 million in 2004, reflecting a different payment pattern of taxes in 2004 compared to 2003. The increase in working capital was mitigated by Company initiatives to improve cash flow, including better inventory management, cash sales transactions, deferral of retirement plan contributions and the utilization of letters of credit. Certain cash initiatives in 2003 lowered cash flow in 2004.

Our net operating cash flow in 2003 was $950 million, reflecting a $46 million decline from 2002. The decrease was attributable to lower utility net income, after adjusting for non-cash items. Partially offsetting the declines were lower working capital and other requirements reflecting Company initiatives to improve cash flow and optimize synfuel operations. The improvement in 2003 working capital was achieved despite a $222 million contribution to our pension plans.

Outlook – We expect cash flow from operations to increase over the long-term primarily due to improvements from utility rate increases and the sales of interests in our synfuel projects. This will be partially offset by higher cash requirements, primarily within our gas storage business. We are continuing our efforts to identify opportunities to improve cash flow through cash improvement initiatives.

Operating cash flow from our utilities is expected to increase in 2005, but will be affected by the level of sales migration under the electric Customer Choice program and the ability of the MPSC within the regulatory processes to put in place a Customer Choice program that has sound economic fundamentals. In addition, the Customer Choice program’s impact will also be determined by the success of the Company in addressing certain structural flaws within additional regulatory proceedings and the legislative process.

Another factor affecting utility cash flows is the degree and timing of rate relief within the electric and gas rate cases. Based on the final and interim orders issued by the MPSC in 2004, approximately $50 million of additional revenues were realized in the 2004 calendar year. Due to the structure of the interim and final rate orders, we will not realize the full benefits of interim and final rate relief until 2006 when all customer rate caps expire.

Improvements in cash flow from our utilities are also expected from better management of our working capital requirements, including the continued focus on reducing past due accounts receivable. Our emphasis in these businesses will continue to be centered around cash generation and conservation.

Cash flows from our synfuel business are expected to total approximately $1.6 billion between 2005 and 2008. The redeployment of this cash represents a unique opportunity to increase shareholder value and strengthen our balance sheet. We expect to use this cash to reduce debt, to continue to pursue growth investments that meet our strict risk-return and value creation criteria and to potentially repurchase common stock if adequate investment opportunities are not available. Our objectives for cash redeployment are to strengthen the balance sheet and coverage ratios in order to improve our current credit ratings and outlook, and to more than replace the value of synfuels.

Cash flows from our synfuel business are expected to approximate $400 million in 2005. The source of synfuel cash flow includes cash from operations (excluding certain working capital changes), asset sales, and the utilization of Section 29 tax credits carried forward from synfuel production prior to 2004.

Our other operating non-utility businesses are expected to contribute approximately $400 million through 2008. Remaining start-up businesses such as unconventional gas production, waste coal recovery and distributed generation will continue to use cash in excess of their cash generation over the next couple of years while they are being further developed. Certain of the previously discussed cash initiatives resulted in accelerating the receipt of cash in 2004, which will have the impact of lowering cash flow in 2005.

Cash from Investing Activities

Cash inflows associated with investing activities are primarily generated from the sale of assets. In any given year, we will look to harvest cash from under-performing or non-strategic assets. Capital spending within the utility business is primarily to maintain our generation and distribution infrastructure, comply with environmental regulations and gas pipeline replacements. Capital spending within our non-utility businesses is for ongoing maintenance and some 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 invest tentatively based on research and analysis. Based on 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 relating to investing activities declined $691 million in 2004 and improved $1.1 billion in 2003, compared to the prior year. The changes were primarily due to proceeds received in 2003 totaling $758 million from the sale of ITC, interests in three synfuel projects and non-strategic assets. Additionally, the changes are due to variations in cash contractually designated for debt service.

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

Cash from Financing Activities

We rely on both short-term borrowings and longer-term financings as a source of funding for our capital requirements not satisfied by the Company’s operations. Short-term borrowings, which are mostly in the form of commercial paper borrowings, provide us with the liquidity needed on a daily basis. Our commercial paper program is supported by our unsecured credit facilities.

DTE Energy and its subsidiaries have a total of $1.675 billion in credit facilities, which provide liquidity to our commercial paper programs and support the use of letters of credit.


(in Millions)
Issuing Entity	Facility Amount		Maturity Date

DTE Energy	$	375.00		5/5/2006
DTE Energy		175.00		10/24/2006
DTE Energy		525.00		10/15/2009
Detroit Edison		68.75		10/24/2006
Detroit Edison		206.25		10/15/2009
MichCon		81.25		10/24/2006
MichCon		243.75		10/15/2009

	$	1,675.00

Borrowings under the facilities are available at prevailing short-term interest rates. The agreements require each of the Companies to maintain a debt to total capitalization ratio of no more than .65 to l and an “earnings before interest, taxes, depreciation and amortization” (EBITDA) to interest ratio of no less than 2 to 1. DTE Energy has significant room under these provisions, with coverage totaling 4.3 to 1 and leverage at .489 to 1 at December 31, 2004. The Companies are currently in compliance with these financial covenants. Should either Detroit Edison or MichCon have delinquent debt obligations of at least $25 million to any creditor, such delinquency will be considered a default under DTE Energy’s credit agreements. These agreements have standard material adverse change (MAC) clauses, however, the agreements expiring in October 2009 include a provision that the MAC clause does not apply when borrowings are made to repay maturing commercial paper.

Additionally, Detroit Edison has a $200 million short-term financing agreement secured by customer accounts receivable. The agreement contains certain covenants related to the delinquency of accounts receivable. Detroit Edison is currently in compliance with these covenants.

For additional information see Note 10 — Short-Term Credit Arrangements and Borrowings.

Our strategy is to have a targeted debt portfolio blend as to fixed and variable interest rates and maturity. We continually evaluate our leverage target, which is currently 50% or lower, to ensure it is consistent with our objective to have a strong investment grade debt rating. 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. The extension of the average maturity was accomplished at interest rates that lowered our debt costs.

Net cash used for financing activities improved $727 million in 2004 and declined $1.0 billion in 2003, compared to the prior periods. The 2004 change was primarily due to higher issuances of new long and short-term debt and fewer repurchases of long-term debt. The 2003 change was due to higher redemptions of long-term debt and lower proceeds from issuances of new debt and common stock. For additional information on debt issuances and redemptions, see Note 9 — Long-Term Debt and Preferred Securities.

Amounts available under shelf registrations include $500 million at DTE Energy and $150 million at Detroit Edison. MichCon does not have current shelf capacity. In 2005, we plan on filing new shelf registration statements for MichCon and Detroit Edison.

Common stock issuances or repurchases can also be a source or use of cash. In January 2005, we announced the DTE Energy Board has authorized the repurchase of up to $700 million in common stock through 2008. The authorization provides Company management with flexibility to pursue share repurchases from time to time, and will depend on future cash flows and investment opportunities. In January 2005, we discontinued issuing new DTE Energy shares for our dividend reinvestment plan, which generated approximately $50 million annually. We also contributed $170 million of DTE Energy common stock to our pension plan in the first quarter of 2004.

Contractual Obligations

The following table details our contractual obligations for debt redemptions, leases, purchase obligations and other long-term obligations as of December 31, 2004:



			Less
(in Millions)			Than						After
Contractual Obligations	Total		1 Year		1-3 Years		4-5 Years		5 Years
Long-term debt:

Mortgage bonds, notes & other	$	6,091	$	410	$	1,224	$	759	$	3,698
Securitization bonds		1,496		96		335		272		793
Equity-linked securities		178		5		173		—		—
Trust preferred-linked securities		289		—		—		—		289
Capital lease obligations		94		11		34		20		29
Interest		6,346		494		1,280		726		3,846
Operating leases		623		64		143		75		341
Electric, gas, fuel, transportation & storage purchase obligations*		6,130		3,694		1,601		236		599
Other long-term obligations		357		97		151		37		72


Total Obligations	$	21,604	$	4,871	$	4,941	$	2,125	$	9,667

Excludes amounts associated with full requirements contracts where no stated minimum purchase volume is required.

Credit Ratings

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and not a recommendation to buy, sell or hold securities. Management believes that the current credit ratings of the Company provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to DTE

Energy may affect the Company’s ability to access these funding sources or cause an increase in the return required by investors.

In November 2004, Moody’s Investors Service and Fitch Ratings downgraded MichCon. In December 2004, Standard & Poor’s downgraded DTE Energy, Detroit Edison and MichCon. The ratings reflect weaker credit metrics due to decreased cash flows mainly stemming from increased operation and maintenance costs without sufficient regulatory relief. Additional unfavorable changes in our ratings could restrict our ability to access capital markets at attractive rates and increase our borrowing costs.

We have issued guarantees for the benefit of various non-utility subsidiaries. In the event that our credit rating is downgraded to below investment grade, certain of these guarantees would require us to post cash or letters of credit valued at approximately $356 million at December 31, 2004. Additionally, our trading business could be required to restrict operations and our access to the short-term commercial paper market could be restricted or eliminated. While we currently do not anticipate such a downgrade, we cannot predict the outcome of current or future reviews. The following table shows our credit rating as determined by three nationally respected credit rating agencies. All ratings are considered investment grade and affect the value of the related securities.




		Credit Rating Agency
		Standard &	Moody’s	Fitch
Entity	Description	Poor’s	Investors Service	Ratings
DTE Energy	Senior Unsecured Debt	BBB-	Baa2 *	BBB
	Commercial Paper	A-2	P-2 *	F2

Detroit Edison	Senior Secured Debt	BBB+	A3 *	A-
	Commercial Paper	A-2	P-2 *	F2

MichCon	Senior Secured Debt	BBB	A3	A-
	Commercial Paper	A-2	P-2	F2

* Currently on negative outlook

CRITICAL ACCOUNTING ESTIMATES

There are estimates used in preparing the consolidated financial statements that require considerable judgment. Such estimates relate to regulation, risk management and trading activities, Section 29 tax credits, goodwill, pension and postretirement costs, the allowance for doubtful accounts, and legal and tax reserves.

Regulation

A significant portion of our business is subject to regulation. Detroit Edison and MichCon currently meet the criteria of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” Application of this standard results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses. SFAS No. 71 requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Future regulatory changes or changes in the competitive environment could result in discontinuing the application of SFAS No. 71 for some or all of our businesses. If we were to discontinue the application of SFAS No. 71 on all our operations, we estimate that the extraordinary loss would be as follows:




(in Millions)
Utility
Detroit Edison*	$	(138	)
MichCon		(42	)
Total	$	(180	)

* Excludes securitized regulatory assets

Management believes that currently available facts support the continued application of SFAS No. 71 and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment (Note 4).

Risk Management and Trading Activities

All derivatives are recorded at fair value and shown as “Assets or liabilities from risk management and trading activities” in the consolidated statement of financial position. Risk management activities are accounted for in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Through December 2002, trading activities were accounted for in accordance with Financial Accounting Standards Board (FASB) Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Energy Trading and Risk Management Activities.” Effective January 2003, trading activities are accounted for in accordance with SFAS No. 133. See Note 2 — New Accounting Pronouncements.

The offsetting entry to “Assets or liabilities from risk management and trading activities” is to other comprehensive income or earnings depending on the use of the derivative, how it is designated and if it qualifies for hedge accounting. The fair values of derivative contracts were adjusted each reporting period for changes using market sources such as:

• published exchange traded market data

• prices from external sources

• price based on valuation models

Market quotes are more readily available for short duration contracts. Derivative contracts are only marked to market to the extent that markets are considered highly liquid where objective, transparent prices can be obtained. Unrealized gains and losses are fully reserved for transactions that do not meet this criterion.

Section 29 Tax Credits

We generate Section 29 tax credits from our synfuel, coke battery and biomass operations. We recognize earnings as tax credits are generated at our facilities in one of two ways. First, to the extent we generate credits to our own account, we recognize earnings through reduced tax expense. Second, to the extent we have sold an interest in our synfuel facilities to third parties, we recognize gains as synfuel is produced and sold, and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectibility is reasonably assured.

All Section 29 tax credits taken after 1997 are subject to audit by the IRS, however, all of our synthetic fuel facilities have received favorable private letter rulings from the IRS with respect to their operations. Audits of four of our synfuel facilities for the years 2001 and 2002 were successfully completed during 2004. One synfuel facility is currently under audit. If our Section 29 tax credits were disallowed in whole or in part as a result of an IRS audit, there could be a significant write-off of previously recorded earnings from such tax credits.

Tax credits generated by our facilities were $449 million in 2004, as compared to $387 million in 2003 and $351 million in 2002. The portion of tax credits generated for our own account were $38 million in 2004, as compared to $241 million in 2003 and $250 million in 2002, with the remaining credits generated allocated to third party partners. Outside firms assist us in assuring we operate in accordance with our private letter rulings and within the parameters of the law, as well as calculating the value of tax credits.

Goodwill

Certain of our business units have goodwill resulting from purchase business combinations (Notes 2 and 16). In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets,” each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In order to perform these impairment tests, we must determine the reporting unit’s fair value using valuation techniques, which use estimates of discounted future cash flows to be generated by the reporting unit. These cash flow valuations involve a number of estimates that require broad assumptions and significant judgment by management regarding future performance. To the extent estimated cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill, which would adversely impact our earnings.

As of December 31, 2004, our goodwill totaled $2.1 billion. The majority of our goodwill is allocated to our utility reporting units, with approximately $772 million allocated to the utility Energy Gas reporting unit. The value of the utility reporting units is significantly impacted by rate orders and the regulatory environment. The utility Energy Gas reporting unit is comprised primarily of MichCon. We have made certain cash flow assumptions for MichCon that are dependent upon the successful outcome of the outstanding gas rate case (Note 4). These assumptions may change when we receive a final rate order, which is expected during the first quarter of 2005.

Based on our 2004 goodwill impairment test, we determined that the fair value of our reporting units exceed their carrying value and no impairment existed. We will continue to monitor regulatory events, and evaluate their impact on our valuation assumptions and the carrying value of the related goodwill. While we believe our assumptions are reasonable, actual results may differ from our projections.

Pension and Postretirement Costs

Our costs of providing pension and postretirement benefits are dependent upon a number of factors, including rates of return on plan assets, the discount rate, the rate of increase in health care costs and the amount and timing of plan sponsor contributions.

We had pension costs for qualified pension plans of $81 million in 2004, $47 million in 2003, and pension income of $9 million in 2002. Postretirement benefits costs for all plans were $125 million in 2004, $118 million in 2003, and $70 million in 2002. Pension and postretirement benefits costs for 2004 is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on our plan assets of 9.0%. In developing our expected long-term rate of return assumption, we evaluated input from our consultants, including their review of asset class risk and return expectations as well as inflation assumptions. Projected returns are based on broad equity and bond markets. Our expected long-term rate of return on plan assets is based on an asset allocation assumption utilizing active investment management of 65% in equity markets, 28% in fixed income markets, and 7% invested in other assets. Because of market volatility, we periodically review our asset allocation and rebalance our portfolio when considered appropriate. Given market conditions, we believe 9.0% is a reasonable long-term rate of return on our plan assets. We will continue to evaluate our actuarial assumptions, including our expected rate of return, at least annually.

We base our determination of the expected return on qualified plan assets on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes changes in fair value in a systematic manner over a three-year period. Because of this method, the future value of assets

will be impacted as previously deferred gains or losses are recorded. We have unrecognized net gains due to the recent favorable performance of the financial markets. As of December 31, 2004, we had $63 million of cumulative gains that remain to be recognized in the calculation of the market-related value of assets.

The discount rate that we utilize for determining future pension and postretirement benefit obligations is based on a review of bonds that receive one of the two highest ratings given by a recognized rating agency. The discount rate determined on this basis has decreased from 6.25% at December 31, 2003 to 6.0% at December 31, 2004. Due to recent financial market performance, lower discount rates and increased health care trend rates, we estimate that our 2005 pension costs will approximate $96 million compared to $81 million in 2004 and our 2005 postretirement benefit costs will approximate $155 million compared to $125 million in 2004. In the last several years we have made modifications to the pension and postretirement benefit plans to mitigate the earnings impact of higher costs. Future actual pension and postretirement benefit costs will depend on future investment performance, changes in future discount rates and various other factors related to plan design. Additionally, future pension costs for Detroit Edison will be affected by a pension tracking mechanism, which was authorized by the MPSC in its November 2004 rate order. The tracking mechanism provides for the recovery or refunding of pension costs above or below the amount reflected in Detroit Edison’s base rates.

Lowering the expected long-term rate of return on our plan assets by 1.0% would have increased our 2004 qualified pension costs by approximately $24 million. Lowering the discount rate and the salary increase assumptions by 1.0% would have increased our pension costs for 2004 by approximately $8 million. Lowering the health care cost trend assumptions by 1.0% would have decreased our postretirement benefit service and interest costs for 2004 by approximately $17 million.

The market value of our pension and postretirement benefit plan assets has been affected by the financial markets. The value of our plan assets increased from $2.4 billion at December 31, 2002 to $2.9 billion at December 31, 2003. The value at December 31, 2004 increased to $3.3 billion. The investment performance returns and declining discount rates required us to recognize an additional minimum pension liability, an intangible asset and an entry to other comprehensive loss (shareholders’ equity) at December 2002, 2003 and 2004. The additional minimum pension liability and related accounting entries will be reversed on the balance sheet in future periods if the fair value of plan assets exceeds the accumulated pension benefit obligations. The recording of the minimum pension liability does not affect net income or cash flow.

Pension and postretirement costs and pension cash funding requirements may increase in future years without substantial returns in the financial markets. We made a $35 million cash contribution to the pension plan in 2002, a $222 million cash contribution in 2003 and a $170 million contribution to our pension plan in the form of DTE Energy common stock in 2004. We also contributed $33 million to the postretirement plans in 2002 and contributed $80 million to the postretirement plans in 2004. We did not contribute to the postretirement plans in 2003. We do not anticipate making a contribution to our qualified pension plans in 2005. At the discretion of management, we anticipate making a $0 to $40 million contribution to our postretirement plans in 2005.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act was signed into law. This Act provides for a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the benefit established by law. The effects of the subsidy on the measurement of net periodic postretirement benefit costs reduced costs by $16 million in 2004.

See Note 14 – Retirement Benefits and Trusteed Assets for a further discussion of our pension and postretirement benefit plans.

Allowance for Doubtful Accounts

We establish an allowance for doubtful accounts based upon factors surrounding the credit risk of specific customers, historical trends, economic conditions, age of receivables and other information. Higher customer bills due to increased gas prices, the lack of adequate levels of assistance for low-income customers and economic conditions have also contributed to the increase in past due receivables. As a result of these factors, our allowance for doubtful accounts increased in 2003 and 2004. We believe the allowance for doubtful accounts is based on reasonable estimates. However, failure to make continued progress in collecting our past due receivables would unfavorably affect operating results and cash flow.

Legal and Tax Reserves

We are involved in legal and tax proceedings, claims and litigation arising in the ordinary course of business. We regularly assess our liabilities and contingencies in connection with asserted or potential matters, and establish reserves when appropriate. Legal reserves are based upon management’s assessment of pending and threatened legal proceedings against the Company. Tax reserves are based upon management’s assessment of potential adjustments to tax positions taken. We regularly review ongoing tax audits and prior audit experience, in addition to current tax and accounting authority in assessing potential adjustments.

ENVIRONMENTAL MATTERS

Protecting the environment, as well as correcting past environmental damage, continues to be a focus of state and federal regulators. Legislation and/or rulemaking could further impact the electric utility industry including Detroit Edison. The Environmental Protection Agency (EPA) and the Michigan Department of Environmental Quality have aggressive programs to clean-up contaminated property.

Air - The EPA ozone transport and acid rain regulations and final new air quality standards relating to ozone and particulate air pollution will continue to impact us. Detroit Edison has spent approximately $580 million through December 2004 and estimates that it will spend up to $100 million in 2005. Detroit Edison estimates it will incur from $700 million to $1.3 billion of additional future capital expenditures over the next five to eight years to satisfy both existing and proposed new control requirements. Recovery of costs to be incurred through December 2004 was provided for in our November 2004 electric rate order. See Note 4 –Regulatory Matters.

The EPA has initiated enforcement actions against several major electric utilities citing violations of the Clean Air Act, asserting that older, coal-fired power plants have been modified in ways that would require them to comply with the more restrictive “new source” provisions of the Clean Air Act. Detroit Edison received and responded to information requests from the EPA on this subject. The EPA has not initiated proceedings against Detroit Edison. The United States District Court for the Southern District of Ohio Eastern Division issued a decision in August 2003 finding Ohio Edison Company in violation of the new source provisions of the Clean Air Act. If the Court’s decision is upheld, the electric utility industry could be required to invest substantial amounts on pollution control equipment. During the same month, however, a district court in a different division rendered a conflicting decision on the matter. On October 27, 2003, the EPA promulgated new rules, effective December 26, 2003, allowing repair, replacement or upgrade of production equipment without triggering source requirement controls if the cost of the parts and repairs do not exceed 20% of the replacement value of the equipment being upgraded. Such repairs will be considered routine maintenance, however any changes in emissions would be subject to existing pollution permit limits and other state and federal programs for pollutants. Several states and environmental organizations have challenged these regulations and, on December 24, 2003, were granted a stay until the U.S. Court of Appeals D.C. Circuit hears the arguments on the case. We cannot predict the future impact of this issue upon Detroit Edison.

Water - In July 2004, the EPA published final regulations establishing performance standards for reducing fish loss at existing power plant cooling water intake structures. These regulations require individual facility studies, and possible intake modifications that will be determined and implemented

over the next five to seven years. It is estimated that we will incur up to $50 million in additional capital expenditures for Detroit Edison.

Contaminated Sites - DTE Enterprises Inc. (MichCon and Citizens) owns, or previously owned, 18 former manufactured gas plant (MGP) sites. During the mid-1980’s, Enterprises conducted preliminary environmental investigations at former MGP sites, and some contamination related to the by-products of gas manufacturing was discovered at each site. Enterprises employed outside consultants to evaluate remediation alternatives and associated costs for these sites. As a result of these studies, Enterprises accrued a liability and a corresponding regulatory asset of $24 million. At December 31, 2004, the reserve balance was $24 million of which $4.5 million was classified as current. Our current estimates indicate that the previously accrued amounts are adequate to cover the costs of required remedial actions.

Detroit Edison conducted remedial investigations at contaminated sites, including two former MGP sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is approximately $8 million, which is expected to be incurred over the next several years. As a result of the investigation, Detroit Edison accrued approximately $8 million liability during 2004.

DTE ENERGY OPERATING SYSTEM AND DTE2

During 2002, we adopted the DTE Energy Operating System, which is the application of tools and operating practices that have resulted in operating efficiencies, inventory reductions and improvements in technology systems, among other enhancements. Operation and maintenance expenses benefited from our Company-wide initiative to pursue cost efficiencies and enhance operating performance. We expect continued cost containment efforts and process improvements.

In 2003, we began the implementation of DTE2, a Company-wide initiative to improve existing processes and to implement new core information systems including, finance, human resources, supply chain and work management. We expect to incrementally spend approximately $150 million to $175 million over the life of the project. We expect the benefits to outweigh this investment primarily from lower costs, faster business cycles, repeatable and optimized processes, enhanced internal controls, improvements in inventory management and reductions in system support costs.

We are in process of launching the first phase of our multi-year DTE2 project. Although our implementation plan includes detailed testing and contingency arrangements to ensure a smooth and successful transition, we can provide no assurance that complications will not arise that could interrupt our operations.

NEW ACCOUNTING PRONOUNCEMENTS

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

FAIR VALUE OF CONTRACTS

The following disclosures are voluntary and we believe provide enhanced transparency of the derivative activities and position of our Energy Trading & Marketing segment and our other businesses.

