Edgar Filing: DTE ENERGY CO

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

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

Date of Report (Date of earliest event reported):
July 14, 2003

Commission file number 1-11607

DTE ENERGY COMPANY

(Exact name of registrant as specified in its charter)


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

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

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

DTE Energy Company

Current Report on Form 8-K
July 14, 2003

Item 5. OTHER EVENTS

In December 2002, DTE Energy Company (DTE Energy and we) entered into a definitive agreement with affiliates of Kohlberg Kravis Roberts & Co. and Trimaran Capital Partners, LLC to sell International Transmission Company (ITC) for approximately $610 million in cash. On February 28, 2003, following the approval of the transaction by the Federal Energy Regulatory Commission and resolution of all other contingencies, the parties closed the sale. In our Form 10-Q for the quarterly period ended March 31, 2003, we presented the financial data reflecting ITC as a discontinued operation.

We are filing this Form 8-K to enable investors to review certain financial data for the fiscal year ended December 31, 2002, reflected in our Annual Report on Form 10-K, as if ITC were a discontinued operation. Additionally, we have presented pro forma disclosure in accordance with Statement of Financial Accounting Standards (SFAS) No. 143 “Accounting for Asset Retirement Obligations”, which became effective January 1, 2003 (See Note 2). Additionally, the Securities and Exchange Commission issued Regulation G, which became effective for filings after March 28, 2003, and provides guidelines for the use of non-GAAP financial measures. Accordingly, the financial information in this Form 8-K eliminates the non-GAAP disclosures that were present in our Form 10-K.

TABLE OF CONTENTS


Definitions
Forward-Looking Statements
Business and Properties
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Schedule II
Independent Auditors’ Consent
Signature

DTE Energy Company

Current Report on Form 8-K
July 14, 2003

Table of Contents


	Page

Definitions		2

Forward-Looking Statements		4

Business and Properties		5

Selected Financial Data		26

Management’s Discussion and Analysis of Financial Condition and Results of Operations		27

Quantitative and Qualitative Disclosures About Market Risk		45

Financial Statements and Supplementary Data		46

Schedule II		106

Independent Auditors’ Consent		107

Signature		108

Definitions


Bcf		Billion cubic feet
Company		DTE Energy Company and subsidiary companies
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.
Customer Choice		Choice programs are statewide initiatives giving customers in Michigan the option to choose alternative suppliers for electricity and gas.
Detroit Edison		The Detroit Edison Company (a 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 which 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-turbines, and other devices capable of producing two kilowatts to one megawatt of power.
DTE Energy		DTE Energy Company, the parent of Detroit Edison and Enterprises
Enterprises		DTE Enterprises Inc. (successor to MCN Energy) and subsidiary companies
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
GCR		A gas cost recovery mechanism authorized by the MPSC that was reinstated by MichCon in January 2002, 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)
kWh		Kilowatthour
Mcf		Thousand cubic feet
MCN Energy		MCN Energy Group Inc. and subsidiary companies that were merged into Enterprises
MichCon		Michigan Consolidated Gas Company and subsidiary companies
MMcf		Million cubic feet of gas
MPSC		Michigan Public Service Commission
MW		Megawatt
MWh		Megawatthour
NRC		Nuclear Regulatory Commission
PSCR		A power supply cost recovery mechanism authorized by the MPSC that allowed Detroit Edison to recover through rates its fuel, fuel-related and purchased power electric expenses. The clause was suspended under Michigan’s restructuring legislation signed into law June 5, 2000, which lowered and froze electric customer rates.


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.
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 are not expected to be recoverable if customers switch to alternative suppliers of electricity and gas.
Synfuels		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.

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;

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

•		environmental issues, including changes in the climate, and regulations;

•		nuclear regulations and risks associated with nuclear operations;

•		ability to utilize Section 29 tax credits or sell interests in facilities producing such credits;

•		implementation of electric and gas Customer Choice programs;

•		implementation of electric and gas utility restructuring in Michigan;

•		employee relations;

•		unplanned outages;

•		access to capital markets and capital market conditions and 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 of fuel, purchased power and natural gas;

•		effects of competition;

•		impact of FERC and MPSC proceedings and regulations;

•		contributions to earnings by non-regulated businesses;

•		changes in federal or state tax laws and their interpretations, including the code, regulations, rulings, court proceedings and audits;

•		ability to recover costs through rate increases;

•		property insurance;

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

•		changes in accounting standards and financial reporting regulations.

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 statement speaks 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.

Business & Properties

GENERAL

In 1995, DTE Energy incorporated in the state of Michigan. DTE Energy owns three regulated companies, Detroit Edison, the International Transmission Company (ITC, sold on February 28, 2003) and MichCon, and numerous non-regulated 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. DTE Energy and all of its subsidiary companies are exempt from the provisions of such Act, 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, incorporated in the state of Michigan in 1967, is a public utility subject to regulation by the MPSC and FERC. Detroit Edison is engaged in the generation, purchase, distribution and sale of electric energy to 2.1 million customers in a 7,600 square mile area in southeastern Michigan.

ITC, incorporated in the state of Michigan in 2000, is regulated by the FERC for rates, conditions of service and operations relating to the transmission of electricity. In January 2001, Detroit Edison transferred its transmission assets to ITC, then a wholly owned subsidiary of Detroit Edison. On May 31, 2001, Detroit Edison distributed 100% of the shares of ITC to DTE Energy. In December 2002, DTE Energy reached a definitive agreement to sell ITC. The sale closed on February 28, 2003. See Note 4 for a further discussion of the ITC sale and its presentation as a discontinued operation.

MichCon is a Michigan corporation organized in 1898. MichCon became an indirect wholly owned subsidiary of DTE Energy in conjunction with the acquisition of MCN Energy (now referred to as Enterprises), which was completed on May 31, 2001. See Note 4 for a further discussion of the MCN Energy acquisition. MichCon is a natural gas utility subject to regulation by the MPSC. MichCon is engaged in the purchase, storage, transmission and distribution of natural gas to 1.2 million customers in a 14,700 square mile area throughout Michigan.

Our website is www.dteenergy.com. Available free of charge on our website is information such as previously filed reports with the SEC, press releases and other informational resources regarding DTE Energy and our subsidiaries. The information on our website is updated as soon as reasonably practicable. The information on our website is not, and shall not be deemed to be, a part of this Form 8-K or any other filing we make with the SEC. Additionally, our previously filed reports and statements are also available at the SEC’s website: www.sec.gov.

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

We operate our businesses through three strategic business units (Energy