We use the criteria in Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted, to determine if certain contracts must be accounted for as derivative instruments. The rules for determining whether a contract meets the criteria for derivative accounting are numerous and complex. Moreover, significant judgment is required to determine whether a contract requires derivative accounting, and similar contracts can sometimes be accounted for differently. If a contract is accounted for as a derivative instrument, it is recorded in the

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

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

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

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

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

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

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

•   “Gas Production” represents derivative activity associated with our Michigan gas reserves. A substantial portion of the price risk associated with these reserves has been mitigated through 2013. Changes in the value of the hedges are recorded as Liabilities from Risk Management and Trading with an offset in other comprehensive income to the extent that the hedges are deemed effective. The amounts shown in the following tables exclude the value of the underlying gas reserves and the changes therein.

Roll-Forward of Mark to Market Energy Contract Net Assets

The following tables provide details on changes in our MTM net asset or (liability) position during 2004:




													Other
	Energy Marketing & Trading												Non-
	Proprietary			Structured			Economic						Trading
(in Millions)	Trading			Contracts			Hedges			Total			Activities			Total
MTM at December 31, 2003	$	10		$	17		$	(171	)	$	(144	)	$	(81	)	$	(225	)

Reclassed to realized upon settlement		(10	)		(10	)		89			69			42			111
Changes in fair value recorded to income		5			12			(20	)		(3	)		(12	)		(15	)
Amortization of option premiums		(2	)		—			—			(2	)		—			(2	)

Amounts recorded to unrealized income		(7	)		2			69			64			30			94
Amounts recorded in OCI (Note 1)		—			4			—			4			(78	)		(74	)
Option premiums paid and other		—			—			4			4			29			33

MTM at December 31, 2004	$	3		$	23		$	(98	)	$	(72	)	$	(100	)	$	(172	)

The following table provides a current and noncurrent analysis of Assets and Liabilities from Risk Management and Trading Activities as reflected in the Consolidated Statement of Financial Position as of December 31, 2004. Amounts that relate to contracts that become due within twelve months are classified as current and all remaining amounts are classified as noncurrent.




																Other
	Energy Marketing & Trading															Non-			Total
	Proprietary			Structured			Economic									Trading			Assets
(in Millions)	Trading			Contracts			Hedges			Eliminations			Totals			Activities			(Liabilities)
Current assets	$	48		$	115		$	150		$	(33	)	$	280		$	16		$	296
Noncurrent assets		18			44			82			(19	)		125			—			125

Total MTM assets		66			159			232			(52	)		405			16			421


Current liabilities		(45	)		(98	)		(204	)		33			(314	)		(55	)		(369	)
Noncurrent liabilities		(18	)		(38	)		(126	)		19			(163	)		(61	)		(224	)

Total MTM liabilities.		(63	)		(136	)		(330	)		52			(477	)		(116	)		(593	)


Total MTM net assets (liabilities)	$	3		$	23		$	(98	)	$	—		$	(72	)	$	(100	)	$	(172	)

Maturity of Fair Value of MTM Energy Contract Net Assets

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

The table below shows the maturity of our MTM positions:




												Total
(in Millions)										2008 and		Fair
Source of Fair Value	2005			2006			2007			Beyond		Value
Proprietary Trading	$	3		$	(2	)	$	2		$	—	$	3
Structured Contracts		17			4			1			1		23
Economic Hedges		(55	)		(27	)		(16	)		—		(98	)

Total Energy Marketing & Trading		(35	)		(25	)		(13	)		1		(72	)
Other Non-Trading Activities		(38	)		(51	)		(11	)		—		(100	)

Total	$	(73	)	$	(76	)	$	(24	)	$	1	$	(172	)

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

DTE Energy has commodity price risk arising from market price fluctuations in conjunction with the anticipated purchase of electricity to meet its obligations during periods of peak demand. We also are exposed to the risk of market price fluctuations on gas sale and purchase contracts, gas production and gas inventories. To limit our exposure to commodity price fluctuations, we have entered into a series of electricity and gas futures, forwards, option and swap contracts. Commodity price risk associated with our electric and gas utilities is limited due to the PSCR and GCR mechanisms (Note 1).

Our Energy Services and Biomass businesses are also subject to crude oil price risk. As previously discussed, the Section 29 tax credits generated by DTE Energy’s synfuel and biomass operations are subject to phase out if domestic crude oil prices reach certain levels.

See Note 12 – Financial and Other Derivative Instruments for further discussion.

Credit Risk

Bankruptcies

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

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

Energy Trading & CoEnergy Portfolio

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 December 31, 2004:




	Credit Exposure
	before Cash		Cash			Net Credit
(in Millions)	Collateral		Collateral			Exposure
Investment Grade (1)
A- and Greater	$	234	$	(2	)	$	232
BBB+ and BBB		191		(18	)		173
BBB-		17		—			17

Total Investment Grade		442		(20	)		422
Non-investment grade (2)		15		—			15
Internally Rated — investment grade (3)		78		(1	)		77
Internally Rated — non-investment grade (4)		2		—			2

Total	$	537	$	(21	)	$	516

(1)		This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s Investors 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 28% 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 less than 2% 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 9% 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 less than 1% of the 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 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 December 31, 2004, the Company has a floating rate debt to total debt ratio of approximately 11% (excluding securitized debt).

Foreign Currency Risk

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

Summary of Sensitivity Analysis

We performed a sensitivity analysis to calculate the fair values of our commodity contracts, long-term debt instruments and foreign currency forward contracts. The sensitivity analysis involved increasing and decreasing forward rates at December 31, 2004 by a hypothetical 10% and calculating the resulting change in the fair values of the commodity, debt and foreign currency agreements.

The following consolidated financial statements and schedules are included herein.



		Page
Controls and Procedures		65
Reports of Independent Registered Public Accounting Firm		66
Consolidated Statement of Operations		69
Consolidated Statement of Financial Position		70
Consolidated Statement of Cash Flows		72
Consolidated Statement of Changes in Shareholders’ Equity and Comprehensive Income		73

Notes to Consolidated Financial Statements
Note 1	Significant Accounting Policies	74
Note 2	New Accounting Pronouncements	81
Note 3	Dispositions	83
Note 4	Regulatory Matters	84
Note 5	Nuclear Operations	93
Note 6	Jointly Owned Utility Plant	96
Note 7	Income Taxes	96
Note 8	Common Stock and Earnings Per Share	98
Note 9	Long-Term Debt and Preferred Securities	99
Note 10	Short-Term Credit Arrangements and Borrowings	102
Note 11	Capital and Operating Leases	102
Note 12	Financial and Other Derivative Instruments	103
Note 13	Commitments and Contingencies	106
Note 14	Retirement Benefits and Trusteed Assets	109
Note 15	Stock-based Compensation	116
Note 16	Segment and Related Information	118
Note 17	Supplementary Quarterly Financial Information	123

	Schedule II – Valuation and Qualifying Accounts	131

CONTROLS AND PROCEDURES

Controls and Procedures

See Item 8. Financial Statements and Supplementary Data for management’s evaluation of disclosure controls and procedures, its report on internal control over financial reporting, and its conclusion on changes in internal control over financial reporting.

(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 Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2004, 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 effectively designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

(b) Management’s report on internal control over financial reporting

The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control system was designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of the effectiveness to future periods are subject to the risks that control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, management believes that, as of December 31, 2004, the Company’s internal control over financial reporting was effective based on those criteria.

Our management’s assessment of the effectiveness of the Company’s internal control over financial reporting has been audited by the Company’s independent auditors, as stated in their report which is included herein.

(c) Changes in internal control over financial reporting

The Company has established a formal assessment process and related procedures to evaluate the effectiveness of internal control over financial reporting using criteria specified by COSO. The assessment process is comprehensive in scope, utilizes internal and external resources and involves many individuals at various levels of the Company in the design, testing and evaluation of internal control.

As part of the evaluation and assessment process, the Company has been improving the design and operating effectiveness of many entity-level and process-level controls. Control testing and remediation activities provide reasonable, but not absolute, assurance that a material weakness in internal control over financial reporting will be avoided. The inherent limitations of our current internal controls, a portion of which are manual by their nature, contribute to the potential for control deficiencies. Management does not believe any areas requiring further improvement constitute a material weakness in internal control over financial reporting as of December 31, 2004.

There has been no change in the Company’s internal control over financial reporting during the fourth quarter of 2004 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of DTE Energy Company:

We have audited management’s assessment, included in the accompanying Management Report on Internal Control Over Financial Reporting, that DTE Energy Company and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.

Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of December 31, 2004 and for the year then ended, and the financial statement schedule; and our report dated March 15, 2005 expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.

/S/ DELOITTE & TOUCHE LLP

Detroit, Michigan

March 15, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of DTE Energy Company:

We have audited the consolidated statement of financial position of DTE Energy Company and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, cash flows, and changes in shareholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of DTE Energy Company and subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements of the Company taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, in connection with the required adoption of certain new accounting principles, in 2003 the Company changed its method of accounting for asset retirement obligations, energy trading contracts and gas inventories and in 2002 the Company changed its method of accounting for goodwill and energy trading contracts.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 15, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/S/ DELOITTE & TOUCHE LLP

Detroit, Michigan

March 15, 2005

DTE Energy Company

Consolidated Statement of Operations


	Year Ended December 31
(in Millions, Except per Share Amounts)	2004			2003			2002
Operating Revenues	$	7,114		$	7,041		$	6,729


Operating Expenses
Fuel, purchased power and gas		2,007			2,241			2,099
Operation and maintenance		3,420			3,109			2,589
Depreciation, depletion and amortization		744			687			737
Taxes other than income		312			334			352
Asset gains and losses, net		(215	)		(77	)		(42	)

		6,268			6,294			5,735


Operating Income		846			747			994


Other (Income) and Deductions
Interest expense		518			546			569
Interest income		(55	)		(37	)		(29	)
Other income		(80	)		(110	)		(45	)
Other expenses		67			82			34

		450			481			529


Income Before Income Taxes and Minority Interest		396			266			465

Income Tax Provision (Benefit) (Note 7)		165			(123	)		(84	)

Minority Interest		(212	)		(91	)		(37	)


Income from Continuing Operations		443			480			586

Income (Loss) from Discontinued Operations, net of tax (Note 3)		(12	)		68			46

Cumulative Effect of Accounting Changes, net of tax (Note 2)		—			(27	)		—


Net Income	$	431		$	521		$	632


Basic Earnings per Common Share (Note 8)
Income from continuing operations	$	2.56		$	2.87		$	3.57
Discontinued operations		(.06	)		.41			.28
Cumulative effect of accounting changes		—			(.17	)		—

Total	$	2.50		$	3.11		$	3.85


Diluted Earnings per Common Share (Note 8)
Income from continuing operations	$	2.55		$	2.85		$	3.55
Discontinued operations		(.06	)		.40			.28
Cumulative effect of accounting changes		—			(.16	)		—

Total	$	2.49		$	3.09		$	3.83


Average Common Shares
Basic		173			168			164
Diluted		173			168			165

Dividends Declared per Common Share	$	2.06		$	2.06		$	2.06

See Notes to Consolidated Financial Statements

DTE Energy Company

Consolidated Statement of Financial Position


	December 31
	2004			2003
(in Millions)
ASSETS
Current Assets
Cash and cash equivalents	$	56		$	54
Restricted cash (Note 1)		126			131
Accounts receivable
Customer (less allowance for doubtful accounts of $129 and $99, respectively)		880			877
Accrued unbilled revenues		378			316
Other		383			338
Inventories
Fuel and gas		509			467
Materials and supplies		159			162
Assets from risk management and trading activities		296			186
Other		209			181

		2,996			2,712

Investments
Nuclear decommissioning trust funds		590			518
Other		558			601

		1,148			1,119

Property
Property, plant and equipment		18,011			17,679
Less accumulated depreciation and depletion (Note 2)		(7,520	)		(7,355	)

		10,491			10,324

Other Assets
Goodwill (Note 3)		2,067			2,067
Regulatory assets (Note 4)		2,119			2,063
Securitized regulatory assets (Note 4)		1,438			1,527
Notes receivable		529			469
Assets from risk management and trading activities		125			88
Prepaid pension assets		184			181
Other		200			203

		6,662			6,598

Total Assets	$	21,297		$	20,753

See Notes to Consolidated Financial Statements

DTE Energy Company
Consolidated Statement of Financial Position


	December 31
	2004			2003
(in Millions, Except Shares)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	892		$	625
Accrued interest		111			110
Dividends payable		90			87
Accrued payroll		33			51
Income taxes		16			185
Short-term borrowings		403			370
Current portion long-term debt, including capital leases		514			477
Liabilities from risk management and trading activities		369			326
Other		581			593

		3,009			2,824

Other Liabilities
Deferred income taxes		1,124			988
Regulatory liabilities (Notes 2 and 4)		817			817
Asset retirement obligations (Note 2)		916			866
Unamortized investment tax credit		143			156
Liabilities from risk management and trading activities		224			173
Liabilities from transportation and storage contracts		387			495
Accrued pension liability		265			345
Deferred gains from asset sales		414			311
Minority interest		132			156
Nuclear decommissioning (Notes 2 and 5)		77			67
Other		635			599

		5,134			4,973

Long-Term Debt (net of current portion) (Note 9)
Mortgage bonds, notes and other		5,673			5,624
Securitization bonds		1,400			1,496
Equity-linked securities		178			185
Trust preferred-linked securities		289			289
Capital lease obligations		66			75

		7,606			7,669


Commitments and Contingencies (Notes 4, 5 and 13)

Shareholders’ Equity
Common stock, without par value, 400,000,000 shares authorized, 174,209,034 and 168,606,522 shares issued and outstanding, respectively		3,323			3,109
Retained earnings		2,383			2,308
Accumulated other comprehensive loss		(158	)		(130	)

		5,548			5,287


Total Liabilities and Shareholders’ Equity	$	21,297		$	20,753

See Notes to Consolidated Financial Statements

DTE Energy Company

Consolidated Statement of Cash Flows


	Year Ended December 31
(in Millions)	2004			2003			2002
Operating Activities
Net income	$	431		$	521		$	632
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		744			691			759
Deferred income taxes		129			(220	)		(208	)
Gain on sale of interests in synfuel projects		(219	)		(83	)		(40	)
Gain on sale of ITC and other assets, net		(17	)		(145	)		—
Partners’ share of synfuel project losses		(223	)		(78	)		(40	)
Contributions from synfuel partners		141			65			22
Cumulative effect of accounting changes		—			27			—
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		9			172			(129	)

Net cash from operating activities		995			950			996


Investing Activities
Plant and equipment expenditures – utility		(815	)		(679	)		(794	)
Plant and equipment expenditures – non-utility		(89	)		(72	)		(190	)
Investment in joint ventures		(36	)		(34	)		(21	)
Proceeds from sale of interests in synfuel projects		221			89			32
Proceeds from sale of ITC and other assets		104			669			9
Restricted cash for debt redemptions		5			106			(79	)
Other investments		(71	)		(69	)		(72	)

Net cash from (used for) investing activities		(681	)		10			(1,115	)


Financing Activities
Issuance of long-term debt		736			527			1,138
Redemption of long-term debt		(759	)		(1,208	)		(793	)
Short-term borrowings, net		33			(44	)		(267	)
Issuance of common stock		41			44			265
Dividends on common stock		(354	)		(346	)		(338	)
Other		(9	)		(12	)		(21	)

Net cash used for financing activities		(312	)		(1,039	)		(16	)

Net Increase (Decrease) in Cash and Cash Equivalents		2			(79	)		(135	)
Cash and Cash Equivalents at Beginning of Period		54			133			268

Cash and Cash Equivalents at End of Period	$	56		$	54		$	133

See Notes to Consolidated Financial Statements

DTE Energy Company

Consolidated Statement of Changes in Shareholders’ Equity and Comprehensive Income


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

Balance, December 31, 2001		161,134		$	2,811		$	1,846		$	(68	)	$	4,589

Net income		—			—			632			—			632
Issuance of new shares		6,426			270			—			—			270
Dividends declared on common stock		—			—			(341	)		—			(341	)
Repurchase and retirement of common stock		(98	)		(1	)		(2	)		—			(3	)
Pension obligations (Note 14)		—			—			—			(518	)		(518	)
Net change in unrealized losses on derivatives, net of tax		—			—			—			(33	)		(33	)
Unearned stock compensation and other		—			(28	)		(3	)		—			(31	)

Balance, December 31, 2002		167,462			3,052			2,132			(619	)		4,565

Net income		—			—			521			—			521
Issuance of new shares		1,225			57			—			—			57
Dividends declared on common stock		—			—			(348	)		—			(348	)
Repurchase and retirement of common stock		(80	)		(1	)		—			—			(1	)
Pension obligations (Note 14)		—			—			—			420			420
Net change in unrealized losses on derivatives, net of tax		—			—			—			17			17
Net change in unrealized gains on investments, net of tax		—			—			—			52			52
Unearned stock compensation and other		—			1			3			—			4

Balance, December 31, 2003		168,607			3,109			2,308			(130	)		5,287
Net income		—			—			431			—			431
Issuance of new shares		5,671			223			—			—			223
Dividends declared on common stock		—			—			(357	)		—			(357	)
Repurchase and retirement of common stock		(69	)		(3	)		—			—			(3	)
Pension obligations (Note 14)		—			—			—			7			7
Net change in unrealized losses on derivatives, net of tax		—			—			—			(15	)		(15	)
Net change in unrealized losses on investments, net of tax		—			—			—			(20	)		(20	)
Unearned stock compensation and other		—			(6	)		1			—			(5	)

Balance, December 31, 2004		174,209		$	3,323		$	2,383		$	(158	)	$	5,548


The following table displays comprehensive income (loss):


(in Millions)	2004			2003		2002
Net income	$	431		$	521	$	632

Other comprehensive income (loss), net of tax:
Pension obligations, net of taxes of $(4), $(226) and $280 (Notes 4 and 14)		7			420		(518	)

Net unrealized losses on derivatives:
Gains (losses) arising during the period, net of taxes of $26, $(8) and $32		(49	)		16		(60	)
Amounts reclassified to earnings, net of taxes of $(18), $- and $(15)		34			1		27

		(15	)		17		(33	)

Net unrealized gains (losses) on investments:
Gains (losses) arising during the period, net of taxes of $3, $(28) and $-		(5	)		52		—
Amounts reclassified to earnings, net of taxes of $8, $- and $-		(15	)		—		—

		(20	)		52		—

Comprehensive income	$	403		$	1,010	$	81

See Notes to Consolidated Financial Statements

DTE Energy Company

Notes to Consolidated Financial Statements

NOTE 1 – SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure

DTE Energy is an exempt holding company under the Public Utility Holding Company Act of 1935 and owns the following businesses:

•   The Detroit Edison Company (Detroit Edison), an electric utility engaged in the generation, purchase, distribution and sale of electric energy to 2.1 million customers in southeast Michigan;

•   Michigan Consolidated Gas Company (MichCon), a natural gas utility engaged in the purchase, storage, transmission and distribution and sale of natural gas to 1.2 million customers throughout Michigan; and

•   Other non-utility subsidiaries engaged in energy marketing and trading, energy services and various other electricity, coal and gas related businesses.

Detroit Edison and MichCon are regulated by the Michigan Public Service Commission (MPSC). The Federal Energy Regulatory Commission (FERC) regulates certain activities of Detroit Edison’s business as well as various other aspects of businesses under DTE Energy. In addition, we are regulated by other federal and state regulatory agencies including the Nuclear Regulatory Commission (NRC) and the Environmental Protection Agency, among others.

Segments realigned – Through 2004, we operated our businesses through three strategic business units (Energy Resources, Energy Distribution and Energy Gas). Each business unit had utility and non-utility operations. The balance of our business consisted of Corporate & Other. See Note 16 for further discussion. In 2005, we expect to realign our business units to strengthen the Company’s focus on customer relationships and growth within our non-utility businesses. Based on this structure, we will set strategic goals, allocate resources and evaluate performance. Beginning with the first quarter of 2005, we expect to report our segment information based on the following realignment:

•   Electric Utility, consisting of Detroit Edison;

•   Gas Utility, primarily consisting of MichCon;

•   Non-utility Operations

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

•   Unconventional Gas Production, primarily consisting of gas production and coal bed methane operations;

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

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

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

Principles of Consolidation

We consolidate all majority owned subsidiaries and investments in entities in which we have controlling influence. Non-majority owned investments are accounted for using the equity method when the company is able to influence the operating policies of the investee. Non-majority owned investments include investments

in limited liability companies, partnerships or joint ventures. When we do not influence the operating policies of an investee, the cost method is used. We eliminate all intercompany balances and transactions.

For entities that are considered variable interest entities, we apply the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46-R, “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51.” For a detailed discussion of FIN 46-R, see Note 2 – New Accounting Pronouncements.

Basis of Presentation

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

Prior to December 2004, DTE Energy did not eliminate amounts, principally within Other Income and Other Deductions, resulting from certain intercompany transactions. The amounts of the transactions are immaterial and had no effect on net income. Previously reported prior period amounts have been adjusted to eliminate those intercompany transactions and are now consistent with the current year’s presentation. We reclassified certain other prior year balances to match the current year’s financial statement presentation.

Revenues

Revenues from the sale and delivery of electricity, and the sale, delivery and storage of natural gas are recognized as services are provided. Detroit Edison and MichCon record revenues for electric and gas provided but unbilled at the end of each month.

Detroit Edison’s accrued revenues include a component for the cost of power sold that is recoverable through the Power Supply Cost Recovery (PSCR) mechanism. MichCon’s accrued revenues include a component for the cost of gas sold that is recoverable through the Gas Cost Recovery (GCR) mechanism. Annual PSCR and GCR proceedings before the MPSC permit Detroit Edison and MichCon to recover prudent and reasonable supply costs. Any overcollection or undercollection of costs, including interest, will be reflected in future rates. Prior to 2004, Detroit Edison’s retail rates were frozen under Public Act (PA) 141. See Note 4 for further discussion. Accordingly, Detroit Edison did not accrue revenues under the PSCR mechanism prior to 2004.

Non-utility businesses recognize revenues as services are provided and products are delivered. Our Energy Marketing & Trading segment records in revenues net unrealized derivative gains and losses on energy trading contracts, including those to be physically settled.

Gains from Sale of Interests in Synthetic Fuel Facilities

Through December 2004, we have sold majority interests in eight of our nine synthetic fuel production plants, representing approximately 92% of our total production capacity. Proceeds from the sales are contingent upon production levels and the value of Section 29 tax credits. Section 29 tax credits are subject to phase out if domestic crude oil prices reach certain levels. See Note 13 for further discussion. We recognize gains from the sale of interests in the synfuel facilities as synfuel is produced and sold, and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectibility is reasonably assured. We have recorded gains from the sale of interests in synthetic fuel facilities totaling $219 million, $83 million and $40 million during 2004, 2003 and 2002, respectively.

Until the gain recognition criteria are met, gains from selling interests in synfuel facilities will be deferred. It is possible that gains will be deferred in the first, second and/or third quarters of each year until there is persuasive evidence that no tax credit phase out will occur for the applicable calendar year. This could result in shifting earnings from earlier quarters to later quarters of a calendar year.

Comprehensive Income

We comply with Statement of Financial Accounting Standards (SFAS) No. 130, “Reporting Comprehensive Income,” that established standards for reporting comprehensive income. SFAS No. 130 defines comprehensive income as the change in common shareholders’ equity during a period from transactions and events from non-owner sources, including net income. As shown in the following table, amounts recorded to other comprehensive income (OCI) at December 31, 2004 include: unrealized gains and losses from derivatives accounted for as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities;” unrealized gains and losses on available for sale securities under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities;” and, minimum pension liabilities as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions.”


	Minimum			Net			Net			Accumulated
	Pension			Unrealized			Unrealized			Other
	Liability			Losses on			Gains on			Comprehensive
(in Millions)	Adjustment			Derivatives			Investments			Loss
Beginning balance	$	(98	)	$	(85	)	$	53		$	(130	)
Current-period change		7			(15	)		(20	)		(28	)

Ending balance	$	(91	)	$	(100	)	$	33		$	(158	)

Cash Equivalents and Restricted Cash

Cash and cash equivalents include cash on hand, cash in banks and temporary investments with remaining maturities of three months or less. Restricted cash consists of funds held to satisfy requirements of certain debt and partnership operating agreements. Restricted cash is classified as a current asset as all restricted cash is designated for interest and principal payments due within one year.

Inventories

We value fuel inventory and materials and supplies at average cost.

Gas inventory at MichCon is determined using the last-in, first-out (LIFO) method. At December 31, 2004, the replacement cost of gas remaining in storage exceeded the $89 million LIFO cost by $330 million. At December 31, 2003, the replacement cost of gas remaining in storage exceeded the $117 million LIFO cost by $251 million. During 2004, MichCon liquidated 5.7 billion cubic feet of prior years’ LIFO layers. The liquidation benefited 2004 cost of gas by approximately $7 million, but had no impact on earnings as a result of the GCR mechanism.

Our Energy Marketing & Trading segment uses the average cost method for its gas in inventory.

Property, Retirement and Maintenance, and Depreciation and Depletion


Summary of property by classification as of December 31:


(in Millions)	2004			2003
Property, Plant and Equipment
Electric Utility
Generation	$	7,100		$	6,938
Distribution		5,831			5,733

Total Electric Utility		12,931			12,671


Gas Utility
Distribution		2,020			1,961
Storage		221			224
Other		883			855

Total Gas Utility		3,124			3,040


Energy Services
Coal Based Fuels		651			652
On-Site Energy		193			180
Merchant Generation		174			229
Other		8			13

Total Energy Services		1,026			1,074


Other Non-utility and Other		930			894

Total Property, Plant and Equipment		18,011			17,679


Less Accumulated Depreciation and Depletion
Electric Utility
Generation		(3,277	)		(3,231	)
Distribution		(2,077	)		(2,108	)

Total Electric Utility		(5,354	)		(5,339	)


Gas Utility
Distribution		(845	)		(798	)
Storage		(100	)		(102	)
Other		(448	)		(432	)

Total Gas Utility		(1,393	)		(1,332	)


Energy Services
Coal Based Fuels		(272	)		(219	)
On-Site Energy		(55	)		(42	)
Merchant Generation		(18	)		(20	)
Other		(3	)		(2	)

Total Energy Services		(348	)		(283	)


Other Non-utility and Other		(425	)		(401	)

Total Accumulated Depreciation and Depletion		(7,520	)		(7,355	)

Net Property, Plant and Equipment	$	10,491		$	10,324

Property is stated at cost and includes construction-related labor, materials, overheads and an “allowance for funds used during construction” (AFUDC). The cost of properties retired, less salvage, at Detroit Edison and MichCon are charged to accumulated depreciation.

Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2. Approximately $3.8 million of expenses related to the anticipated Fermi 2 refueling outage scheduled for 2006 were accrued at December 31, 2004. Amounts are being accrued on a pro-rata basis over an 18-month period that began in November 2004. We have utilized the accrue-in-advance policy for nuclear refueling outage costs since the Fermi 2 plant was placed in service in 1988. This method also matches the regulatory recovery of these costs in rates set by the MPSC.

We base depreciation provisions for utility property at Detroit Edison and MichCon on straight-line and units of production rates approved by the MPSC. The composite depreciation rate for Detroit Edison was 3.4% in 2004, 2003 and 2002. The composite depreciation rate for MichCon was 3.6%, 3.5%, and 3.6% in 2004, 2003 and 2002, respectively.

The average estimated useful life for each class of utility property, plant and equipment as of December 31, 2004 follows:

Estimated Useful Lives in Years

Utility

Generation

Distribution

Transmission

Electric

—

Gas

N/A

Non-utility property is depreciated over its estimated useful life using straight-line, declining-balance or units-of-production methods.

We credit depreciation, depletion and amortization expense when we establish regulatory assets for stranded costs related to the electric Customer Choice program and deferred environmental expenditures.

Gas Production

We follow the successful efforts method of accounting for investments in gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well are expensed. The costs of development wells are capitalized, whether productive or nonproductive. Geological and geophysical costs on exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. An impairment loss is recorded to the extent that capitalized costs of unproved properties, on a property-by-property basis, are considered not to be realizable. An impairment loss is recorded if the net capitalized costs of proved gas properties exceed the aggregate related undiscounted future net revenues. Depreciation, depletion and amortization of proved gas properties are determined using the units-of-production method.

Long-Lived Assets

Our long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. If the carrying amount of the asset exceeds the expected future cash flows generated by the asset, an impairment loss is recognized resulting in the asset being written down to its estimated fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less cost to sell.

Intangible Assets, Including Software Costs

Our intangible assets consist primarily of software. We capitalize the costs associated with computer software we develop or obtain for use in our business. We amortize intangible assets on a straight-line basis over expected periods of benefit. Intangible assets amortization expense was $43 million in 2004, $40 million in 2003 and $46 million in 2002. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2004 were $445 million and $151 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2003 were $537 million and $303 million,

respectively. Amortization expense of intangible assets is estimated to be $40 million annually for 2005 through 2009.

Excise and Sales Taxes

We record the billing of excise and sales taxes as receivable with an offsetting payable to the applicable taxing authority, with no impact on the consolidated statement of operations.

Deferred Debt Costs

The costs related to the issuance of long-term debt are deferred and amortized over the life of each debt issue. In accordance with MPSC regulations applicable to our electric and gas utilities, the unamortized discount, premium and expense related to debt redeemed with a refinancing are amortized over the life of the replacement issue. Discount, premium and expense on early redemptions of debt associated with non-utility operations are charged to earnings.

Insured and Uninsured Risks

We have a comprehensive insurance program in place to provide coverage for various types of risks. Our insurance policies cover risk of loss from various events, including property damage, general liability, workers’ compensation, auto liability and directors’ and officers’ liability.

Under our risk management policy, we self-insure portions of certain risks up to specified limits, depending on the type of exposure. We periodically review our insurance coverage. During 2003, we reviewed our process for estimating and recognizing reserves for self-insured risks. As a result of this review, we revised the process for estimating liabilities under our self-insured layers to include an actuarially determined estimate of “incurred but not reported” (IBNR) claims. We have an actuarially determined estimate of our IBNR liability prepared annually and adjust the related reserve as appropriate.

Stock-Based Compensation

We have a stock-based employee compensation plan, which is described in Note 15. The plan permits the awarding of various stock awards, including options, restricted stock and performance shares. We account for stock awards under the plan under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” No compensation cost related to stock options is reflected in earnings, as all options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. The recognition provisions under SFAS No. 123, “Accounting for Stock-Based Compensation,” require the recording of compensation expense for stock options equal to their fair value at date of grant as determined using an option pricing model. The following table illustrates the effect on net income and earnings per share if we had recorded compensation expense for options granted under the fair value recognition provisions of SFAS No. 123.


(in Millions, except per share amounts)	2004			2003			2002
Net Income as Reported	$	431		$	521		$	632
Less: Total Stock-based Expense (1)		(6	)		(7	)		(7	)

Pro Forma Net Income	$	425		$	514		$	625


Income Per Share
Basic – as reported	$	2.50		$	3.11		$	3.85

Basic – pro forma	$	2.46		$	3.06		$	3.81


Diluted – as reported	$	2.49		$	3.09		$	3.83

Diluted – pro forma	$	2.45		$	3.05		$	3.79

(1)

Expense determined using a Black-Scholes based option pricing model.

Investments in Debt and Equity Securities

We generally classify investments in debt and equity securities as either trading or available-for-sale and have recorded such investments at market value with unrealized gains or losses included in earnings or in other comprehensive income or loss, respectively. Changes in the fair value of nuclear decommissioning-related investments are recorded as adjustments to regulatory assets or liabilities (Note 5).

Investment in Plug Power

In 1997, we invested in Plug Power Inc., a company that designs and develops on-site electric fuel cell power generation systems. Since Plug Power is considered a development stage company, generally accepted accounting principles required us to record gains and losses from Plug Power stock issuances as an adjustment to equity. Prior to November 2003, we accounted for our investment in Plug Power under the equity method of accounting. We did not participate in Plug Power’s secondary stock offering in November 2003 and as of December 31, 2003 we owned 14.1 million shares or approximately 19% of Plug Power’s common stock. We have determined that we do not have the ability to exercise significant influence over the operating or financial policies of Plug Power. Accordingly, we began prospective application of the cost method of accounting for our investment in Plug Power, effective November 2003. We record our investment at market value and account for unrealized gains and losses in other comprehensive income or loss. In May 2004, we sold 3.5 million shares of Plug Power stock and recorded a gain of approximately $14 million, net of taxes. The sale reduced our ownership interest in Plug Power to 10.6 million shares, or approximately 14%.

Consolidated Statement of Cash Flows

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


	2004			2003			2002
(in Millions)
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	73		$	(50	)	$	(129	)
Accrued unbilled receivable		(62	)		(20	)		(54	)
Accrued GCR revenue		(35	)		29			(5	)
Inventories		(40	)		(61	)		(71	)
Accrued/Prepaid Pensions		88			(196	)		(10	)
Accounts payable		266			(21	)		66
Accrued PSCR refund		112			—			—
Exchange gas payable		(43	)		90			9
Income taxes payable		(170	)		135			(8	)
General taxes		(14	)		(12	)		(36	)
Risk management and trading activities		(64	)		127			69
Postretirement obligation		29			112			77
Other		(131	)		39			(37	)

	$	9		$	172		$	(129	)

Supplementary cash and non-cash information for the years ended December 31 were as follows:


	2004		2003		2002
(in Millions)
Cash Paid for
Interest (excluding interest capitalized)	$	517	$	552	$	551
Income taxes	$	203	$	31	$	167

Noncash Investing and Financing Activities
Notes received from sale of synfuel projects	$	214	$	238	$	217
Common stock contributed to pension plan	$	170	$	—	$	—
Exchange of debt	$	—	$	100	$	—
Issuance of equity-linked securities	$	—	$	—	$	21

See the following notes for other accounting policies impacting our financial statements:


Note		Title

2		New Accounting Pronouncements
4		Regulatory Matters
7		Income Taxes
12		Financial and Other Derivative Instruments
14		Retirement Benefits and Trusteed Assets

NOTE 2 – NEW ACCOUNTING PRONOUNCEMENTS

Energy Trading Activities

Under Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” companies were required to use mark-to-market accounting for contracts utilized in energy trading activities. EITF Issue No. 98-10 was rescinded in October 2002, and energy trading contracts must now be reviewed to determine if they meet the definition of a derivative under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133 requires all derivatives to be recognized in the statement of financial position as either assets or liabilities measured at their fair value. SFAS No. 133 also requires that changes in the fair value of derivatives be recognized in earnings unless specific hedge accounting criteria are met. Energy trading contracts not meeting the definition of a derivative are accounted for under settlement accounting, effective October 25, 2002 for new contracts and effective January 1, 2003 for existing contracts. Derivative contracts are only marked to market to the extent that markets are considered highly liquid where objective, transparent prices can be obtained. Unrealized gains and losses are fully reserved for transactions that do not meet this criteria.

Additionally, inventory utilized in energy trading activities accounted for under the fair value method of accounting as prescribed by Accounting Research Bulletin (ARB) No. 43 is no longer permitted. Our Energy Marketing & Trading segment uses gas inventory in its trading operations and switched from the fair value method to the average cost method in January 2003.

Effective January 1, 2003, we no longer applied EITF Issue No. 98-10 to energy contracts and ARB No. 43 to gas inventory. As a result of discontinuing the application of these accounting principles, we recorded a cumulative effect of accounting change that reduced net income for the first quarter of 2003 by $16 million (net of taxes of $9 million).

Asset Retirement Obligations

On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred. We identified a legal retirement obligation for the decommissioning costs for our Fermi 1 and 2 nuclear plants. To a lesser extent, we have retirement obligations for our synthetic fuel operations, gas production facilities, asphalt plant, gas gathering facilities and various other operations. As to utility operations, we believe that adoption of SFAS No. 143 results primarily in timing differences in the recognition of legal asset retirement costs that we are currently recovering in rates and are deferring such differences under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.”

As a result of adopting SFAS No. 143 on January 1, 2003, we recorded a plant asset of $306 million with offsetting accumulated depreciation of $106 million, a retirement obligation liability of $815 million and reversed previously recognized obligations of $377 million, principally nuclear decommissioning liabilities. We also recorded a cumulative effect amount related to utility operations as a regulatory asset of $221 million, and a cumulative effect charge against earnings of $11 million (net of tax of $7 million) for 2003.

If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, such as assets with an indeterminate life, the liability is to be recognized when a reasonable estimate of fair value can be made. Generally, distribution assets have an indeterminate life, retirement cash flows cannot be determined and there is a low probability of retirement, therefore no liability has been recorded for these assets.

The pro forma effect on earnings had SFAS No. 143 been adopted for all periods presented would decrease reported net income and basic and diluted earnings per share as follows:


	(in Millions)
	Net		Basic and Diluted
Year	Income		Earnings per Share
2002	$	4.8	$	.03

A reconciliation of the asset retirement obligation for 2004 follows:


(in Millions)
Asset retirement obligations at January 1, 2004	$	866
Accretion		57
Liabilities settled		(5	)
Revisions in estimated cash flows		(2	)

Asset retirement obligations at December 31, 2004	$	916

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

SFAS No. 143 also requires the quantification of the estimated cost of removal obligations, arising from other than legal obligations, which have been accrued through depreciation charges. At December 31, 2003, we reclassified approximately $655 million of previously accrued asset removal costs related to our utility operations, which had been previously netted against accumulated depreciation to regulatory liabilities. There is a generic case before the MPSC to determine the accounting and regulatory treatment of removal costs for Michigan utilities.

Consolidation of Variable Interest Entities

In January 2003, FASB Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin (ARB) No. 51,” was issued and requires an investor with a majority of the variable interests (primary beneficiary) in a variable interest entity to consolidate the assets, liabilities and results of operations of the entity. A variable interest entity is an entity in which the equity investors do not have controlling interests, the equity investment at risk is insufficient to finance the entity’s activities without receiving additional subordinated financial support from other parties, or equity investors do not share proportionally in gains or losses.

In October 2003 and December 2003, the FASB issued Staff Position No. FIN 46-6 and FIN 46-Revised (FIN 46-R), respectively, which clarified and replaced FIN 46 and also provided for the deferral of the effective date of FIN 46 for certain variable interest entities. We have evaluated all of our equity and non-equity interests and have adopted all current provisions of FIN 46-R. The adoption of FIN 46-R did not have a material effect on our financial statements.

Medicare Act Accounting

In December 2003, the “Medicare Prescription Drug, Improvement and Modernization Act of 2003” (Medicare Act) was signed into law. The Medicare Act provides for a non-taxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least “actuarially equivalent” to the benefit established by law. We elected at that time to defer the provisions of the Medicare Act, and its impact on our accumulated postretirement benefit obligation and net periodic postretirement benefit cost, pending the issuance of specific authoritative accounting guidance by the FASB.

In May 2004, FASB Staff Position (FSP) No. 106-2 was issued on accounting for the effects of the Medicare Act. The guidance in this FSP is applicable to sponsors of single-employer defined benefit postretirement health care plans for which (a) the employer has concluded the prescription drug benefits available under the plan to some or all participants are “actuarially equivalent” to Medicare Part D and thus qualify for the subsidy under the Medicare Act and (b) the expected subsidy will offset or reduce the employer’s share of the cost of the underlying postretirement prescription drug coverage on which the subsidy is based. We believe we qualify for the subsidy under the Medicare Act and the expected subsidy will partially offset our share of the cost of postretirement prescription drug coverage.

In June 2004, we adopted FSP No. 106-2, retroactive to January 1, 2004. As a result of the adoption, our accumulated postretirement benefit obligation for the subsidy related to benefits attributed to past service was reduced by approximately $95 million and was accounted for as an actuarial gain. The effects of the subsidy reduced net postretirement costs by $16 million in 2004.

Stock Based Payments

In December 2004, the FASB issued SFAS No. 123-R, “Stock Based Payments,” which establishes the accounting for transactions in which an entity exchanges equity instruments for goods or services. Application of SFAS No. 123-R is required for interim or annual periods beginning after June 15, 2005 with earlier adoption encouraged. We have completed a preliminary review and estimate that the new standard will reduce reported earnings by approximately $5 million to $10 million per year.

Goodwill and Other Intangible Assets

Effective January 1, 2002, we adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” which addresses the financial accounting and reporting standards for the acquisition of intangible assets outside of a business combination and for goodwill and other intangible assets subsequent to their acquisition. This accounting standard requires that goodwill no longer be amortized, but reviewed at least annually for impairment. In accordance with SFAS No. 142, we discontinued the amortization of goodwill effective January 1, 2002.

NOTE 3 – DISPOSITIONS

International Transmission Company – Discontinued Operation

In February 2003, we sold International Transmission Company (ITC), our electric transmission business, for $610 million to affiliates of Kohlberg Kravis Roberts & Co. and Trimaran Capital Partners, LLC. The sale

generated a preliminary net of tax gain of $63 million in 2003. The gain was net of transaction costs, the portion of the gain that was refundable to customers and the write off of approximately $44 million of allocated goodwill. The gain was lowered to $58 million in 2004 under the MPSC’s November 2004 final rate order that resulted in a revision of the applicable transaction costs and customer refund.

As prescribed by SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we have reported the operations of ITC as a discontinued operation as shown in the following table:


(in Millions)	2003(3)		2002
Revenues (1)	$	21	$	138
Expenses (2)		13		67

Operating income		8		71
Income taxes		3		25

Income from discontinued operations	$	5	$	46

(1)		Includes intercompany revenues of $18 million for 2003 and $118 million for 2002.

(2)		Excludes general corporate overhead costs that were previously allocated to ITC in 2003 and 2002.

(3)		Represents activity from January 1, 2003 through February 28, 2003, when ITC was sold.

Detroit Edison’s Steam Heating Business

In January 2003, we sold Detroit Edison’s steam heating business to Thermal Ventures II, LP. Due to the continuing involvement of Detroit Edison in the steam heating business, including the commitment to purchase steam and/or electricity through 2024, fund certain capital improvements and guarantee the buyer’s credit facility, we recorded a net of tax loss of approximately $14 million in 2003. As a result of Detroit Edison’s continuing involvement, this transaction is not considered a sale for accounting purposes. The steam heating business had assets of $6 million at December 31, 2002, and had net losses of $12 million in 2002. See Note 13 – Commitments and Contingencies.

Southern Missouri Gas Company – Discontinued Operation

We own Southern Missouri Gas Company (SMGC), a public utility engaged in the distribution, transmission and sale of natural gas in southern Missouri. In the first quarter of 2004, management approved the marketing of SMGC for sale. As of March 31, 2004, SMGC met the SFAS No. 144 criteria of an asset “held for sale,” and we have reported its operating results as a discontinued operation. We recognized a net of tax impairment loss of approximately $7 million in 2004, representing the write-down to fair value of the assets of SMGC, less costs to sell, and the write-off of allocated goodwill. In November 2004, we entered into a definitive agreement providing for the sale of SMGC. Following receipt of regulatory approvals and resolution of other contingencies, it is anticipated that the transaction will close in 2005. SMGC had assets of $9 million and liabilities of $35 million at December 31, 2004.

NOTE 4 – REGULATORY MATTERS

Regulation

Detroit Edison and MichCon are subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to retail rates, recovery of certain costs, including the costs of generating facilities and regulatory assets, conditions of service, accounting and operating-related matters. Detroit Edison is also regulated by the FERC with respect to financing authorization and wholesale electric activities.

As subsequently discussed in the “Electric Industry Restructuring” section, Detroit Edison’s rates were frozen through 2003 and capped for small business customers through 2004 and for residential customers through 2005 as a result of Public Act (PA) 141. However, Detroit Edison was allowed to defer certain costs to be

recovered once rates could be increased, including costs incurred as a result of changes in taxes, laws and other governmental actions.

Regulatory Assets and Liabilities

Detroit Edison and MichCon apply the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” to their regulated operations. SFAS No. 71 requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as revenue and expense in non-regulated businesses. Continued applicability of SFAS No. 71 requires that rates be designed to recover specific costs of providing regulated services and be charged to and collected from customers. Future regulatory changes or changes in the competitive environment could result in the Company discontinuing the application of SFAS No. 71 for some or all of its utility businesses and may require the write-off of the portion of any regulatory asset or liability that was no longer probable of recovery through regulated rates. Management believes that currently available facts support the continued application of SFAS No. 71 to Detroit Edison and MichCon.

The following are balances and a brief description of the regulatory assets and liabilities at December 31:


	2004			2003
(in Millions)
Assets
Securitized regulatory assets	$	1,438		$	1,527

Recoverable income taxes related to securitized regulatory assets	$	788		$	837
Recoverable minimum pension liability		605			585
Asset retirement obligation		183			192
Other recoverable income taxes		109			114
Recoverable costs under PA 141
Net stranded costs		122			68
Excess capital expenditures		7			—
Deferred Clean Air Act expenditures		76			54
Midwest Independent System Operator charges		27			21
Transmission integration costs		—			10
Electric Customer Choice implementation costs		95			84
Enhanced security costs		8			6
Unamortized loss on reacquired debt		63			60
Deferred environmental costs		31			29
Accrued GCR revenue		55			19
Other		5			3

		2,174			2,082
Less amount included in current assets		(55	)		(19	)

	$	2,119		$	2,063


Liabilities
Asset removal costs	$	679		$	655
Excess securitization savings		—			14
Customer refund – 1997 storm		2			2
Refundable income taxes		135			146
Accrued GCR potential disallowance		28			26
Accrued PSCR refund		112			—
Other		3			3

		959			846
Less amount included in current liabilities		(142	)		(29	)

	$	817		$	817

ASSETS

• Securitized regulatory assets — The net book balance of the Fermi 2 nuclear plant was written off in 1998 and an equivalent regulatory asset was established. In 2001, the Fermi 2 regulatory asset and certain other regulatory assets were securitized pursuant to PA 142 and an MPSC order. A non-bypassable securitization bond surcharge recovers the securitized regulatory asset over a fourteen-year period ending in 2015.

•   Recoverable income taxes related to securitized regulatory assets — Receivable for the recovery of income taxes to be paid on the non-bypassable securitization bond surcharge. A non-bypassable securitization tax surcharge recovers the income tax.

•   Recoverable minimum pension liability — An additional minimum pension liability was recorded under generally accepted accounting principles due to the current under funded status of certain pension plans. The traditional rate setting process allows for the recovery of pension costs as measured by generally accepted accounting principles. Accordingly, the minimum pension liability associated with utility operations is recoverable. See Notes 4 and 14.

•   Asset retirement obligation — Asset retirement obligations were recorded pursuant to adoption of SFAS No. 143 in 2003. These obligations are primarily for Fermi 2 decommissioning costs that are recovered in rates.

•   Other recoverable income taxes — Income taxes receivable from Detroit Edison’s customers representing the difference in property-related deferred income taxes receivable and amounts previously reflected in Detroit Edison’s rates.

•   Net stranded costs — PA 141 permits, after MPSC authorization, the recovery of and a return on fixed cost deficiency associated with the electric Customer Choice program. Net stranded costs occur when fixed cost related revenues do not cover the fixed cost revenue requirements.

•   Excess capital expenditures – Starting in 2004, PA 141 permits, after MPSC authorization, the recovery of and a return on capital expenditures that exceed a base level of depreciation expense.

•   Deferred Clean Air Act expenditures — PA 141 permits, after MPSC authorization, the recovery of and a return on Clean Air Act expenditures.

•   Midwest Independent System Operator charges — PA 141 permits, after MPSC authorization, the recovery of and a return on charges from a regional transmission operator such as the Midwest Independent System Operator.

•   Transmission integration costs —The MPSC’s November 2004 final rate order denied recovery and determined these costs to be transaction expenses in DTE Energy’s sale of ITC.

•   Electric Customer Choice implementation costs — PA 141 permits, after MPSC authorization, the recovery of and a return on costs incurred associated with the implementation of the electric Customer Choice program.

•   Enhanced security costs — PA 141 permits, after MPSC authorization, the recovery of enhanced homeland security costs for an electric generating facility.

•   Unamortized loss on reacquired debt — The unamortized discount, premium and expense related to debt redeemed with a refinancing are deferred, amortized and recovered over the life of the replacement issue.

•   Deferred environmental costs — The MPSC approved the deferral and recovery of investigation and remediation costs associated with former manufactured gas plant sites.

•   Accrued GCR revenue —Receivable for the temporary under-recovery of and a return on gas costs incurred by MichCon which are recoverable through the GCR mechanism.

LIABILITIES

•   Asset removal costs – The amount collected from customers for the funding of future asset removal activities.

•   Excess securitization savings — Savings associated with the 2001 securitization of Fermi 2 and other costs are refundable to Detroit Edison’s customers.

•   Customer refund – 1997 storm — The over collection of 1997 storm costs, which will be refunded in accordance with the MPSC’s November 2004 rate order.

•   Refundable income taxes — Income taxes refundable to MichCon’s customers representing the difference in property-related deferred income taxes payable and amounts recognized pursuant to MPSC authorization.

•   Accrued GCR potential disallowance — Potential refund resulting from an MPSC order in MichCon’s 2002 GCR plan case that required MichCon to reduce revenues in the calculation of its 2002 GCR expense.

•   Accrued PSCR refund – Payable for the temporary over-recovery of and a return on power supply costs, and beginning with the MPSC’s November 2004 rate order, transmission costs incurred by Detroit Edison which are recoverable through the PSCR mechanism.

Electric Rate Case

Rate Request- In June 2003, Detroit Edison filed an application with the MPSC requesting a change in retail electric rates, resumption of the PSCR mechanism, and recovery of net stranded costs. The application and subsequent revisions resulted in a request to increase base rates by $583 million annually.

In addition, Detroit Edison requested recovery of certain regulatory assets. As subsequently discussed, Detroit Edison received interim and final rate orders relating to its June 2003 rate application.

A summary of the rate orders follows:


	Interim			Final
	Rate Increase (1)			Rate Increase (1)
(in Millions)
Base Rate Revenue Deficiency	$	248		$	336
Recovery of SMC Discounts		—			38

Overall Base Rate Increase		248			374
PSCR Savings		(126	)		(126	)

Total	$	122		$	248


	Actual			Estimate
	2004			2005 (2)		Total
Cumulative Recoverable Regulatory Assets
Clean Air Act	$	76		$	68	$	144
MISO Transmission Costs		27			49		76
Excess Capital Expenditures		7			15		22
Customer Refund – 1997 Storm		(2	)		—		(2	)

		108			132		240
Electric Choice Implementation Costs		95			6		101
Net Stranded Costs		44			—		44

Total	$	247		$	138	$	385

(1)		The impact of rate caps not included.

(2)		Represents estimated amounts to be incurred in 2005, as well as carrying costs on unrecovered balances, that were authorized for recovery by the MPSC. Actual amounts incurred are subject to review in future MPSC proceedings, and any overcollections or undercollections will be reflected in future rates.

MPSC Interim Rate Order - On February 20, 2004, the MPSC issued an order for interim rate relief. The order authorized an interim increase in base rates, a transition charge for customers participating in the electric Customer Choice program and a new PSCR factor.

The interim base rate increase totaled $248 million annually, effective February 21, 2004, and was applicable to all customers not subject to a rate cap. The increase was allocated to both full-service customers ($240 million) and electric Customer Choice customers ($8 million). However, because of the rate caps under PA 141, not all of the increase was realized in 2004. The interim order also terminated certain transition credits and authorized transition charges to electric Customer Choice customers designed to result in $30 million in additional revenues. Additionally, the MPSC authorized a reduced PSCR factor for all customers, designed to lower revenues by $126 million annually. However, the MPSC order allowed Detroit Edison to increase base rates for customers still subject to the cap in an equal and offsetting amount with the required reduction in the PSCR factor to maintain the total capped rate levels currently in effect for these customers.

The MPSC deferred addressing other items in the rate request, including a surcharge to recover regulatory assets, until a final rate order was issued.

MPSC Final Rate Order - On November 23, 2004, the MPSC issued an order for final rate relief. The MPSC determined that the base rate increase granted to Detroit Edison should be $336 million annually effective November 24, 2004 and is applicable to all customers not subject to the rate cap. The final order provides for the future recovery of losses resulting from electric Customer Choice. Additionally, beginning in 2005, the final order allows Detroit Edison to recover the discounts previously provided to special manufacturing contract (SMC) customers of $38 million, resulting in an overall base rate increase of $374 million annually. As subsequently discussed, Detroit Edison has been deferring certain costs as regulatory assets that it believes are recoverable under PA 141 once rate caps expire. The final order addressed numerous issues relating to regulatory assets, including the amounts recoverable and the recovery mechanism. The final order authorized the recovery of a lower level of stranded costs than had been recorded through February 20, 2004, the date of the interim order. Accordingly, Detroit Edison adjusted its net stranded costs related regulatory asset, which decreased 2004 net income by $21 million.

The MPSC’s final order authorizes the recovery of approximately $385 million of regulatory assets through three mechanisms:

•   The first mechanism recovers certain accrued regulatory assets over a five-year period using a regulatory asset recovery surcharge (RARS) and is collectible from all full service customers as their rate caps expire. The total amount to be collected is estimated to be $240 million, plus carrying costs of 9.74% on unrecovered balances. The recoverable regulatory assets include costs associated with Clean Air Act compliance, deferred Midwest Independent System Operator (MISO) transmission fees, and deferred excess capital expenditures. The MPSC also authorized the refunding of over collected 1997 storm costs.

•   The second mechanism includes a surcharge to recover electric Customer Choice implementation costs of $101 million and is collectible from both full service and electric Customer Choice customers. This charge will not be implemented until all current rate caps expire in 2006 and will include carrying costs of 7% on unrecovered balances.

•   The third mechanism includes a surcharge to recover $44 million in historical stranded costs incurred in 2002, 2003 and January and February 2004 and is collectible from electric Customer Choice customers, including carrying costs of 7% on unrecovered balances.

Other significant items authorized by the MPSC in its final order:

•   Rate increase was based on a 54% debt and 46% equity capital structure, and an 11% rate of return on common equity.

•   Customer rate caps do not expire until January 2006. As a result, the MPSC determined that there is a need to true-up stranded costs for at least 2004. This true-up case must be filed by March 31, 2005. The MPSC also permits Detroit Edison to file additional annual stranded cost true-up proceedings if it deems appropriate to do so pursuant to PA 141.

•   Transmission and MISO costs and costs associated with nitrogen oxide (NOx) allowances will be recoverable through the PSCR mechanism and charged to full service customers; however, costs associated with sulfur dioxide (SOx) allowances will not be included in the PSCR, but recoverable through base rates.

•   Full cost recovery of $550 million of Clean Air Act environmental expenditures was authorized. We believe that future mandated environmental expenditures will also be recovered through base rates.

•   A pension tracking mechanism was established to manage changes in pension costs. Under the tracking mechanism, Detroit Edison would recover or refund pension costs above or below the amount reflected in base rates. Detroit Edison was also required to propose a similar tracking mechanism for retiree health care costs. In February 2005, Detroit Edison filed a request with the MPSC seeking authority to

    implement a tracking mechanism for retiree health care costs (Other Postemployment Benefits Costs Tracker).

•   Detroit Edison was ordered to file a rate unbundling and restructuring case by March 23, 2005. As subsequently discussed, this rate restructuring proposal was filed on February 4, 2005.

•   Changes to the existing electric Customer Choice program regarding customers returning to full utility service. Customers electing to participate in the electric Customer Choice program will not be permitted to return to Detroit Edison’s full service rates for two years. Electric Customer Choice customers returning to full service must remain on bundled rates for at least one year following their return. Customers who fail to give the appropriate notice or do not stay on the electric Customer Choice program for two years are required to pay the higher of the applicable tariff energy price plus 10%, or the market price of power plus 10%, for any power taken from Detroit Edison.

In December 2004, Detroit Edison and other parties filed petitions for rehearing relating to the MPSC’s November 2004 final rate order. Among other items, Detroit Edison’s petition requests a correction of the capital structure used in determination of the final order and recovery of certain disallowed costs. Detroit Edison awaits an MPSC decision on the petitions for rehearing.

Electric Rate Restructuring Proposal

On February 4, 2005, Detroit Edison filed a rate restructuring proposal with the MPSC to restructure its electric rates and begin phasing out subsidies that are part of its current pricing structure. The proposal would adjust rates for each customer class to be reflective of the full costs incurred to service such customers. Under the proposal, commercial and industrial rates would be lowered, but residential rates would increase over a five-year period beginning in 2007. The MPSC anticipates that this proceeding will be completed in time to have new rates in effect no later than January 1, 2006.

Other Postemployment Benefits Costs Tracker

On February 10, 2005, Detroit Edison filed an application requesting MPSC approval of a proposed tracking mechanism for retiree health care costs. The application was filed as required pursuant to the MPSC’s November 2004 order.

Electric Industry Restructuring

Electric Rates, Customer Choice and Stranded Costs – In 2000, the Michigan Legislature enacted PA 141 that reduced electric retail rates by 5%, as a result of savings derived from the issuance of securitization bonds. The legislation also contained provisions freezing rates through 2003 and preventing rate increases (i.e., rate caps) for small business customers through 2004 and for residential customers through 2005. The price freeze period expired on February 20, 2004 pursuant to an MPSC order. In addition, PA 141 codified the MPSC’s existing electric Customer Choice program and provided Detroit Edison with the right to recover net stranded costs associated with Customer Choice. Detroit Edison was also allowed to defer certain costs to be recovered once rates could be increased, including costs incurred as a result of changes in taxes, laws and other governmental actions.

As required by PA 141, the MPSC conducted a proceeding to develop a methodology for calculating net stranded costs associated with electric Customer Choice. In a December 2001 order, the MPSC determined that Detroit Edison could recover net stranded costs associated with the fixed cost component of its electric generation operations. Specifically, there would be an annual proceeding or true-up before the MPSC reconciling the receipt of revenues associated with the fixed cost component of its generation services to the revenue requirement for the fixed cost component of those services, inclusive of an allowance for the cost of capital. Any resulting shortfall in recovery, net of mitigation, would be considered a net stranded cost. The MPSC authorized Detroit Edison to establish a regulatory asset to defer recovery of its incurred stranded costs, subject to review in a subsequent annual net stranded cost proceeding.

In July 2003, the MPSC issued an order finding that Detroit Edison had no net stranded costs in 2000 and 2001. Detroit Edison filed a petition for rehearing of the July 2003 order, which the MPSC denied in December 2003. Detroit Edison has appealed. As previously discussed, the MPSC’s November 2004 final order authorized recovery of $44 million of historical stranded costs incurred in 2002, 2003 and January and February 2004 collectible from electric Customer Choice customers through transition charges. Since March 1, 2004, Detroit Edison has recorded $108 million of additional stranded costs as a regulatory asset as the result of rate caps and higher electric Customer Choice sales losses than included in the 2004 MPSC interim order.

Securitization – Detroit Edison formed The Detroit Edison Securitization Funding LLC (Securitization LLC), a wholly owned subsidiary, for the purpose of securitizing its qualified costs, primarily related to the unamortized investment in the Fermi 2 nuclear power plant. In March 2001, the Securitization LLC issued $1.75 billion of securitization bonds, and Detroit Edison sold $1.75 billion of qualified costs to the Securitization LLC. The Securitization LLC is independent of Detroit Edison, as is its ownership of the qualified costs. Due to principles of consolidation, the qualified costs and securitization bonds appear on the company’s consolidated statement of financial position. The Company makes no claim to these assets. Ownership of such assets has vested in the Securitization LLC and been assigned to the trustee for the securitization bonds. Neither the qualified costs nor funds from an MPSC approved non-bypassable surcharge collected from Detroit Edison’s customers for the payment of costs related to the Securitization LLC and securitization bonds are available to Detroit Edison’s creditors.

Excess Securitization Savings – In January 2004, the MPSC issued an order directing Detroit Edison to file a report by March 15, 2004, of the accounting of the savings due to securitization and the application of those savings through December 2003. In addition, Detroit Edison was requested to include in the report an estimate of the foregone carrying cost associated with the excess securitization savings. A report was filed on February 16, 2004 in compliance with the MPSC order.

DTE2 Accounting Application

In 2003, we began the implementation of DTE2, a Company-wide initiative to improve existing processes and to implement new core information systems, including finance, human resources, supply chain and work management. The new information systems are replacing systems that are approaching the end of their useful lives. We expect the benefits of DTE2 to include lower costs, faster business cycles, repeatable and optimized processes, enhanced internal controls, improvements in inventory management and reductions in system support costs.

In July 2004, Detroit Edison filed an accounting application with the MPSC requesting authority to capitalize and amortize DTE2 costs, consisting of computer equipment, software and development costs, as well as related training, maintenance and overhead costs. Through December 2004, we have expensed approximately $20 million of training, maintenance and overhead costs pending MPSC action on our application. Detroit Edison is proposing a 15-year amortization period for the costs, exclusive of the computer equipment costs.

Power Supply Cost Recovery Proceedings

2004 Plan Year – An MPSC December 2003 order resumed the PSCR mechanism that had been suspended while rates were frozen. The order authorized a new PSCR factor for all customers effective January 1, 2004. The MPSC’s February 2004 interim order provided for a credit of 1.05 mills per kWh compared to a 2.04 mills per kWh charge previously in effect. Detroit Edison will file a 2004 PSCR reconciliation case by March 31, 2005.

2005 Plan Year – In September 2004, Detroit Edison filed its 2005 PSCR plan case seeking approval of a levelized PSCR factor of 1.82 mills per kWh above the amount included in base rates. In December 2004, Detroit Edison filed revisions to its 2005 PSCR plan case in accordance with the November 2004 MPSC rate order. The revised filing seeks approval of a levelized PSCR factor of up to 0.48 mills per kWh above the new base rates established in the final electric rate order. Included in the factor are power supply costs, transmission expenses and NOx emission allowance costs. Detroit Edison self-implemented a factor of a

negative 2.00 mills per kWh on January 1, 2005. The Michigan Attorney General has filed a motion for summary disposition of this proceeding based on arguments that the PSCR statute requires a fixed 48-month PSCR factor. We cannot predict the nature or timing of actions the MPSC will take on this motion.

Transmission Proceedings

On November 18, 2004, a FERC order approved a transmission pricing structure to facilitate seamless trading of electricity between MISO and the PJM Interconnection. The pricing structure eliminates layers of transmission charges between the two regional transmission organizations. The FERC noted that the new pricing structure may result in transmission owners facing abrupt revenue shifts. To facilitate the transition to the new pricing structure, the FERC authorized a Seams Elimination Cost Adjustment (SECA), effective from December 2004 through March 2006. Under MISO’s filing with the FERC, Detroit Edison’s SECA obligation would be $2.2 million per month from December 2004 through March 2005. Detroit Edison has estimated that the SECA charge for the April 2005 through March 2006 period will be approximately $1 million per month. On December 20, 2004, Detroit Edison filed a request for rehearing with the FERC which states, among other things, that SECA is retroactive ratemaking and is unlawful under the Federal Power Act. Under the MPSC’s November 2004 final rate order, transmission expenses are recoverable through the PSCR mechanism. Therefore, SECA charges, if ultimately imposed, should not have a financial impact to Detroit Edison.

Gas Rate Case

Rate Request – In September 2003, MichCon filed an application with the MPSC for an increase in service and distribution charges (base rates) for its gas sales and transportation customers. The filing requests an overall increase in base rates of $194 million per year (approximately 7% increase, inclusive of gas costs), beginning January 1, 2005. MichCon requested that the MPSC increase base rates by $154 million per year on an interim basis by April 1, 2004.

MPSC Interim Rate Order – In September 2004, the MPSC issued an order granting interim rate relief to MichCon in the amount of $35 million. The interim rate order was based on a 50% debt and 50% equity capital structure, and an 11.5% rate of return on common equity. Amounts collected are subject to a potential refund pending a final order in this rate case.

MPSC Staff Recommendation on Final Rate Relief – The Staff has recommended a $76 million increase in base rates compared to MichCon’s requested base rate relief of $194 million. The Staff also supports a provision, proposed by MichCon, that would allow MichCon to recover or refund 90% of uncollectible accounts receivable expense above or below the amount that is reflected in base rates. In addition, the Staff proposed a 50% debt and 50% equity capital structure utilizing a reduced rate of return on common equity of 11%. MichCon’s current allowed rate of return on common equity is 11.5%.

MPSC Proposal for Decision (PFD) – The Administrative Law Judge (ALJ) issued a PFD on MichCon’s rate request on December 10, 2004. The PFD recommends an increase in base rates of $60 million. The PFD supports the Staff’s recommendations for capital structure, rate of return on common equity and for the proposed reconciliation of uncollectible accounts receivable. MichCon expects a final order in the first quarter of 2005.

Gas Industry Restructuring

In December 2001, the MPSC approved MichCon’s application for a voluntary, expanded permanent gas Customer Choice program, which replaced the experimental program that expired in March 2002. The number of customers eligible to participate in the gas Customer Choice program increased over a three-year period. Effective April 2004, all of MichCon’s 1.2 million customers could elect to participate in the Customer Choice program, thereby purchasing their gas from suppliers other than MichCon. The MPSC also approved the use of deferred accounting for the recovery of implementation costs of the gas Customer Choice program. As of December 2004, approximately 111,000 customers are participating in the gas Customer Choice program.

Gas Cost Recovery Proceedings

2002 Plan Year - In December 2001, the MPSC issued an order that permitted MichCon to implement GCR factors up to $3.62 per thousand cubic feet (Mcf) for January 2002 billings and up to $4.38 per Mcf for the remainder of 2002. The order also allowed MichCon to recognize a regulatory asset of approximately $14 million representing the difference between the $4.38 factor and the $3.62 factor for volumes that were unbilled at December 31, 2001. The regulatory asset is subject to the 2002 GCR reconciliation process. In March 2003, the MPSC issued an order in MichCon’s 2002 GCR plan case. The MPSC ordered MichCon to reduce its gas cost recovery expenses by $26.5 million for purposes of calculating the 2002 GCR factor due to MichCon’s decision to utilize storage gas during 2001 that resulted in a gas inventory decrement for the 2001 calendar year.

Although we recorded a $26.5 million reserve in 2003 to reflect the impact of this order, a final determination of actual 2002 revenue and expenses including any disallowances or adjustment, will be decided in MichCon’s 2002 GCR reconciliation case that was filed with the MPSC in February 2003. The Staff and various intervening parties in this proceeding are seeking to have the MPSC disallow an additional $26 million, representing unbilled revenues at December 2001. One party has also proposed the disallowance of half of an $8 million payment made to settle Enron bankruptcy issues. The other parties to the case have recommended that the Enron bankruptcy settlement be addressed in the 2003 GCR reconciliation case. An MPSC Administrative Law Judge has recommended disallowances of $26.5 million related to the use of storage gas in 2001 and $26 million related to the December 2001 unbilled issue, and recommended that the $8 million related to the Enron issue be addressed in the 2003 GCR reconciliation case. We have included this item in our testimony in the 2003 GCR reconciliation filed in February 2004. The Staff has recommended that MichCon be allowed to recover the entire $8 million related to the Enron issue. A final order in this proceeding is expected in 2005. In addition, we filed an appeal of the March 2003 MPSC order with the Michigan Court of Appeals. In November 2004, the Michigan Court of Appeals denied the appeal.

2003 Plan Year – In July 2003, the MPSC approved an increase in MichCon’s 2003 GCR rate to a maximum of $5.75 per Mcf for the billing months of August 2003 through December 2003. MichCon’s 2003 GCR reconciliation case was filed with the MPSC in February 2004. In November 2004, the ALJ issued a PFD in the 2003 reconciliation case. The ALJ recommended that MichCon recover the full $8 million related to the Enron issue since MichCon had reason to believe at that time that cancellation of the contract was in the best interests of customers and since customers ultimately realized a benefit from the cancellation. The ALJ agreed with the MPSC Staff that a $2 million accounting adjustment related to exchange gas be disallowed.

2004 Plan Year – In September 2003, MichCon filed its 2004 GCR plan case proposing a maximum GCR factor of $5.36 per Mcf. MichCon agreed to switch from a calendar year to an operational year as a condition of its settlement in the 2003 GCR plan case. The operational GCR year would run from April to March of the following year. To accomplish the switch, the 2004 GCR plan case reflects a 15-month transitional period, January 2004 through March 2005. Under the transition proposal, MichCon would file two reconciliations pertaining to the transition period; one addressing the January 2004 to March 2004 period, the other addressing the remaining April 2004 to March 2005 period. The plan also proposes a quarterly GCR ceiling price adjustment mechanism. This mechanism allows MichCon to increase the maximum GCR factor to compensate for increases in market prices, thereby reducing the possibility of a GCR under-recovery. Due to the sustained increase in market prices for natural gas, in June 2004 the MPSC approved a temporary increase in the maximum GCR factor and a contingent factor which resulted in a new temporary maximum factor of $6.62 per Mcf, effective from July 1, 2004 until the MPSC issues its final order in this case. As of December 31, 2004, MichCon has accrued a $55 million regulatory asset representing the under-recovery of actual gas costs incurred in 2004, and the 2003 and 2002 GCR under-recovery.

2005-2006 Plan Year – In December 2004, MichCon filed its 2005-2006 GCR plan case proposing a maximum GCR factor of $7.99 per Mcf. The plan includes a quarterly GCR ceiling price adjustment mechanism. This mechanism allows MichCon to increase the maximum GCR factor to compensate for increases in market prices, thereby reducing the possibility of a GCR under-recovery.

Minimum Pension Liability

In December 2002, we recorded an additional minimum pension liability as required under SFAS No. 87, with offsetting amounts to an intangible asset and other comprehensive income. During 2003, the MPSC Staff provided an opinion that the MPSC’s traditional rate setting process allowed for the recovery of pension costs as measured by SFAS No. 87. Based on the MPSC Staff opinion, management believes that it will be allowed to recover in rates the minimum pension liability associated with its utility operations. In 2004 and 2003, we reclassified approximately $605 million ($393 million net of tax) and $585 million ($380 million net of tax), respectively, of other comprehensive loss associated with the minimum pension liability to a regulatory asset (Note 14).

Other

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

NOTE 5 – NUCLEAR OPERATIONS

General

Fermi 2, our nuclear generating plant, began commercial operation in 1988. Fermi 2 has a design electrical rating (net) of 1,150 megawatts. This plant represents approximately 10% of Detroit Edison’s summer net rated capability. The net book balance of the Fermi 2 plant was written off at December 31, 1998, and an equivalent regulatory asset was established. In 2001, the Fermi 2 regulatory asset was securitized. See Note 4 – Regulatory Matters. Detroit Edison also owns Fermi 1, a nuclear plant that was shut down in 1972 and is currently being decommissioned. The NRC has jurisdiction over the licensing and operation of Fermi 2 and the decommissioning of Fermi 1.

Property Insurance

Detroit Edison maintains several different types of property insurance policies specifically for the Fermi 2 plant. These policies cover such items as replacement power and property damage. The Nuclear Electric Insurance Limited (NEIL) is the primary supplier of these insurance polices.

Detroit Edison maintains a policy for extra expenses, including replacement power costs necessitated by Fermi 2’s unavailability due to an insured event. These policies have a 12-week waiting period and provide an aggregate $490 million of coverage over a three-year period.

Detroit Edison has $500 million in primary coverage and $2.25 billion of excess coverage for stabilization, decontamination, debris removal, repair and/or replacement of property and decommissioning. The combined coverage limit for total property damage is $2.75 billion.

For multiple terrorism losses caused by acts of terrorism not covered under the Terrorism Risk Insurance Act (TRIA) of 2002 occurring within one year after the first loss from terrorism, the NEIL policies would make available to all insured entities up to $3.2 billion, plus any amounts recovered from reinsurance, government indemnity, or other sources to cover losses.

Under the NEIL policies, Detroit Edison could be liable for maximum assessments of up to approximately $28 million per event if the loss associated with any one event at any nuclear plant in the United States should exceed the accumulated funds available to NEIL.

Public Liability Insurance

As required by federal law, Detroit Edison maintains $300 million of public liability insurance for a nuclear incident. For liabilities arising from a terrorist act outside the scope of TRIA, the policy is subject to one industry aggregate limit of $300 million. Further, under the Price-Anderson Amendments Act of 1988 (Act), deferred premium charges up to $101 million could be levied against each licensed nuclear facility, but not more than $10 million per year per facility. Thus, deferred premium charges could be levied against all owners of licensed nuclear facilities in the event of a nuclear incident at any of these facilities. The Act expired on August 1, 2002. During 2003, the U.S. Congress extended the Act for commercial nuclear facilities through December 31, 2003. However, provisions of the Act remain in effect for existing commercial reactors. Legislation to extend the Act in conjunction with comprehensive energy legislation is currently under debate in Congress. We cannot predict whether Congress will pass the legislation.

Decommissioning

The NRC has jurisdiction over the decommissioning of nuclear power plants and requires decommissioning funding based upon a formula. The MPSC and FERC regulate the recovery of costs of decommissioning nuclear power plants and both require the use of external trust funds to finance the decommissioning of Fermi 2. Rates approved by the MPSC provide for the recovery of decommissioning costs of Fermi 2. Detroit Edison is continuing to fund FERC jurisdictional amounts for decommissioning even though explicit provisions are not included in FERC rates. We believe the MPSC and FERC collections will be adequate to fund the estimated cost of decommissioning using the NRC formula.

Detroit Edison has established a restricted external trust to hold funds collected from customers for decommissioning and the disposal of low-level radioactive waste. Detroit Edison collected $38 million in 2004, $36 million in 2003 and $42 million in 2002 from customers for decommissioning and low-level radioactive waste disposal. Net unrealized investment gains of $17 million and $62 million in 2004 and 2003, respectively, and $39 million in losses in 2002, were recorded as adjustments to the nuclear decommissioning trust funds and regulatory assets. At December 31, 2004, investments in the external trust consisted of approximately 55% in publicly traded equity securities, 43% in fixed debt instruments and 2% in cash equivalents.

At December 31, 2004 and 2003, Detroit Edison had external decommissioning trust funds of $546 million and $474 million, respectively, for the future decommissioning of Fermi 2. At December 31, 2004 and 2003, Detroit Edison had an additional $18 million and $22 million in trust funds for the decommissioning of Fermi 1. At December 31, 2004 and 2003, Detroit Edison also had an external decommissioning trust fund for low-level radioactive waste disposal costs of $26 million and $22 million, respectively. It is estimated that the cost of decommissioning Fermi 2, when its license expires in 2025, will be $1.0 billion in 2004 dollars and $3.4 billion in 2025 dollars, using a 6% inflation rate. In 2001, the company began the decommissioning of Fermi 1, with the goal of removing the radioactive material and terminating the Fermi 1 license. The decommissioning of Fermi 1 is expected to be complete by 2009.

As a result of adopting SFAS No. 143, Detroit Edison recorded a retirement obligation liability for the decommissioning of Fermi 1 and 2 and reversed previously recognized decommissioning liabilities. At December 31, 2004, we have recorded a liability for the removal of the non-nuclear portion of the plants of $77 million.

Nuclear Fuel Disposal Costs

In accordance with the Federal Nuclear Waste Policy Act of 1982, Detroit Edison has a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. Detroit Edison is obligated to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold. The 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. Until the DOE is able to fulfill its obligation under the contract, Detroit Edison is responsible for the spent nuclear fuel storage. Detroit Edison estimates that existing storage capacity will be sufficient until 2007. Detroit Edison is a party in the litigation against the

NOTE 6 — JOINTLY OWNED UTILITY PLANT

Detroit Edison has joint ownership interest in two power plants, Belle River and Ludington Hydroelectric Pumped Storage. Ownership information of the two utility plants as of December 31, 2004 was as follows:


			Ludington
			Hydroelectric
	Belle River		Pumped Storage
In-service date		1984-1985		1973
Total plant capacity	1,026 MW		1,872 MW
Ownership interest		*		49	%
Investment (in Millions)	$	1,581	$	166
Accumulated depreciation (in Millions)	$	740	$	88

Detroit Edison’s ownership interest is 63% in Unit No. 1, 81% of the facilities applicable to Belle River used jointly by the Belle River and St. Clair Power Plants and 75% in common facilities used at Unit No. 2.

Belle River

The Michigan Public Power Agency (MPPA) has an ownership interest in Belle River Unit No. 1 and other related facilities. The MPPA is entitled to 19% of the total capacity and energy of the plant and is responsible for the same percentage of the plant’s operation, maintenance and capital improvement costs.

Ludington Hydroelectric Pumped Storage

Consumers Energy Company has an ownership interest in the Ludington Hydroelectric Pumped Storage Plant. Consumers Energy is entitled to 51% of the total capacity and energy of the plant and is responsible for the same percentage of the plant’s operation, maintenance and capital improvement costs.

NOTE 7 — INCOME TAXES

We file a consolidated federal income tax return.

Total income tax expense (benefit) varied from the statutory federal income tax rate for the following reasons:


(Dollars in Millions)	2004			2003			2002
Effective federal income tax rate		27.1	%		(34.4)	%		(16.7)	%


Income before income taxes and minority interest	$	396		$	266		$	465
Less minority interest		(212	)		(91	)		(37	)

Income from continuing operations before tax	$	608		$	357		$	502


Income tax expense at 35% statutory rate	$	213		$	125		$	175
Section 29 tax credits		(38	)		(241	)		(250	)
Investment tax credits		(8	)		(8	)		(9	)
Depreciation		(4	)		(4	)		2
Employee Stock Ownership Plan dividends		(5	)		(5	)		(4	)
Other, net		7			10			2

Income tax expense (benefit) from continuing operations	$	165		$	(123	)	$	(84	)

The minority interest allocation reflects the adjustment to earnings to allocate partnership losses to third party owners. The tax impact of partnership earnings and losses are attributable to the partners instead of the partnerships. The minority interest allocation is therefore removed in computing income taxes associated with continuing operations.

Components of income tax expense (benefit) were as follows:


	2004			2003			2002
(in Millions)
Continuing Operations
Current federal and other income tax expense	$	31		$	14		$	135
Deferred federal income tax expense (benefit)		134			(137	)		(219	)

		165			(123	)		(84	)
Discontinued operations		(4	)		61			25
Cumulative Effect of Accounting Changes		—			(15	)		—

Total	$	161		$	(77	)	$	(59	)

Internal Revenue Code Section 29 provides a tax credit for qualified fuels produced and sold by a taxpayer to an unrelated party during the taxable year. Our Section 29 tax credits earned but not utilized totaled $483 million and are carried forward indefinitely as alternative minimum tax credits. The majority of our tax credit properties, including all of our synfuel projects, have received private letter rulings from the Internal Revenue Service (IRS) that provide assurance as to the appropriateness of using these credits to offset taxable income, however, these tax credits are subject to IRS audit and adjustment.

We have a net operating loss carryforward of $203 million that expires in years 2018 through 2020. We do not believe that a valuation allowance is required, as we expect to utilize the loss carryforward prior to its expiration.

Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in the financial statements. Deferred tax assets and liabilities are classified as current or noncurrent according to the classification of the related assets or liabilities. Deferred tax assets and liabilities not related to assets or liabilities are classified according to the expected reversal date of the temporary differences.

Deferred tax assets (liabilities) were comprised of the following at December 31:


	2004			2003
(in Millions)
Property	$	(1,193	)	$	(1,124	)
Securitized regulatory assets		(778	)		(827	)
Alternative minimum tax credit carryforward		483			497
Merger basis differences		125			132
Pension and benefits		(56	)		(50	)
Net operating loss		71			84
Other		317			380

	$	(1,031	)	$	(908	)


Deferred income tax liabilities	$	(2,527	)	$	(2,525	)
Deferred income tax assets		1,496			1,617

	$	(1,031	)	$	(908	)

The IRS is currently conducting audits of our federal income tax returns for the years 1998 through 2001. In addition, one of our synfuel facilities is under audit by the IRS for 2001. Audits of four of our synfuel facilities for the years 2001 and 2002 were completed successfully during 2004. The Company accrues tax and interest related to tax uncertainties that arise due to actual or potential disagreements with governmental agencies about the tax treatment of specific items. At December 31, 2004, the Company had accrued approximately $53 million for such uncertainties. We believe that our accrued tax liabilities are adequate for all years.

NOTE 8 — COMMON STOCK AND EARNINGS PER SHARE

Common Stock

In March 2004, we issued 4,344,492 shares of DTE Energy common stock, valued at $170 million. The common stock was contributed to a defined benefit retirement plan.

Under the DTE Energy Company Long-Term Incentive Plan, we grant non-vested stock awards to key employees, primarily management. At the time of grant, we record the fair value of the non-vested awards as unearned compensation, which is reflected as a reduction in common stock. The number of non-vested stock awards is included in the number of common shares outstanding; however, for purposes of computing basic earnings per share, non-vested stock awards are excluded.

Shareholders’ Rights Agreement

We have a Shareholders’ Rights Agreement designed to maximize shareholder value should DTE Energy be acquired. Under certain triggering events, each right entitles the holder to purchase from DTE Energy one one-hundredth of a share of Series A Junior Participating Preferred Stock of DTE Energy at a price of $90.00, subject to adjustment as provided for in the Shareholders’ Rights Agreement. The rights expire in October 2007.

Earnings per Share

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


(in Millions, except per share amounts)	2004		2003		2002
Basic Earnings per Share

Income from continuing operations	$	442.6	$	480.4	$	585.7

Average number of common shares outstanding		172.6		167.7		164.0

Income per share of common stock based on average number of shares outstanding	$	2.56	$	2.87	$	3.57


Diluted Earnings per Share

Income from continuing operations	$	442.6	$	480.4	$	585.7

Average number of common shares outstanding		172.6		167.7		164.0
Incremental shares from stock-based awards		.7		.6		.8

Average number of dilutive shares outstanding		173.3		168.3		164.8

Income per share of common stock assuming issuance of incremental shares	$	2.55	$	2.85	$	3.55

Options to purchase approximately one million shares of common stock in 2004, five million shares in 2003 and one million shares in 2002 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. Common stock to be issued in August 2005 associated with the equity-linked securities is not included in the computation of diluted earnings per share as these shares were not dilutive (Note 9).

NOTE 9 — LONG-TERM DEBT AND PREFERRED SECURITIES

Long-Term Debt

Our long-term debt outstanding and weighted average interest rates^*of debt outstanding at December 31 was:


(in Millions)	2004			2003
DTE Energy Debt, Unsecured
6.1% due 2006 to 2033	$	1,945		$	2,005
Detroit Edison Taxable Debt, Principally Secured
6.1% due 2005 to 2032		1,672			1,485
Detroit Edison Tax Exempt Revenue Bonds
5.6% due 2008 to 2032		1,145			1,175
MichCon Taxable Debt, Principally Secured
6.2% due 2006 to 2033		785			772
Quarterly Income Debt Securities (QUIDS)
7.5% due 2026 to 2038		385			385
Non-Recourse Debt		56			78
Other Long-Term Debt		95			106

		6,083			6,006
Less amount due within one year		(410	)		(382	)

	$	5,673		$	5,624


Securitization Bonds	$	1,496		$	1,585
Less amount due within one year		(96	)		(89	)

	$	1,400		$	1,496


Equity-Linked Securities	$	178		$	185


Trust Preferred – Linked Securities
8.625% due 2038	$	—		$	103
7.8% due 2032		186			186
7.5% due 2044		103			—

	$	289		$	289

*	Weighted average interest rates as of December 31, 2004

We issued and optionally redeemed long-term debt consisting of the following:

2005

• Issued $400 million of Detroit Edison senior notes in two series, $200 million of 4.8% series due 2015 and $200 million of 5.45% series due 2035. The proceeds were used to redeem the $385 million of 7.5% Quarterly Income Debt Securities due 2026 to 2028.

• Detroit Edison redeemed $76 million of 7.5% senior notes and $100 million of 7.0% remarketed secured notes, which matured February 2005.

2004

• MCN Financing II, an unconsolidated affiliate, redeemed $100 million of 8.625% Trust Originated Preferred Securities due 2038. Accordingly, the underlying trust preferred-linked securities were also simultaneously redeemed.

• Redeemed $60 million of MCN Energy Enterprises 7.12% medium term notes.

• Issued $36 million of Detroit Edison 4-7/8% tax-exempt bonds due 2029, the proceeds of which were used to redeem $36 million of Detroit Edison 6.55% tax-exempt bonds due 2024.

• Issued $32 million of Detroit Edison 4.65% tax-exempt bonds due in 2028, the proceeds of which were used to redeem the following Detroit Edison tax-exempt issues: $11.5 million of 6.05% bonds due 2023, $7.5 million of 5.875% bonds due 2024, and $13 million of 6.45% bonds due 2024.

• DTE Energy Trust II, an unconsolidated affiliate, issued an aggregate of $100 million of 7.50% Trust Originated Preferred Securities. The proceeds from the issuance were loaned to DTE Energy in exchange for debt securities with essentially the same terms as the related preferred securities.

• Issued $250 million of DTE Energy floating rate notes due in 2007. The floating rate is based on 3 month LIBOR plus 0.95%. These notes may be called at par in June 2005. The proceeds were used to repay short-term borrowings incurred in connection with the June 2004 redemption of $250 million DTE Energy 6.0% senior notes.

• Issued $200 million of Detroit Edison 5.40% senior notes due in 2014. The proceeds were used to repay short-term borrowings and for general corporate purposes.

• Issued $120 million of MichCon 5.0% senior notes due in 2019. The proceeds were used to redeem the following two issues: $52 million of 6.85% senior notes due 2038 and $55 million of 6.85% senior notes due 2039.

2003

• Issued $400 million of DTE Energy 6-3/8% senior notes maturing in April 2033. In conjunction with this issuance, DTE Energy exchanged $100 million principal amount of existing DTE Enterprises, Inc. debt due April 2008. The exchange premium and other costs associated with the original debt were deferred and are being amortized to interest expense over the term of the new debt.

• Redeemed $100 million of DTE Energy 6.17% Remarketed Notes maturing in 2038.

• Issued $49 million of Detroit Edison 5.5% tax exempt bonds maturing in 2030.

• Redeemed $49 million of Detroit Edison 6.55% tax-exempt bonds maturing in 2024.

• Issued $200 million of MichCon 5.7% senior notes maturing in March 2033.

• Redeemed $314 million of Detroit Edison taxable debt with an average interest rate of 7.4% and maturities from 2003-2023.

• Redeemed $34 million of Detroit Edison 6.875% tax-exempt bonds maturing in 2022.

In the years 2005 – 2009, our long-term debt maturities are $507 million, $680 million, $597 million, $455 million and $ 361 million, respectively.

Remarketable Securities

At December 31, 2004, $175 million of notes of Detroit Edison and MichCon were subject to periodic remarketings. The $100 million scheduled to remarket in February 2005 was optionally redeemed by Detroit Edison, and no remarketings will take place in 2005. We direct the remarketing agents to remarket these securities at the lowest interest rate necessary to produce a par bid. In the event that a remarketing fails, we would be required to purchase the securities.

Quarterly Income Debt Securities (QUIDS)

Detroit Edison had three series of QUIDS outstanding at December 31, 2004. Detroit Edison redeemed all of its outstanding QUIDS on March 4, 2005.

Equity-Linked Securities

In June 2002, DTE Energy issued 6.9 million equity security units with gross proceeds from the issuance of $172.5 million. An equity security unit consists of a stock purchase contract and a senior note of DTE Energy. Under the stock purchase contracts, we will sell, and equity security unit holders must buy, shares of DTE Energy common stock in August 2005 for $172.5 million. The issue price per share and the exact number of common shares to be sold is dependent on the market value of a share in August 2005. The issue price will be not less than $43.25 or more than $51.90 per common share, with the corresponding number of shares issued of not more than 4.0 million or less than 3.3 million shares. We are also obligated to pay the security unit holders a quarterly contract adjustment payment at an annual rate of 4.15% of the stated amount until the purchase contract settlement date. We recorded the present value of the contract adjustment payments of $26 million in long-term debt with an offsetting reduction in shareholders’ equity. The liability is reduced as the contract adjustment payments are made.

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Each senior note has a stated value of $25, pays an annual interest rate of 4.60% and matures in August 2007. The senior notes are pledged as collateral to secure the security unit holders’ obligation to purchase DTE Energy common stock under the stock purchase contracts. The security unit holders may satisfy their obligations under the stock purchase contracts by allowing the senior notes to be remarketed with proceeds being paid to DTE Energy as consideration for the purchase of stock under the stock purchase contracts. Alternatively, holders may choose to continue holding the senior notes and use cash as consideration for the purchase of stock under the stock purchase contracts.

Net proceeds from the equity security unit issuance totaled $167 million. Expenses incurred in connection with this issuance totaled $5.6 million and were allocated between the senior notes and the stock purchase contracts. The amount allocated to the senior notes was deferred and will be recognized as interest expense over the term of the notes. The amount allocated to the stock purchase contracts was charged to equity.

Trust Preferred-Linked Securities

DTE Energy has interests in various unconsolidated trusts that were formed for the sole purpose of issuing preferred securities and lending the gross proceeds to us. The sole assets of the trusts are debt securities of DTE Energy with terms similar to those of the related preferred securities. Payments we make are used by the trusts to make cash distributions on the preferred securities it has issued.

We have the right to extend interest payment periods on the debt securities. Should we exercise this right, we cannot declare or pay dividends on, or redeem, purchase or acquire, any of our capital stock during the deferral period.

DTE Energy has issued certain guarantees with respect to payments on the preferred securities. These guarantees, when taken together with our obligations under the debt securities and related indenture, provide full and unconditional guarantees of the trusts’ obligations under the preferred securities.

Financing costs for these issuances were paid for and deferred by DTE Energy. These costs are being amortized using the straight-line method over the estimated lives of the related securities.

Cross Default Provisions

Substantially all of the net utility properties of Detroit Edison and MichCon are subject to the lien of mortgages. Should Detroit Edison or MichCon fail to timely pay their indebtedness under these mortgages, such failure will create cross defaults in the indebtedness of DTE Energy Corporate.

Preferred and Preference Securities – Authorized and Unissued

At December 31, 2004, DTE Energy had 5 million shares of preferred stock without par value authorized, with no shares issued. Of such amount, 1.5 million shares are reserved for issuance in accordance with the Shareholders’ Rights Agreement.

At December 31, 2004, Detroit Edison had approximately 6.75 million shares of preferred stock with a par value of $100 per share and 30 million shares of preference stock with a par value of $1 per share authorized, with no shares issued.

At December 31, 2004, MichCon had 7 million shares of preferred stock with a par value of $1 per share and 4 million shares of preference stock with a par value of $1 per share authorized, with no shares issued.

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NOTE 10 – SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

In May 2004, DTE Energy entered into a $375 million two-year unsecured revolving credit facility with a group of banks to be utilized for general corporate borrowings. DTE Energy had approximately $148 million of letters of credit outstanding against this facility at December 31, 2004. This agreement requires the company to maintain a debt to total capitalization ratio of no more than .65 to l and an “earnings before interest, taxes, depreciation and amortization” (EBITDA) to interest ratio of no less than 2 to 1. DTE Energy is currently in compliance with these financial covenants.

In October 2004, DTE Energy entered into a $525 million, five-year unsecured revolving credit facility and lowered its existing three-year revolving credit facility from $350 million to $175 million. Detroit Edison and MichCon also entered into similar revolving credit facilities. Detroit Edison entered into a $206.25 million, five-year facility and lowered its three-year facility from $137.5 million to $68.75 million. MichCon entered into a $243.75 million, five-year facility and lowered its three-year facility from $162.5 million to $81.25 million. The five-year facilities replace the October 2003 364-day facilities, which expired. The three-year revolving credit facilities expire in October 2006. The five- and three-year credit facilities are with a syndicate of banks and may be utilized for general corporate borrowings, but primarily are intended to provide liquidity support for each of the Companies’ commercial paper programs. Borrowings under the facilities will be available at prevailing short-term interest rates. The agreements require each of the Companies to maintain a debt to total capitalization ratio of no more than .65 to l and an EBITDA to interest ratio of no less than 2 to 1. The Companies are currently in compliance with these financial covenants. Should either Detroit Edison or MichCon have delinquent debt obligations of at least $25 million to any creditor, such delinquency will be considered a default under DTE Energy’s credit agreements.

As of December 31, 2004, we had outstanding commercial paper of $402 million and other short-term borrowings of $1 million.

Detroit Edison also has a $200 million short-term financing agreement secured by customer accounts receivable. This agreement contains certain covenants related to the delinquency of accounts receivable. Detroit Edison is currently in compliance with these covenants. We had no balances outstanding under this financing agreement at December 31, 2004.

The weighted average interest rates for short-term borrowings were 2.4% and 1.9% at December 31, 2004 and 2003, respectively.

NOTE 11 – CAPITAL AND OPERATING LEASES

Lessee - We lease various assets under capital and operating leases, including coal cars, a gas storage field, office buildings, a warehouse, computers, vehicles and other equipment. The lease arrangements expire at various dates through 2029. Portions of the office buildings are subleased to tenants.

Future minimum lease payments under non-cancelable leases at December 31, 2004 were:

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	Capital			Operating
	Leases			Leases
(in Millions)
2005	$	11		$	64
2006		13			56
2007		10			47
2008		11			40
2009		11			38
Thereafter		38			378

Total minimum lease payments		94		$	623

Less imputed interest		(21	)

Present value of net minimum lease payments		73
Less current portion		(7	)

Non-current portion	$	66

Total minimum lease payments for operating leases have not been reduced by future minimum sublease rentals totaling $6 million under non-cancelable subleases expiring at various dates to 2020.

Rental expense for operating leases was $75 million in 2004, $73 million in 2003 and $40 million in 2002.

Lessor - MichCon leases a portion of its pipeline system to the Vector Pipeline Partnership through a capital lease contract that expires in 2020, with renewal options extending for five years. The components of the net investment in the capital lease at December 31, 2004, were as follows:


(in Millions)
2005	$	9
2006		9
2007		9
2008		9
2009		9
Thereafter		98

Total minimum future lease receipts		143
Residual value of leased pipeline		40
Less unearned income		(101	)

Net investment in capital lease		82
Less current portion		(1	)

	$	81

NOTE 12 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

We comply with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149. Listed below are important SFAS No. 133 requirements:

• All derivative instruments must be recognized as assets or liabilities and measured at fair value, unless they meet the normal purchases and sales exemption.

• The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated as a hedge and qualifies for hedge accounting.

• Special accounting is allowed for a derivative instrument qualifying as a hedge and designated as a hedge for the variability of cash flow associated with a forecasted transaction. Gain or loss associated with the effective portion of the hedge is recorded in other comprehensive income. The ineffective portion is recorded to earnings. Amounts recorded in other comprehensive income will be reclassified to net

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income when the forecasted transaction affects earnings. If a cash flow hedge is discontinued because it is likely the forecasted transaction will not occur, net gains or losses are immediately recorded to earnings.

• Special accounting is also allowed for a derivative instrument qualifying as a hedge and designated as a hedge of the changes in fair value of an existing asset, liability or firm commitment. Gain or loss on the hedging instrument is recorded into earnings. An offsetting loss or gain on the underlying asset, liability or firm commitment is also recorded to earnings.

Our primary market risk exposure is associated with commodity prices, credit, interest rates and foreign currency. We have risk management policies to monitor and decrease market risks. We use derivative instruments to manage some of the exposure. Except for the activities of the Energy Marketing & Trading segment, we do not hold or issue derivative instruments for trading purposes. The fair value of all derivatives is shown as “assets or liabilities from risk management and trading activities” in the consolidated statement of financial position.

Commodity Price Risk

Utility Operations

Detroit Edison - Detroit Edison generates, purchases, distributes and sells electricity. Detroit Edison uses forward energy, capacity, and futures contracts to manage changes in the price of electricity and fuel. These derivatives are designated as cash flow hedges or meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. There were no commodity price risk cash flow hedges for utility operations at December 31, 2004.

MichCon - MichCon purchases, stores, transmits and distributes and sells natural gas. MichCon has fixed-priced contracts for portions of its expected gas supply requirements through 2005. These contracts are designated and qualify for the normal purchases and sales exemption and are therefore accounted for under the accrual method.

Commodity price risk associated with our utilities is limited due to the PSCR and GCR mechanisms (Note 1).

Non-Utility Operations

Energy Marketing & Trading — Energy Marketing and Trading markets and trades wholesale electricity and natural gas physical products, trades 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 on its operations. These derivatives are accounted for by recording changes in fair value to earnings, usually as adjustments to operating revenues or fuel, purchased power and gas expense. This fair value accounting better aligns financial reporting with the way the business is managed and its performance measured.

Energy Marketing & Trading experiences earnings volatility as a result of its gas inventory and other non-derivative assets that do not qualify for fair value accounting under U. S. generally accepted accounting principles. Although the risks associated with these asset positions are substantially offset, requirements to fair value the underlying derivatives result in unrealized gains and losses being recorded to earnings that eventually reverse upon settlement.

Energy Services and Biomass — Our Energy Services and Biomass businesses generate Section 29 tax credits. Additionally, through December 2004, Energy Services has sold majority interests in eight of its nine synthetic fuel production plants. Proceeds from the sales are contingent upon production levels, the production qualifying for Section 29 tax credits, and the value of such credits. Section 29 tax credits are subject to phase out if domestic crude oil prices reach certain levels. See Note 13 for further discussion.

To manage our exposure in 2005 to the risk of an increase in oil prices that could reduce synfuel sales proceeds, we entered into a series of derivative contracts covering a specified number of barrels of oil. The

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derivatives, coupled with other contracts, economically hedge approximately 65% of our 2005 synfuel cash flow exposure. The derivative contracts involve purchased and written call options that provide for net cash settlement at expiration based on the full year 2005 average New York Mercantile Exchange (NYMEX) trading price of oil in relation to the strike price of each option. If the average NYMEX price of oil in 2005 is less than approximately $56 per barrel, the derivatives will yield no payment. If the average NYMEX price of oil exceeds approximately $56 per barrel, the derivatives will yield a payment equal to the excess of the average NYMEX price over $56 per barrel, multiplied by the number of barrels covered, up to a maximum price of approximately $68 per barrel. The agreements do not qualify for hedge accounting and, as a result, changes in the fair value of the options are recorded currently in earnings. The fair value changes are recorded as adjustments to the gain from selling interests in synfuel facilities and therefore included in the “Asset gains and losses, net” line item in the consolidated statement of operations.

Gas Production - Our Gas Production business is engaged in natural gas exploration, development and production. We use 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 as the related forecasted production affects earnings through 2013. In 2005, we estimate reclassifying $35 million of losses to earnings.

Credit Risk

Our utility and non-utility businesses are exposed to credit risk if customers or counterparties do not comply with their contractual obligations. We maintain credit policies that significantly minimize overall credit risk. These policies include an evaluation of potential customers’ and counterparties’ financial condition, credit rating, collateral requirements or other credit enhancements such as letters of credit or guarantees. We use standardized agreements that allow the netting of positive and negative transactions associated with a single counterparty.

Interest Rate Risk

We use interest rate swaps, treasury locks and other derivatives to hedge the risk associated with interest rate market volatility. In 2004 and 2000, we entered into a series of interest rate derivatives to limit our sensitivity to market interest rate risk associated with the issuance of long-term debt. Such instruments were designated as cash flow hedges. We subsequently issued long-term debt and terminated these hedges at a cost that is included in other comprehensive loss. Amounts recorded in other comprehensive loss will be reclassified to interest expense as the related interest affects earnings through 2030. In 2005, we estimate reclassifying $6 million of losses to earnings.

Foreign Currency Risk

Energy Marketing and Trading has foreign currency forward contracts to hedge fixed Canadian dollar commitments existing under power purchase and sale contracts and gas transportation contracts. We entered into these contracts to mitigate any price volatility with respect to fluctuations of the Canadian dollar relative to the U.S. dollar. Certain of these contracts are designated as cash flow hedges with changes in fair value recorded to other comprehensive income. Amounts recorded to other comprehensive income are classified to operating revenues or fuel, purchased power and gas expense when the related hedged item affects earnings.

Fair Value of Other Financial Instruments

The fair value of financial instruments is determined by using various market data and other valuation techniques. The table below shows the fair value relative to the carrying value for long-term debt securities. The carrying value of certain other financial instruments, such as notes payable, customer deposits and notes receivable approximate fair value and are not shown.

2004

2003

Fair Value

Carrying Value

Fair Value

Carrying Value

Long-Term Debt

$8.5 billion

$8.0 billion

$8.5 billion

$7.9 billion

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NOTE 13 — COMMITMENTS AND CONTINGENCIES

Synthetic Fuel Operations

We partially or wholly own nine synthetic fuel production facilities. Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applicable IRS rules. Section 29 of the Internal Revenue Code provides tax credits for the production and sale of solid synthetic fuels produced from coal. To qualify for the Section 29 tax credits, the synthetic fuel must meet three primary conditions: (1) there must be a significant chemical change in the coal feedstock, (2) the product must be sold to an unaffiliated entity, and (3) the production facility must have been placed in service before July 1, 1998. In addition to meeting the qualifying conditions, a taxpayer must have sufficient taxable income to earn the Section 29 tax credits.

In-Service Date - During July 2004, several unaffiliated companies announced that they have been notified that the IRS intends to challenge the placed in service dates for some of their synfuel facilities. If the IRS ultimately prevails, Section 29 credits claimed by these companies would be disallowed. The placed in service issue is fact-driven and specific to each facility. The in-service dates for eight of our nine synfuel plants have been favorably reviewed by the IRS in conjunction with issuing determination letters and/or recently completed audits. We believe all nine of our synthetic fuel plants meet the required in-service condition.

Through December 31, 2004, we have generated and recorded approximately $512 million in synfuel tax credits.

Oil Prices - To reduce U.S. dependence on imported oil, the Internal Revenue Code provides Section 29 tax credits as an incentive for taxpayers to produce fuels from alternative sources. This incentive is not deemed necessary if the price of oil increases and provides a natural market for these fuels. As such, the tax credit in a given year is reduced if the Reference Price of oil within that year exceeds a threshold price. The Reference Price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil, which in recent years has been $3 — $4 lower than the NYMEX price for light, sweet crude oil. The threshold price at which the credit begins to be reduced was set in 1980 and is adjusted annually for inflation. For 2004, we estimate that the threshold price at which the tax credit would have begun to be reduced was $51.34 and would have been completely phased out if the Reference Price reached $64.45. The Reference Price of oil is estimated to be $37.61 for 2004. We also estimate that the 2005 average wellhead price per barrel of oil would have to exceed approximately $52.37 per barrel to begin phase out and exceed approximately $65.74 per barrel to eliminate the credits. We cannot predict with any accuracy the future price of a barrel of oil.

Numerous recent events have increased domestic crude oil prices, including terrorism, storm-related supply disruptions and worldwide demand. If the credit is reduced or eliminated in future years, our financial statements would be negatively impacted. We continue to evaluate the current volatility in oil prices and alternatives available to mitigate our exposure to oil prices as part of our synfuel-related risk management strategy. To manage our exposure to oil prices in 2005, we entered into oil-related derivative contracts. See Note 12 for further discussion.

Environmental

Air - The EPA issued ozone transport and acid rain regulations and, in December 2003, proposed additional emission regulations relating to ozone, fine particulate and mercury air pollution. The new rules have led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, carbon dioxide and particulate emissions. To comply with these new controls, Detroit Edison has spent approximately $580 million through December 2004, and estimates that it will spend up to $100 million in 2005 and incur from $700 million to $1.3 billion of additional future capital expenditures over the next five to eight years to satisfy

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both the existing and proposed new control requirements. Under the June 2000 Michigan restructuring legislation, beginning January 1, 2004, annual return of and on this capital expenditure, in excess of current depreciation levels, could be deferred in ratemaking, until after the expiration of the rate cap period, presently expected to end on December 31, 2005 upon MPSC authorization. Under PA 141 and the MPSC’s November 2004 final rate order, we believe that prudently incurred capital expenditures, in excess of current depreciation levels, are recoverable in rates.

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

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. Enterprises (MichCon and Citizens) owns, or previously owned, 18 such former manufactured gas plant (MGP) sites. During the mid-1980’s, Enterprises conducted preliminary environmental investigations at former MGP sites, and some contamination related to the by-products of gas manufacturing was discovered at each site. The existence of these sites and the results of the environmental investigations have been reported to the MDEQ.

Enterprises is remediating eight of the former MGP sites and conducting more extensive investigations at five other former MGP sites. Enterprises received MDEQ closure of one site, and a determination that it is not a responsible party for three other sites. Enterprises received closure from the EPA in 2002 for one site.

In 1984, Enterprises established a $12 million reserve for costs associated with environmental investigation and remediation activities. During 1993, MichCon received MPSC approval of a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites in excess of this reserve. Enterprises employed outside consultants to evaluate remediation alternatives for these sites, to assist in estimating its potential liabilities and to review its archived insurance policies. As a result of these studies, Enterprises accrued an additional liability and a corresponding regulatory asset of $35 million during 1995. In early December 2004, Enterprises retained multiple environmental consultants to estimate the projected cost to remediate each MGP facility. The results of the evaluation indicated that the MGP reserve should be set at $24 million.

During 2004, Enterprises spent approximately $2 million investigating and remediating these former MGP sites. At December 31, 2004, the reserve balance was $24 million of which $4.5 million was classified as current. 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, therefore, have an effect on the Company’s financial position and cash flows. However, we anticipate the cost deferral and rate recovery mechanism approved by the MPSC will prevent environmental costs from having a material adverse impact on our results of operations.

Detroit Edison conducted remedial investigations at contaminated sites, including two former MGP sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the cost to remediate these sites is approximately $8 million, which is expected to be incurred over the next several years. As a result of the investigation, Detroit Edison accrued an $8 million liability during 2004.

Guarantees

In certain circumstances we enter into contractual guarantees. We may guarantee another entity’s obligation in the event it fails to perform. We may provide guarantees in certain indemnification agreements. Finally, we may provide indirect guarantees of the indebtedness of others. Below are the details of specific material guarantees we currently provide. Our other guarantees are not individually material and total approximately $40 million at December 31, 2004.

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Sale of Interests in Synfuel Facilities

We have provided certain guarantees and indemnities in conjunction with the sales of interests in our synfuel facilities. The guarantees cover general commercial, environmental and tax-related exposure and will survive until 90 days after expiration of all applicable statute of limitations, or indefinitely, depending on the nature of the guarantee. We estimate that our maximum liability under these guarantees at December 31, 2004 totals $905 million.

Parent Company Guarantee of Subsidiary Obligations

We have issued guarantees for the benefit of various non-utility subsidiary transactions. In the event that DTE Energy’s credit rating is downgraded below investment grade, certain of these guarantees would require us to post cash or letters of credit valued at approximately $356 million at December 31, 2004. This estimated amount fluctuates based upon the provisions and maturities of the underlying agreements.

Personal Property Taxes

Prior to 1999, Detroit Edison, MichCon and other Michigan utilities asserted that Michigan’s valuation tables result in the substantial overvaluation of utility personal property. Valuation tables established by the Michigan State Tax Commission (STC) are used to determine the taxable value of personal property based on the property’s age. In November 1999, the STC approved new valuation tables that more accurately recognize the value of a utility’s personal property. The new tables became effective in 2000 and are currently used to calculate property tax expense. However, several local taxing jurisdictions have taken legal action attempting to prevent the STC from implementing the new valuation tables and have continued to prepare assessments based on the superseded tables. The legal actions regarding the appropriateness of the new tables were before the Michigan Tax Tribunal (MTT) which, in April 2002, issued its decision essentially affirming the validity of the STC’s new tables. In June 2002, petitioners in the case filed an appeal of the MTT’s decision with the Michigan Court of Appeals. In January 2004, the Michigan Court of Appeals upheld the validity of the new tables. With no further appeal by the petitioners available, the MTT began to schedule utility personal property valuation cases for Prehearing General Calls. Detroit Edison and MichCon have filed motions and the MTT agreed to place their cases in abeyance pending the conclusion of settlement negotiations being conducted by State of Michigan Treasury officials. On February 14, 2005, MTT issued a scheduling order that lifts the prior abeyances in a significant number of Detroit Edison and MichCon appeals. The scheduling order sets litigation calendars for these cases extending into mid-2006.

Detroit Edison and MichCon continue to record property tax expense based on the new tables. Detroit Edison and MichCon will continue through settlement or litigation to seek to apply the new tables retroactively and to ultimately resolve the pending tax appeals related to 1997 through 1999. This is a solution supported by the STC in the past. To the extent that settlements cannot be achieved with the jurisdictions, litigation regarding the valuation of utility property will delay any recoveries by Detroit Edison and MichCon.

Other Commitments

Detroit Edison has an Energy Purchase Agreement to purchase steam and electricity from the Greater Detroit Resource Recovery Authority (GDRRA). Under the Agreement, Detroit Edison will purchase steam through 2008 and electricity through June 2024. In 1996, a special charge to income was recorded that included a reserve for steam purchase commitments in excess of replacement costs from 1997 through 2008. The reserve for steam purchase commitments is being amortized to fuel, purchased power and gas expense with non-cash accretion expense being recorded through 2008. We purchased $42 million of steam and electricity in 2004, $39 million in 2003 and $37 million in 2002. We estimate steam and electric purchase commitments through 2024 will not exceed $472 million. As discussed in Note 3 — Dispositions, in January 2003, we sold the steam heating business of Detroit Edison to Thermal Ventures II, LP. Due to terms of the sale, Detroit Edison remains contractually obligated to buy steam from GDRRA until 2008 and recorded an additional

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liability of $20 million for future commitments. Also, we have guaranteed bank loans that Thermal Ventures II, LP may use for capital improvements to the steam heating system.

In 2004, we modified our future purchase commitments under a transportation agreement with an interstate pipeline company and terminated a related long-term gas exchange (storage) agreement. Under the gas exchange agreement, we received gas from the customer during the summer injection period and redelivered the gas during the winter heating season. The agreements were at rates that were not reflective of current market conditions and had been fair valued under accounting principles generally accepted in the U.S. In 2002, the fair value of the transportation agreement was frozen when it no longer met the definition of a derivative as a result of FERC Order 637. The fair value amounts were being amortized to income over the life of the related agreements, representing a net liability of approximately $75 million as of December 31, 2003. As a result of the contract modification and termination, we recorded an adjustment to the net liability increasing 2004 earnings by $48 million, net of taxes.

At December 31, 2004, we have entered into numerous long-term purchase commitments relating to a variety of goods and services required for our business. These agreements primarily consist of fuel supply commitments and energy trading contracts. We estimate that these commitments will be approximately $7.3 billion through 2027. We also estimate that 2005 base level capital expenditures will be $1.1 billion. We have made certain commitments in connection with expected capital expenditures.

Bankruptcies

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

Other

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

See Note 4 and Note 5 for a discussion of contingencies related to Regulatory Matters and Nuclear Operations.

NOTE 14 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

Measurement Date

In the fourth quarter of 2004, we changed the date for actuarial measurement of our obligations for benefit programs from December 31 to November 30. We believe the one-month change of the measurement date is a preferable change as it allows time for management to plan and execute its review of the completeness and accuracy of its benefit programs results and to fully reflect the impact on its financial results. The change did not have a material effect on retained earnings as of January 1, 2004, and income from continuing operations, net income and related per share amounts for any interim period in 2004. Accordingly, all amounts reported in the following tables for balances as of December 31, 2004 are based on a measurement date of November

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30, 2004. Amounts reported in tables for the year ended December 31, 2004 and for balances as of December 31, 2003 are based on a measurement date of December 31, 2003. Amounts reported in tables for the year ended December 31, 2003 are based on a measurement date of December 31, 2002.

Qualified and Nonqualified Pension Plan Benefits

We have defined benefit retirement plans for eligible represented and nonrepresented employees. The plans are noncontributory, cover substantially all employees and provide retirement benefits based on the employees’ years of benefit service, average final compensation and age at retirement. Certain represented and nonrepresented employees are covered under cash balance benefits based on annual employer contributions and interest credits. Our policy is to fund pension costs by contributing the minimum amount required by the Employee Retirement Income Security Act (ERISA) and additional amounts when we deem appropriate. We do not anticipate making a contribution to our qualified pension plans in 2005.

We also maintain supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees. These plans provide for benefits that supplement those provided by DTE Energy’s other retirement plans.

Net pension cost (credit) includes the following components:


	Qualified Pension Plans									Nonqualified Pension Plans
	2004			2003			2002			2004		2003		2002
(in Millions)
Service Cost	$	58		$	48		$	43		$	2	$	2	$	1
Interest Cost		168			164			162			3		4		3
Expected Return on Plan Assets		(216	)		(211	)		(223	)		—		—		—
Amortization of
Net loss		63			38			2			1		1		1
Prior service cost		8			8			9			—		—		1
Net transition asset		—			—			(2	)		—		—		—

Net Pension Cost (Credit)	$	81		$	47		$	(9	)	$	6	$	7	$	6

The following table reconciles the obligations, assets and funded status of the plans as well as the amounts recognized as prepaid pension cost or pension liability in the consolidated statement of financial position at December 31:

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	Qualified Pension Plans						Nonqualified Pension Plans
	2004			2003			2004			2003
(in Millions)
Measurement Date	November 30			December 31			November 30			December 31
Accumulated Benefit Obligation-End of Period	$	2,689		$	2,556		$	54		$	57


Projected Benefit Obligation-Beginning of Period	$	2,745		$	2,499		$	59		$	50
Service Cost		58			48			2			2
Interest Cost		168			164			3			4
Actuarial Loss (Gain)		76			201			(4	)		6
Benefits Paid		(149	)		(159	)		(4	)		(3	)
Plan Amendments		1			(8	)		—			—

Projected Benefit Obligation-End of Period	$	2,899		$	2,745		$	56		$	59


Plan Assets at Fair Value-Beginning of Period	$	2,348		$	1,845		$	—		$	—
Actual Return on Plan Assets		196			440			—			—
Company Contributions		170			222			4			3
Benefits Paid		(149	)		(159	)		(4	)		(3	)

Plan Assets at Fair Value-End of Period	$	2,565		$	2,348		$	—		$	—


Funded Status of the Plans	$	(334	)	$	(397	)	$	(56	)	$	(59	)
Unrecognized
Net loss		1,043			1,010			15			18
Prior service cost		34			41			1			3

Net Amount Recognized at Measurement Date		743			654			(40	)		(38	)
Company Contribution in December 2004		—			—			1			—

Net Amount Recognized-End of Period	$	743		$	654		$	(39	)	$	(38	)


Amount Recorded as
Prepaid pension assets	$	184		$	181		$	—		$	—
Accrued pension liability		(212	)		(287	)		(53	)		(58	)
Regulatory asset		594			572			11			13
Accumulated other comprehensive loss		139			147			2			4
Intangible asset		38			41			1			3

	$	743		$	654		$	(39	)	$	(38	)

Assumptions used in determining the projected benefit obligation and net pension costs are listed below:


	2004			2003			2002
Projected Benefit Obligation
Discount rate		6.00	%		6.25	%		6.75	%
Annual increase in future compensation levels		4.0	%		4.0	%		4.0	%

Net Pension Costs
Discount rate		6.25	%		6.75	%		7.25	%
Annual increase in future compensation levels		4.0	%		4.0	%		4.0	%
Expected long-term rate of return on Plan assets		9.0	%		9.0	%		9.5	%

At December 31, 2004, the benefits related to our qualified and nonqualified plans expected to be paid in each of the next five years and in the aggregate for the five fiscal years thereafter are as follows:

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(in Millions)
2005	$	173
2006		177
2007		182
2008		189
2009		194
2010 - 2014		1,091

Total	$	2,006

We employ a consistent formal process in determining the long-term rate of return for various asset classes. We evaluate input from our consultants, including their review of historic financial market risks and returns and long-term historic relationships between the asset classes of equities, fixed income and other assets, consistent with the widely accepted capital market principle that asset classes with higher volatility generate a greater return over the long-term. Current market factors such as inflation, interest rates, asset class risks and asset class returns are evaluated and considered before long-term capital market assumptions are determined. The long-term portfolio return is also established employing a consistent formal process, with due consideration of diversification, active investment management and rebalancing. Peer data is reviewed to check for reasonableness .

We employ a total return investment approach whereby a mix of equities, fixed income and other investments are used to maximize the long-term return of plan assets consistent with prudent levels of risk. The intent of this strategy is to minimize plan expenses over the long-term. Risk tolerance is established through consideration of future plan cash flows, plan funded status, and corporate financial considerations. The investment portfolio contains a diversified blend of equity, fixed income and other investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, growth and value investment styles, and large and small market capitalizations. Other assets such as private equity and absolute return funds are used judiciously to enhance long term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on an ongoing basis through annual liability measurements, periodic asset/liability studies, and quarterly investment portfolio reviews.

Our plans’ weighted-average asset allocations by asset category at December 31 were as follows:



	2004			2003
Equity Securities		69	%		67	%
Debt Securities		26			27
Other		5			6

		100	%		100	%

Our plans’ weighted-average asset target allocations by asset category at December 31, 2004 were as follows:


Equity Securities	65	%
Debt Securities	28
Other	7

	100	%

In December 2002, we recognized an additional minimum pension liability as required under SFAS No. 87, “Employers’ Accounting for Pensions.” An additional pension liability may be required when the

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accumulated benefit obligation of the plan exceeds the fair value of plan assets. Under SFAS No. 87, we recorded an additional minimum pension liability, an intangible asset and other comprehensive loss. In 2003, we reclassified $572 million of other comprehensive loss related to Detroit Edison’s minimum pension liability to a regulatory asset after the MPSC Staff provided an opinion that the MPSC’s traditional rate setting process allowed for the recovery of pension costs as measured by SFAS No. 87. The additional minimum pension liability, regulatory asset, intangible asset and other comprehensive loss are adjusted in December of each year based on the plans’ funded status.

We also sponsor defined contribution retirement savings plans. Participation in one of these plans is available to substantially all represented and nonrepresented employees. We match employee contributions up to certain predefined limits based upon eligible compensation, the employee’s contribution rate and, in some cases, years of credited service. The cost of these plans was $28 million in 2004, $26 million in 2003 and $25 million in 2002.

Other Postretirement Benefits

We provide certain postretirement health care and life insurance benefits for employees who are eligible for these benefits. Our policy is to fund certain trusts to meet our postretirement benefit obligations. Separate qualified Voluntary Employees Beneficiary Association (VEBA) trusts exist for represented and nonrepresented employees.

Net postretirement cost includes the following components:


	2004			2003			2002
(in Millions)
Service Cost	$	41		$	37		$	30
Interest Cost		92			87			78
Expected Return on Plan Assets		(56	)		(47	)		(59	)
Amortization of Net loss		43			31			3
Prior service cost		(3	)		(3	)		(1	)
Net transition obligation		8			13			19

Net Postretirement Cost	$	125		$	118		$	70

The following table reconciles the obligations, assets and funded status of the plans including amounts recorded as accrued postretirement cost in the consolidated statement of financial position at December 31:

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	2004				2003
(in Millions)
Measurement Date	November 30			December 31

Accumulated Postretirement Benefit Obligation-Beginning of Period	$	1,582			$	1,494
Service Cost		41				37
Interest Cost		92				87
Actuarial Loss		146				162
Plan Amendments		7				(126	)
Benefits Paid		(75	)			(72	)

Accumulated Postretirement Benefit Obligation-End of Period	$	1,793			$	1,582


Plan Assets at Fair Value-Beginning of Period	$	586			$	537
Actual Return on Plan Assets		53				114
Company Contributions		40				—
Benefits Paid		—				(65	)

Plan Assets at Fair Value-End of Period	$	679			$	586


Funded Status of the Plans	$	(1,114	)		$	(996	)
Unrecognized Net loss		811				705
Prior service cost		(8	)			(27	)
Net transition obligation		58				74

Accrued Postretirement Liability at Measurement Date		(253	)			(244	)
Company Contribution And Benefit Payments in December 2004		(20	)			—

Accrued Postretirement Liability-End of Period	$	(273	)		$	(244	)

Assumptions used in determining the projected benefit obligation and net benefit costs are listed below:


	2004		2003		2002
Projected Benefit Obligation
Discount rate		6.00 %		6.25 %		6.75 %

Net Benefit Costs
Discount rate		6.25%		6.75 %		7.25 %
Expected long-term rate of return on Plan assets		9.0 %		9.0 %		9.5 %

Benefit costs were calculated assuming health care cost trend rates beginning at 9.0% for 2005 and decreasing to 5.0% in 2010 and thereafter for persons under age 65 and decreasing from 8.0% to 5.0% for persons age 65 and over. A one-percentage-point increase in health care cost trend rates would have increased the total service cost and interest cost components of benefit costs by $20 million and increased the accumulated benefit obligation by $177 million at December 31, 2004. A one-percentage-point decrease in the health care cost trend rates would have decreased the total service and interest cost components of benefit costs by $17 million and would have decreased the accumulated benefit obligation by $157 million at December 31, 2004.

Effective 2005, we amended our postretirement health care plan to provide for some enhancements. The changes increased our expected 2005 postretirement cost by $6 million.

At December 31, 2004, the benefits expected to be paid, including prescription drug benefits, in each of the next five years and in the aggregate for the five fiscal years thereafter are as follows:

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(in Millions)
2005	$	97
2006		106
2007		110
2008		113
2009		120
2010 - 2014		665

Total	$	1,211

The process used in determining the long-term rate of return for assets and the investment approach for our other postretirement benefits plans is similar to those previously described for our qualified pension plans.

Our plans’ weighted-average asset allocations by asset category at December 31 were as follows:


	2004			2003
Equity Securities		68	%		66	%
Debt Securities		28			30
Other		4			4

		100	%		100	%

Our plans’ weighted-average asset target allocations by asset category at December 31, 2004 were as follows:


Equity Securities	65	%
Debt Securities	28
Other	7

	100	%

In December 2003, the Medicare Act was signed into law which provides for a non-taxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least “actuarially equivalent” to the benefit established by law. As discussed in Note 2, we adopted FSP No. 106-2 in 2004, which provides guidance on the accounting for the Medicare Act. As a result of the adoption, our accumulated postretirement benefit obligation for the subsidy related to benefits attributed to past service was reduced by approximately $95 million at January 1, 2004 and was accounted for as an actuarial gain. The effects of the subsidy reduced net periodic postretirement benefit costs by $16 million in 2004. The impact of the Medicare Act on the components of other postretirement benefit costs for the year ended December 31 was as follows:


(in Millions)	2004
Reduction in service cost	$	2
Reduction in interest cost		6
Amortization of actuarial gain		8

Decrease in postretirement benefit cost	$	16

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At December 31, 2004, the gross amount of federal subsidies expected to be received in each of the next five years and in the aggregate for the five fiscal years thereafter was as follows:


(in Millions)
2005	$	—
2006		11
2007		11
2008		12
2009		12
2010 - 2014		69

Total	$	115

Grantor Trust

MichCon maintains a Grantor Trust that invests in life insurance contracts and income securities. Employees and retirees have no right, title or interest in the assets of the Grantor Trust, and MichCon can revoke the trust subject to providing the MPSC with prior notification. We account for our investment at fair value with unrealized gains and losses recorded to earnings.

NOTE 15 – STOCK-BASED COMPENSATION

The DTE Energy Stock Incentive Plan permits the grant of incentive stock options, non-qualifying stock options, stock awards, performance shares and performance units. A maximum of 18 million shares of common stock may be issued under the plan. Participants in the plan include our employees and members of our Board of Directors. As of December 31, 2004, no performance units have been granted under the plan.

Options

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


				Weighted
	Number of			Average
	Options			Exercise Price
Outstanding at December 31, 2001 (1,678,870 exercisable)		5,281,624		$	38.51
Granted		1,334,370		$	42.08
Exercised		(678,715	)	$	34.64
Canceled		(456,684	)	$	38.74

Outstanding at December 31, 2002 (2,285,323 exercisable)		5,480,595		$	39.87
Granted		1,654,879		$	40.56
Exercised		(329,528	)	$	35.88
Canceled		(152,824	)	$	42.67

Outstanding at December 31, 2003 (3,506,038 exercisable)		6,653,122		$	40.18
Granted		1,300,900		$	39.41
Exercised		(891,353	)	$	34.94
Canceled		(356,000	)	$	43.06

Outstanding at December 31, 2004 (3,939,939 exercisable at a weighted average exercise price of $40.52)		6,706,669		$	40.57

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


					Weighted
			Weighted		Average
Range of	Number of		Average		Remaining
Exercise Prices	Options		Exercise Price		Contractual Life
$27.62 - $38.04		649,604		$31.70	5.02 years
$38.60 - $42.44		4,594,837		$40.68	7.65 years
$42.60 - $44.54		690,950		$42.70	6.38 years
$45.28 - $46.74		771,278		$45.47	6.51 years

		6,706,669		$40.57	7.13 years

We account for option awards under APB Opinion 25. Accordingly, no compensation expense has been recorded for options granted. As required by SFAS No. 123, we have determined the fair value for these options at the date of grant using a Black-Scholes based option pricing model and the following assumptions:


	2004			2003			2002
Risk-free interest rate		3.55	%		2.93	%		5.33	%
Dividend yield		5.23	%		4.97	%		4.90	%
Expected volatility		20.00	%		20.89	%		19.79	%

Expected life	6 years			6 years			6 years

Fair value per option	$	4.46		$	4.78		$	6.25

Stock Awards

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

The stock awards are recorded at cost that approximates fair value on the date of grant. We account for stock awards as unearned compensation, which is recorded as a reduction to common stock. The cost is amortized to compensation expense over the vesting period. Stock award activity for the years ended December 31 was:


	2004		2003		2002
Restricted common shares awarded		209,650		102,060		113,410
Weighted average market price of shares awarded	$	39.95	$	41.39	$	42.92
Compensation cost charged against income (in thousands)	$	5,616	$	6,366	$	4,101

Performance Share Awards

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

117

probable achievement of performance objectives; and (ii) the fair value of the shares. For 2004, 2003 and 2002, we recorded compensation expense totaling $6.1 million, $5.5 million and $3.6 million, respectively.

During the vesting period, the recipient of a performance share award has no shareholder rights. However, recipients will be paid an amount equal to the dividend equivalent on such shares. Performance share awards are nontransferable and are subject to risk of forfeiture. As of December 31, 2004, there were 619,044 performance share awards outstanding.

NOTE 16 – SEGMENT AND RELATED INFORMATION

We operate our businesses through three strategic business units (Energy Resources, Energy Distribution and Energy Gas). Each business unit has utility and non-utility operations. The balance of our business consists of Corporate & Other. Based on this structure, we set strategic goals, allocate resources and evaluate performance. This results in the following reportable segments.

Energy Resources

• Utility — Power Generation operations include the power generation services of Detroit Edison, the company’s electric utility. Electricity is generated from Detroit Edison’s numerous fossil plants or its nuclear plant and sold throughout Southeastern Michigan to residential, commercial, industrial and wholesale customers.

• Non-utility

• Energy Services is comprised of various businesses that develop, acquire and manage energy-related assets and services. Such projects include coke production, synfuels production, on-site energy projects and merchant generation facilities.

• Energy Marketing & Trading consists of the electric and gas marketing and trading operations of DTE Energy Trading Company and the natural gas marketing and trading operations of DTE Enterprises. Energy Marketing & Trading enters into forwards, futures, swaps and option contracts as part of its trading strategy.

• Other Non-utility operations consist primarily of businesses involved in coal services and landfill gas recovery. Also includes administrative and general expenses not allocated to other non-utility businesses.

Energy Distribution

• Utility — Power Distribution operations include the electric distribution services of Detroit Edison. Energy Distribution distributes electricity generated by Energy Resources and alternative energy suppliers to Detroit Edison’s 2.1 million residential, commercial and industrial customers.

• Non-utility operations include businesses that assemble, market, distribute and service a broad portfolio of distributed generation products, provides application engineering, and monitors and manages system operations.

Energy Gas

• Utility operations include gas distribution services provided by MichCon, the company’s gas utility that purchases, stores and distributes natural gas throughout Michigan to 1.2 million residential, commercial and industrial customers.

• Non-utility operations include the production of gas and the gathering, processing and storing of gas. Certain pipeline and storage assets are supported by the Energy Marketing & Trading segment.

Corporate & Other includes administrative and general expenses, and interest costs of DTE Energy corporate that have not been allocated to the utility and non-utility businesses. Corporate & Other also includes various other non-utility operations, including investments in new emerging energy technologies.

The income tax provisions or benefits of DTE Energy’s subsidiaries are determined on an individual company basis and recognize the tax benefit of Section 29 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

118



(in Millions)
				Depreciation,
	Operating			Depletion &		Interest			Income			Net			Total					Capital
2004	Revenue			Amortization		Expense			Taxes			Income			Assets			Goodwill		Expenditures

Energy Resources
Utility — Power Generation	$	2,210		$	272	$	167		$	23		$	62		$	8,288		$	406	$	332
Non-Utility
Energy Services		1,089			82		33			64			188			1,790			41		17
Energy Marketing & Trading		665			3		5			46			92			1,098			17		8
Other		576			8		3			(11	)		1			126			4		13

Total Non-Utility		2,330			93		41			99			281			3,014			62		38

Total Energy Resources		4,540			365		208			122			343			11,302			468		370

Energy Distribution
Utility — Power Distribution		1,358			251		113			41			88			4,554			796		370
Non-Utility		46			2		2			(10	)		(19	)		64			16		1

		1,404			253		115			31			69			4,618			812		371

Energy Gas
Utility — Gas Distribution		1,682			103		58			(9	)		20			3,128			772		113
Non-Utility		119			20		11			11			21			549			15		48

		1,801			123		69			2			41			3,677			787		161

Corporate & Other		16			3		198			10			(10	)		2,275			—		2
Reconciliation & Eliminations		(647	)		—		(72	)		—			—			(584	)		—		—


Total from Continuing Operations	$	7,114		$	744	$	518		$	165			443			21,288			2,067		904


Discontinued Operations (Note 3)													(12	)		9			—		—

Total												$	431		$	21,297		$	2,067	$	904




Electric Utility	$	3,568		$	523	$	280		$	64		$	150		$	12,842		$	1,202	$	702
Gas Utility		1,682			103		58			(9	)		20			3,128			772		113
Non-utility		2,495			115		54			100			283			3,627			93		87
Corporate & Other		16			3		198			10			(10	)		2,275			—		2
Reconciliation & Eliminations		(647	)		—		(72	)		—			—			(584	)		—		—


Total from Continuing Operations	$	7,114		$	744	$	518		$	165			443			21,288			2,067		904


Discontinued Operations (Note 3)													(12	)		9			—		—

Total												$	431		$	21,297		$	2,067	$	904

120



(in Millions)
				Depreciation,
	Operating			Depletion &		Interest			Income			Net			Total					Capital
2003	Revenue			Amortization		Expense			Taxes			Income			Assets			Goodwill		Expenditures

Energy Resources
Utility — Power Generation	$	2,448		$	224	$	157		$	135		$	235		$	7,216		$	406	$	340
Non-Utility
Energy Services		929			84		20			(249	)		199			1,644			41		22
Energy Marketing & Trading		764			2		2			20			45			1,067			17		6
Other		297			7		2			(17	)		(2	)		128			4		11

Total Non-Utility		1,990			93		24			(246	)		242			2,839			62		39

Total Energy Resources		4,438			317		181			(111	)		477			10,055			468		379

Energy Distribution
Utility — Power Distribution		1,247			249		127			10			17			5,333			796		240
Non-Utility		39			2		—			(8	)		(15	)		65			12		1

		1,286			251		127			2			2			5,398			808		241

Energy Gas
Utility — Gas Distribution		1,498			101		58			—			29			3,021			776		99
Non-Utility		90			18		8			14			29			518			15		28

		1,588			119		66			14			58			3,539			791		127

Corporate & Other		12			—		219			(28	)		(57	)		2,383			—		4

Reconciliation & Eliminations		(283	)		—		(47	)		—			—			(636	)		—		—


Total from Continuing Operations	$	7,041		$	687	$	546		$	(123	)		480			20,739			2,067		751


Discontinued Operations (Note 3)													68			14			—		—
Cumulative Effect of Accounting Changes													(27	)		—			—		—

Total												$	521		$	20,753		$	2,067	$	751



Electric Utility	$	3,695		$	473	$	284		$	145		$	252		$	12,549		$	1,202	$	580
Gas Utility		1,498			101		58			—			29			3,021			776		99
Non-utility		2,119			113		32			(240	)		256			3,422			89		68
Corporate & Other		12			—		219			(28	)		(57	)		2,383			—		4
Reconciliation & Eliminations		(283	)		—		(47	)		—			—			(636	)		—		—


Total from Continuing Operations	$	7,041		$	687	$	546		$	(123	)		480			20,739			2,067		751


Discontinued Operations (Note 3)													68			14			—		—
Cumulative Effect of Accounting Changes													(27	)		—			—		—

Total												$	521		$	20,753		$	2,067	$	751

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(in Millions)
				Depreciation,
	Operating			Depletion &			Interest			Income			Net			Total					Capital
2002	Revenue			Amortization			Expense			Taxes			Income			Assets			Goodwill		Expenditures

Energy Resources
Utility — Power Generation	$	2,711		$	331		$	184		$	120		$	241		$	7,334		$	406	$	395
Non-Utility
Energy Services		645			81			19			(268	)		182			1,536			41		130
Energy Marketing & Trading		681			3			15			13			25			822			17		—
Other		102			9			4			(19	)		7			256			4		8

Total Non-Utility		1,428			93			38			(274	)		214			2,614			62		138

Total Energy Resources		4,139			424			222			(154	)		455			9,948			468		533

Energy Distribution
Utility — Power Distribution		1,343			246			127			58			111			4,154			796		290
Non-Utility		39			2			1			(9	)		(16	)		60			12		2

		1,382			248			128			49			95			4,214			808		292

Energy Gas
Utility — Gas Distribution		1,369			104			57			36			66			2,857			776		93
Non-Utility		87			19			6			14			26			504			16		32

		1,456			123			63			50			92			3,361			792		125

Corporate & Other		16			—			232			(32	)		(56	)		2,378			—		24

Reconciliation & Eliminations		(264	)		(58	)		(76	)		3			—			(548	)		—		—


Total from Continuing Operations	$	6,729		$	737		$	569		$	(84	)		586			19,353			2,068		974


Discontinued Operations (Note 3)														46			632			44		10

Total													$	632		$	19,985		$	2,112	$	984




Electric Utility	$	4,054		$	577		$	311		$	178		$	352		$	11,488		$	1,202	$	685
Gas Utility		1,369			104			57			36			66			2,857			776		93
Non-utility		1,554			114			45			(269	)		224			3,178			90		172
Corporate & Other		16			—			232			(32	)		(56	)		2,378			—		24
Reconciliation & Eliminations		(264	)		(58	)		(76	)		3			—			(548	)		—		—


Total from Continuing Operations	$	6,729		$	737		$	569		$	(84	)		586			19,353			2,068		974


Discontinued Operations (Note 3)														46			632			44		10

Total													$	632		$	19,985		$	2,112	$	984

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NOTE 17 — SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly earnings per share may not total for the years, since quarterly computations are based on weighted average common shares outstanding during each quarter. We account for the operations of ITC and SMGC as discontinued operations (Note 3).




	First			Second			Third			Fourth
(in Millions, except per share amounts)	Quarter (1)			Quarter			Quarter			Quarter			Year
2004
Operating Revenues	$	2,093		$	1,501		$	1,594		$	1,926		$	7,114
Operating Income	$	368		$	95		$	173		$	210		$	846
Net Income (Loss)
From continuing operations	$	197		$	35		$	93		$	118		$	443
Discontinued operations		(7	)		—			—			(5	)		(12	)

Total	$	190		$	35		$	93		$	113		$	431


Basic Earnings (Loss) per Share
From continuing operations	$	1.16		$	.20		$	.54		$	.68		$	2.56
Discontinued operations		(0.04	)		—			—			(.03	)		(.06	)

Total	$	1.12		$	.20		$	.54		$	.65		$	2.50


Diluted Earnings (Loss) per Share
From continuing operations	$	1.15		$	.20		$	.54		$	.68		$	2.55
Discontinued operations		(0.04	)		—			—			(.03	)		(.06	)

Total	$	1.11		$	.20		$	.54		$	.65		$	2.49


2003
Operating Revenues	$	2,095		$	1,600		$	1,654		$	1,692		$	7,041
Operating Income	$	217		$	71		$	232		$	227		$	747
Net Income (Loss)
From continuing operations	$	108		$	(37	)	$	180		$	229		$	480
Discontinued operations		74			(2	)		(4	)		—			68
Cumulative effect of accounting changes		(27	)		—			—			—			(27	)

Total	$	155		$	(39	)	$	176		$	229		$	521


Basic Earnings (Loss) per Share
From continuing operations	$	.65		$	(.22	)	$	1.07		$	1.36		$	2.87
Discontinued operations		.44			(.01	)		(.02	)		—			.41
Cumulative effect of accounting changes		(.17	)		—			—			—			(.17	)

Total	$	.92		$	(.23	)	$	1.05		$	1.36		$	3.11


Diluted Earnings (Loss) per Share
From continuing operations	$	.64		$	(.22	)	$	1.06		$	1.36		$	2.85
Discontinued operations		.44			(.01	)		(.02	)		—			.40
Cumulative effect of accounting changes		(.16	)		—			—			—			(.16	)

Total	$	.92		$	(.23	)	$	1.04		$	1.36		$	3.09

(1)

Previously reported first quarter 2004 amounts have been adjusted to reflect the retroactive adoption of FSP No. 106-2, relating to the impact of the Medicare Act on postretirement benefit costs (Note 2).

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Item 9B. Other Information

On March 11, 2005, the Company entered into Change-in-Control Severance Agreements with each of the following executive officers: Anthony F. Earley, Jr., Gerard M. Anderson, Robert J. Buckler, Stephen E. Ewing and David E. Meador. The form of Change-in-Control Severance Agreement is filed as Exhibit 10-56 to this Form 10-K (the “Agreement”). Each of the Agreements is effective as of March 11, 2005 and replaces previous change in control agreements between the Company and the above named officers, including the agreement with Mr. Meador effective as of December 28, 2004. The Agreement is substantially similar to the form of change in control agreements signed by other officers of the Company, except with respect to the payment multiple. The description set forth below is qualified in its entirety by reference to the form of the Agreement filed herewith. Capitalized terms are defined in the Agreement.

Under each of the Agreements, in the event that the named officer’s employment is terminated following a Change in Control, either by the Company or, under certain circumstances, the officer’s volition, and in accordance with all the terms and conditions of the Agreements, the named officer will be paid a lump sum payment in an amount equal to three times the sum of (A) Base Pay, plus (B) the greater of (1) the Annual Bonus for the year in which the Change in Control occurs or (2) the Annual Bonus for the year in which the Termination Date occurs, in either case based on the assumption that target performance goals for such year would be met and such payments would be made assuming the named officer was employed for the entire year or until such later date as may be required to receive such payment.

Additionally, the named officer would also be paid a lump sum payment in an amount equal to (A) the greater of (1) the Annual Bonus for the year in which the Change in Control occurs or (2) the Annual Bonus for the year in which the Termination Date occurs, in either case based on the assumption that target performance goals for such year would be met and such payments would be made assuming the named officer was employed for the entire year or until such later date as may be required to receive such payment, (B) multiplied by a fraction, the numerator of which is the number of days prior to the named officer’s Termination Date during the calendar year in which the Termination Date occurs, and the denominator of which is 365.

Additionally, for a period of twenty-four months following the Termination Date, the Company will continue to provide the named officer with Welfare Benefits substantially similar to those he was receiving or entitled to receive immediately prior to the Termination Date, or under certain circumstances, a lump sum payment equal to the present value of the cost of such benefits. The Agreements also provide for Gross-Up Payments relating to Excise Taxes incurred by the named officer as a result of severance payments, and include certain noncompetition obligations.

125

Part III

Item 10. Directors and Executive Officers of the Registrant

Item 11. Executive Compensation

Item 12. Security Ownership of Certain Beneficial Owners and Management

Item 13. Certain Relationships and Related Transactions

Item 14. Principal Accountant Fees and Services

Information required by Part III (Items 10, 11, 12, 13 and 14) of this Form 10-K is incorporated by reference from DTE Energy’s definitive Proxy Statement for its 2005 Annual Meeting of Common Shareholders. The annual meeting will be held April 28, 2005. The Proxy Statement will be filed with the Securities and Exchange Commission, pursuant to Regulation 14A, not later than 120 days after the end of our fiscal year covered by this report on Form 10-K, all of which information is hereby incorporated by reference in, and made part of, this Form 10-K, except that the information required by Item 10 with respect to executive officers of the Registrant is included in Part I of this report.

Part IV

Item 15. Exhibits and Financial Statement Schedules

(a) The following documents are filed as part of this Annual Report on Form 10-K.

(1)   Consolidated financial statements. See “Item 8 — Financial Statements and Supplementary Data.”

(2)   Financial statement schedule. See “Item 8 — Financial Statements and Supplementary Data.”

(3)   Exhibits.


(i)		Exhibits filed herewith.

10-56		Form of Change-in-Control Severance Agreement, dated as of March 11, 2005, between DTE Energy Company and each of Anthony F. Earley, Jr., Gerard M. Anderson, Robert J. Buckler, Stephen E. Ewing and David E. Meador.

12-34		Computation of Ratio of Earnings to Fixed Charges.

18-1		Letter Regarding Change in Accounting Principles.

23-17		Consent of Deloitte & Touche LLP.

31-13		Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report.

31-14		Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report.

99-15		Sixth Amendment, dated as of September 1, 1998, to Master Trust Agreement (“Master Trust”), dated as of June 30, 1994, between The Detroit Edison Company and Fidelity Management Trust Company.

126


99-16		Seventh Amendment, dated as of December 15, 1999, to Master Trust.

99-17		Eighth Amendment, dated as of February 1, 2000, to Master Trust.

99-18		Ninth Amendment, dated as of April 1, 2000, to Master Trust.

99-19		Tenth Amendment, dated as of May 1, 2000, to Master Trust.

99-20		Eleventh Amendment, dated as of July 1, 2000, to Master Trust.

99-21		Twelfth Amendment, dated as of August 1, 2000, to Master Trust.

99-22		Thirteenth Amendment, dated as of December 21, 2001, to Master Trust.

99-23		Fourteenth Amendment, dated as of March 1, 2002, to Master Trust.

99-24		Fifteenth Amendment, dated as of January 1, 2002, to Master Trust.

(ii)		Exhibits incorporated herein by reference.

3(a)		Amended and Restated Articles of Incorporation of DTE Energy Company, dated December 13, 1995 (Exhibit 3-5 to Form 10-Q for quarter ended September 30, 1997).

3(b)		Certificate of Designation of Series A Junior Participating Preferred Stock of DTE Energy Company, dated September 23, 1997 (Exhibit 3-6 to Form 10-Q for quarter ended September 30, 1997).

3(c)		Rights Agreement, dated September 23, 1997, by and between DTE Energy Company and The Detroit Edison Company, as Rights Agent (Exhibit 4-1 to Form 8-K dated September 22, 1997).

3(d)		Bylaws of DTE Energy Company, as amended through February 24, 2005 (Exhibit 3.1 to Form 8-K dated February 24, 2005).

4(a)		Amended and Restated Indenture, dated as of April 9, 2001, between DTE Energy Company and The Bank of New York, as trustee (Exhibit 4-1 to Registration No. 333-58834).

4(b)		Amended and Restated First Supplemental Indenture, dated as of April 9, 2001, between DTE Energy Company and The Bank of New York, as trustee, creating Remarketed Notes, Series A due 2038 (Exhibit 4-223 to Form 10-Q for quarter ended March 31, 2001).

4(c)		Amended and Restated Second Supplemental Indenture, dated as of April 9, 2001, between DTE Energy Company and The Bank of New York, as trustee, creating Remarketed Notes, 1998 Series B (Exhibit 4-224 to Form 10-Q for quarter ended March 31, 2001).

4(d)		Third Supplemental Indenture, dated as of April 9, 2001, among DTE Capital Corporation, DTE Energy Company and The Bank of New York, as trustee (Exhibit 4-225 to Form 10-Q for quarter ended March 31, 2001).

4(e)		Supplemental Indenture, dated as of May 30, 2001, between DTE Energy Company and The Bank of New York, as trustee, creating 6% Senior Notes due 2004, 6.45% Senior Notes due 2006 and 7.05% Senior Notes due 2011 (Exhibit 4-226 to Form 10-Q for quarter ended June 30, 2001).

4(f)		Fourth Supplemental Indenture, dated as of January 15, 2002, between DTE Energy Company and The Bank of New York, as trustee, creating 7.8% Junior Subordinated Debentures due 2032 (Exhibit 4-228 to Form 10-K for year ended December 31, 2001).

4(g)		Supplemental Indenture, dated as of April 5, 2002, between DTE Energy Company and The Bank of New York, as trustee, creating the 2002 Series A 6.65% Senior Notes due 2009 (Exhibit 4-230 to Form 10-Q for quarter ended March 31, 2002).

4(h)		Sixth Supplemental Indenture, dated as of June 25, 2002, between DTE Energy Company and The Bank of New York, as trustee, creating 4.60% Senior Notes due 2007 (Exhibit 4-233 to Form 10-Q for quarter ended June 30, 2002).

127


4(i)		Supplemental Indenture, dated as of April 1, 2003, between DTE Energy Company and The Bank of New York, as trustee, creating 2003 Series A 6 3/8% Senior Notes due 2033 (Exhibit 4(o) to Form 10-Q for quarter ended March 31, 2003).

4(j)		Supplemental Indenture, dated as of June 1, 2004, between DTE Energy Company and BNY Midwest Trust Company (successor to The Bank of New York), creating 2004 Series C Floating Rate Notes due 2007 (Exhibit 4(p) to Form 10-Q for quarter ended June 30, 2004).

4(k)		Supplemental Indenture, dated as of June 1, 2004, between DTE Energy Company and the and BNY Midwest Trust Company (successor to The Bank of New York), creating 7.50% Junior Subordinated Debentures due 2044 (Exhibit 4(r) to Form 10-Q for quarter ended June 30, 2004).

4(l)		Pledge Agreement, dated as of June 25, 2002, between DTE Energy Company and The Bank of New York (Exhibit 4-231 to Form 10-Q for quarter ended June 30, 2002).

4(m)		Purchase Contract Agreement, dated as of June 25, 2002, between DTE Energy Company and The Bank of New York, as purchase contract agent (Exhibit 4-232 to Form 10-Q for quarter ended June 30, 2002).

4(n)		Amended and Restated Trust Agreement of DTE Energy Trust I, dated as of January 15, 2002 (Exhibit 4-229 to Form 10-K for year ended December 31, 2001).

4(o)		Amended and Restated Trust Agreement of DTE Energy Trust II, dated as of June 1, 2004 (Exhibit 4(q) to Form 10-Q for the quarter ended June 30, 2004).

4(p)		Trust Agreement of DTE Energy Trust III (Exhibit 4-21 to Registration Statement on Form S-3 (File No. 333-99955)).

4(q)		Two-Year Credit Agreement, dated as of May 7, 2004, between DTE Energy Company and the Initial Lenders named therein (Exhibit 4(s) to Form 10-Q quarter ended June 30, 2004).

10(a)		Form of 1995 Indemnification Agreement between DTE Energy Company and its directors and officers (Exhibit 3L (10-1) to Form 8-B dated January 2, 1996).

10(b)		Form of Indemnification Agreement between The Detroit Edison Company and its officers (Exhibit 10-40 to Form 10-K for year ended December 31, 2000).

10(c)		Certain arrangements pertaining to the employment of Anthony F. Earley, Jr. with The Detroit Edison Company, dated April 25, 1994 (Exhibit 10-53 to The Detroit Edison Company’s Form 10-Q for quarter ended March 31, 1994).

10(d)		Certain arrangements pertaining to the employment of Gerard M. Anderson with The Detroit Edison Company, dated October 6, 1993 (Exhibit 10-48 to The Detroit Edison Company’s Form 10-K for year ended December 31, 1993).

10(e)		Certain arrangements pertaining to the employment of David E. Meador with The Detroit Edison Company, dated January 14, 1997 (Exhibit 10-5 to Form 10-K for year ended December 31, 1996).

10(f)		Certain arrangements pertaining to the employment of Bruce D. Peterson, dated May 22, 2002 (Exhibit 10-48 to Form 10-Q for quarter ended June 30, 2002).

10(g)		Termination and Consulting Agreement, dated as of October 4, 1999, among DTE Energy Company, MCN Energy Group Inc., DTE Enterprises Inc. and A.R. Glancy, III (Exhibit 10-41 to Form 10-K for year ended December 31, 2001).

10(h)		Amended and Restated Post-Employment Income Agreement, dated March 23, 1998, between The Detroit Edison Company and Anthony F. Earley, Jr. (Exhibit 10-21 to Form 10-Q for quarter ended March 31, 1998).

10(i)		Executive Post-Employment Income Arrangement, dated March 27, 1989, between The Detroit

128


		Edison Company and S. Martin Taylor (Exhibit 10-22 to Form 10-Q for quarter ended March 31, 1998).

10(j)		Amended and Restated Executive Incentive Plan of DTE Energy Company, dated February 23, 2000 (Exhibit 10-35 to Form 10-Q for quarter ended March 31, 2000).

10(k)		DTE Energy Company Annual Incentive Plan (Exhibit 10-44 to Form 10-Q for quarter ended March 31, 2001).

10(l)		DTE Energy Company 2001 Stock Incentive Plan (Exhibit 10-43 to Form 10-Q for quarter ended March 31, 2001).

10(m)		DTE Energy Company Deferred Stock Compensation Plan for Non-Employee Directors, effective as of January 1, 1999 (Exhibit 10-30 to Form 10-K for year ended December 31, 1998).

10(n)		DTE Energy Company Retirement Plan for Non-Employee Directors (as amended and restated effective as of December 31, 1998) (Exhibit 10-31 to Form 10-K for year ended December 31, 1998).

10(o)		DTE Energy Company Plan for Deferring the Payment of Directors’ Fees (as amended and restated effective as of January 1, 1999) (Exhibit 10-29 to Form 10-K for year ended December 31, 1998).

10(p)		DTE Energy Company Supplemental Savings Plan, effective as of December 6, 2001 (Exhibit 10-44 to Form 10-Q for quarter ended June 30, 2002).

10(q)		Amendment to the DTE Energy Company Supplemental Savings Plan (Exhibit 10-54 to Form 10-Q for quarter ended September 30, 2004).

10(r)		DTE Energy Company Executive Deferred Compensation Plan, effective as of January 1, 2002 (Exhibit 10-45 to Form 10-Q for quarter ended June 30, 2002).

10(s)		Amendment to the DTE Energy Company Executive Deferred Compensation Plan (Exhibit 10-55 to Form 10-Q for quarter ended September 30, 2004).

10(t)		DTE Energy Company Supplemental Retirement Plan, effective as of January 1, 2002 (Exhibit 10-46 to Form 10-Q for quarter ended June 30, 2002).

10(u)		Amendment to the DTE Energy Company Supplemental Retirement Plan (Exhibit 10-53 to Form 10-Q for quarter ended September 30, 2004).

10(v)		DTE Energy Company Executive Supplemental Retirement Plan, effective as of January 1, 2001 (Exhibit 10-51 to Form 10-Q for quarter ended September 30, 2004).

10(w)		Amendment to the DTE Energy Company Executive Supplemental Retirement Plan (Exhibit 10-52 to Form 10-Q for quarter ended September 30, 2004).

10(x)		The Detroit Edison Company Supplemental Long-Term Disability Plan, dated January 27, 1997 (Exhibit 10-4 to Form 10-K for year ended December 31, 1996).

10(y)		Description of Executive Life Insurance Plan (Exhibit 10-47 to Form 10-Q for quarter ended June 30, 2002).

10(z)		Executive Vehicle Plan of The Detroit Edison Company, dated as of September 1, 1999 (Exhibit 10-41 to Form 10-Q for quarter ended March 31, 2001).

10(aa)		DTE Energy Affiliates Nonqualified Plans Master Trust, effective as of May 1, 2003 (Exhibit 10-49 to Form 10-Q for quarter ended March 31, 2003).

10(bb)		Five-Year Credit Agreement, dated as of October 15, 2004, among DTE Energy Company, Citibank, as Administrative Agent, and the Initial Lenders named therein (Exhibit 10.1 to Form 8-K dated October 15, 2004).

129


21(a)		Subsidiaries of the Company (Form U-3A-2 filed February 28, 2005 (File No. 069-00395)).

99(a)		Master Trust Agreement (“Master Trust”), dated as of June 30, 1994, between The Detroit Edison Company and Fidelity Management Trust Company relating to the Savings and Investment Plans (Exhibit 4-167 to Form 10-Q for quarter ended June 30, 1994).

99(b)		First Amendment, dated as of February 1, 1995, to Master Trust (Exhibit 4-10 to Registration No. 333-00023).

99(c)		Second Amendment, dated as of February 1, 1995 to Master Trust (Exhibit 4-11 to Registration No. 333-00023).

99(d)		Third Amendment, effective January 1, 1996, to Master Trust (Exhibit 4-12 to Registration No. 333-00023).

99(e)		Fourth Amendment, dated as of August 1, 1996, to Master Trust (Exhibit 4-185 to Form 10-K for year ended December 31, 1997).

99(f)		Fifth Amendment, dated as of January 1, 1998, to Master Trust (Exhibit 4-186 to Form 10-K for year ended December 31, 1997).

99(g)		Three-Year Credit Agreement dated as of October 24, 2003, between DTE Energy Company and the Initial Lenders named therein (as amended by the Five-Year Credit Agreement identified as Exhibit 10(bb) above, $175 million) (Exhibit 99-14 to Form 10-Q for quarter ended September 30, 2003).


(iii)		Exhibits furnished herewith.

32-13		Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report.

32-14		Chief Financial Officer Section 906 Form 10-K Certification of Periodic Report.

130

Signatures

Pursuant to the requirements of Section 13 or 15(d) 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: March 15, 2005	By	/s/ ANTHONY F. EARLEY, JR.

		Anthony F. Earley, Jr.
		Chairman of the Board,
		Chief Executive Officer,
		and Chief Operating Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.


By	/s/ ANTHONY F. EARLEY, JR.	By	/s/ DAVID E. MEADOR

	Anthony F. Earley, Jr.		David E. Meador
	Chairman of the Board,		Executive Vice President and Chief
	Chief Executive Officer and		Financial Officer
	Chief Operating Officer

By	/s/ DANIEL G. BRUDZYNSKI	By	/s/JOHN E. LOBBIA

	Daniel G. Brudzynski		John E. Lobbia, Director
	Vice President and Controller
		By	/s/ GAIL J. McGOVERN

			Gail J. McGovern, Director

By	/s/ LILLIAN BAUDER

	Lillian Bauder, Director

		By	/s/ EUGENE A. MILLER

			Eugene A. Miller, Director
By	/s/ ALLAN D. GILMOUR

	Allan D. Gilmour, Director

		By	/s/ CHARLES W. PRYOR, JR.

			Charles W. Pryor, Jr., Director

By	/s/ ALFRED R. GLANCY III

	Alfred R. Glancy III, Director

		By	/s/ JOSUE ROBLES, JR.

			Josue Robles, Jr., Director

By	/s/ FRANK M. HENNESSEY

	Frank M. Hennessey, Director
		By	/s/ HOWARD F. SIMS

			Howard F. Sims, Director

Date: March 15, 2005

132

Exhibit Index


Exhibit No.		Description
(i)		Exhibits filed herewith

10-56		Form of Change-in-Control Severance Agreement, dated as of March 11, 2005, between DTE Energy Company and each of Anthony F. Earley, Jr., Gerard M. Anderson, Robert J. Buckler, Stephen E. Ewing and David E. Meador.

12-34		Computation of Ratio of Earnings to Fixed Charges.

18-1		Letter Regarding Change in Accounting Principles.

23-17		Consent of Deloitte & Touche LLP.

31-13		Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report.

31-14		Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report.

99-15		Sixth Amendment, dated as of September 1, 1998, to Master Trust Agreement (“Master Trust”), dated as of June 30, 1994, between The Detroit Edison Company and Fidelity Management Trust Company.

99-16		Seventh Amendment, dated as of December 15, 1999, to Master Trust.

99-17		Eighth Amendment, dated as of February 1, 2000, to Master Trust.

99-18		Ninth Amendment, dated as of April 1, 2000, to Master Trust.

99-19		Tenth Amendment, dated as of May 1, 2000, to Master Trust.

99-20		Eleventh Amendment, dated as of July 1, 2000, to Master Trust.

99-21		Twelfth Amendment, dated as of August 1, 2000, to Master Trust.

99-22		Thirteenth Amendment, dated as of December 21, 2001, to Master Trust.

99-23		Fourteenth Amendment, dated as of March 1, 2002, to Master Trust.

99-24		Fifteenth Amendment, dated as of January 1, 2002, to Master Trust.

(iii)		Exhibits furnished herewith

32-13		Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report

32-14		Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report


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

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

*	Issued by DTE Energy Trust I. DTE Energy fully and unconditionally guarantees the payments of all amounts due on these securities to the extent DTE Energy Trust I has funds available for payment of such distributions.

**	Issued by DTE Energy Trust II. DTE Energy fully and unconditionally guarantees the payments of all amounts due on these securities to the extent DTE Energy Trust II has funds available for payment of such distributions.

	•	Optimizing of our synfuel portfolio;

	•	Providing operating services to owners of power plants;

	•	Acquiring and developing solid fuel fired power plants;

	•	Expanding on-site energy projects; and

	•	Developing new tax advantaged opportunities.

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

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

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

•	“Gas Production” represents derivative activity associated with our Michigan gas reserves. A substantial portion of the price risk associated with these reserves has been mitigated through 2013. Changes in the value of the hedges are recorded as Liabilities from Risk Management and Trading with an offset in other comprehensive income to the extent that the hedges are deemed effective. The amounts shown in the following tables exclude the value of the underlying gas reserves and the changes therein.


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

Gas Contracts	$	(18	)	$	18		Commodity contracts
Power Contracts	$	1		$	(2	)	Commodity contracts
Oil Contracts	$	15		$	(8	)	Commodity options
Interest Rate Risk	$	(311	)	$	325		Long-term debt
Foreign Currency Risk	$	—		$	—		Forward contracts

	•	The Detroit Edison Company (Detroit Edison), an electric utility engaged in the generation, purchase, distribution and sale of electric energy to 2.1 million customers in southeast Michigan;

	•	Michigan Consolidated Gas Company (MichCon), a natural gas utility engaged in the purchase, storage, transmission and distribution and sale of natural gas to 1.2 million customers throughout Michigan; and

	•	Other non-utility subsidiaries engaged in energy marketing and trading, energy services and various other electricity, coal and gas related businesses.

	•	Electric Utility, consisting of Detroit Edison;

	•	Gas Utility, primarily consisting of MichCon;

	•	Non-utility Operations

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

	•	Unconventional Gas Production, primarily consisting of gas production and coal bed methane operations;

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

•	Recoverable income taxes related to securitized regulatory assets — Receivable for the recovery of income taxes to be paid on the non-bypassable securitization bond surcharge. A non-bypassable securitization tax surcharge recovers the income tax.

•	Recoverable minimum pension liability — An additional minimum pension liability was recorded under generally accepted accounting principles due to the current under funded status of certain pension plans. The traditional rate setting process allows for the recovery of pension costs as measured by generally accepted accounting principles. Accordingly, the minimum pension liability associated with utility operations is recoverable. See Notes 4 and 14.

•	Asset retirement obligation — Asset retirement obligations were recorded pursuant to adoption of SFAS No. 143 in 2003. These obligations are primarily for Fermi 2 decommissioning costs that are recovered in rates.

•	Other recoverable income taxes — Income taxes receivable from Detroit Edison’s customers representing the difference in property-related deferred income taxes receivable and amounts previously reflected in Detroit Edison’s rates.

•	Net stranded costs — PA 141 permits, after MPSC authorization, the recovery of and a return on fixed cost deficiency associated with the electric Customer Choice program. Net stranded costs occur when fixed cost related revenues do not cover the fixed cost revenue requirements.

•	Excess capital expenditures – Starting in 2004, PA 141 permits, after MPSC authorization, the recovery of and a return on capital expenditures that exceed a base level of depreciation expense.

•	Deferred Clean Air Act expenditures — PA 141 permits, after MPSC authorization, the recovery of and a return on Clean Air Act expenditures.

•	Midwest Independent System Operator charges — PA 141 permits, after MPSC authorization, the recovery of and a return on charges from a regional transmission operator such as the Midwest Independent System Operator.

•	Transmission integration costs —The MPSC’s November 2004 final rate order denied recovery and determined these costs to be transaction expenses in DTE Energy’s sale of ITC.

•	Electric Customer Choice implementation costs — PA 141 permits, after MPSC authorization, the recovery of and a return on costs incurred associated with the implementation of the electric Customer Choice program.

•	Enhanced security costs — PA 141 permits, after MPSC authorization, the recovery of enhanced homeland security costs for an electric generating facility.

•	Unamortized loss on reacquired debt — The unamortized discount, premium and expense related to debt redeemed with a refinancing are deferred, amortized and recovered over the life of the replacement issue.

•	Deferred environmental costs — The MPSC approved the deferral and recovery of investigation and remediation costs associated with former manufactured gas plant sites.

•	Accrued GCR revenue —Receivable for the temporary under-recovery of and a return on gas costs incurred by MichCon which are recoverable through the GCR mechanism.

•	Asset removal costs – The amount collected from customers for the funding of future asset removal activities.

•	Excess securitization savings — Savings associated with the 2001 securitization of Fermi 2 and other costs are refundable to Detroit Edison’s customers.

•	Customer refund – 1997 storm — The over collection of 1997 storm costs, which will be refunded in accordance with the MPSC’s November 2004 rate order.

•	Refundable income taxes — Income taxes refundable to MichCon’s customers representing the difference in property-related deferred income taxes payable and amounts recognized pursuant to MPSC authorization.

•	Accrued GCR potential disallowance — Potential refund resulting from an MPSC order in MichCon’s 2002 GCR plan case that required MichCon to reduce revenues in the calculation of its 2002 GCR expense.

•	Accrued PSCR refund – Payable for the temporary over-recovery of and a return on power supply costs, and beginning with the MPSC’s November 2004 rate order, transmission costs incurred by Detroit Edison which are recoverable through the PSCR mechanism.

•	The first mechanism recovers certain accrued regulatory assets over a five-year period using a regulatory asset recovery surcharge (RARS) and is collectible from all full service customers as their rate caps expire. The total amount to be collected is estimated to be $240 million, plus carrying costs of 9.74% on unrecovered balances. The recoverable regulatory assets include costs associated with Clean Air Act compliance, deferred Midwest Independent System Operator (MISO) transmission fees, and deferred excess capital expenditures. The MPSC also authorized the refunding of over collected 1997 storm costs.

•	The second mechanism includes a surcharge to recover electric Customer Choice implementation costs of $101 million and is collectible from both full service and electric Customer Choice customers. This charge will not be implemented until all current rate caps expire in 2006 and will include carrying costs of 7% on unrecovered balances.

•	The third mechanism includes a surcharge to recover $44 million in historical stranded costs incurred in 2002, 2003 and January and February 2004 and is collectible from electric Customer Choice customers, including carrying costs of 7% on unrecovered balances.

•	Rate increase was based on a 54% debt and 46% equity capital structure, and an 11% rate of return on common equity.

•	Customer rate caps do not expire until January 2006. As a result, the MPSC determined that there is a need to true-up stranded costs for at least 2004. This true-up case must be filed by March 31, 2005. The MPSC also permits Detroit Edison to file additional annual stranded cost true-up proceedings if it deems appropriate to do so pursuant to PA 141.

•	Transmission and MISO costs and costs associated with nitrogen oxide (NOx) allowances will be recoverable through the PSCR mechanism and charged to full service customers; however, costs associated with sulfur dioxide (SOx) allowances will not be included in the PSCR, but recoverable through base rates.

•	Full cost recovery of $550 million of Clean Air Act environmental expenditures was authorized. We believe that future mandated environmental expenditures will also be recovered through base rates.

•	A pension tracking mechanism was established to manage changes in pension costs. Under the tracking mechanism, Detroit Edison would recover or refund pension costs above or below the amount reflected in base rates. Detroit Edison was also required to propose a similar tracking mechanism for retiree health care costs. In February 2005, Detroit Edison filed a request with the MPSC seeking authority to

	implement a tracking mechanism for retiree health care costs (Other Postemployment Benefits Costs Tracker).

•	Detroit Edison was ordered to file a rate unbundling and restructuring case by March 23, 2005. As subsequently discussed, this rate restructuring proposal was filed on February 4, 2005.

•	Changes to the existing electric Customer Choice program regarding customers returning to full utility service. Customers electing to participate in the electric Customer Choice program will not be permitted to return to Detroit Edison’s full service rates for two years. Electric Customer Choice customers returning to full service must remain on bundled rates for at least one year following their return. Customers who fail to give the appropriate notice or do not stay on the electric Customer Choice program for two years are required to pay the higher of the applicable tariff energy price plus 10%, or the market price of power plus 10%, for any power taken from Detroit Edison.

	(1)	Consolidated financial statements. See “Item 8 — Financial Statements and Supplementary Data.”

	(2)	Financial statement schedule. See “Item 8 — Financial Statements and Supplementary Data.”

	(3)	Exhibits.


	Year Ending December 31,
	2004			2003			2002
(in Millions)
Allowance for Doubtful Accounts (shown as Deduction from accounts receivable in the consolidated statement of financial position)
Balance at Beginning of Period	$	99		$	82		$	57
Additions:
Charged to costs and expenses		108			80			45
Charged to other accounts (1)		9			4			15
Deductions (2)		(87	)		(67	)		(35	)

Balance At End of Period	$	129		$	99		$	82

(1)		Collection of accounts previously written off.

(2)		Uncollectible accounts written off.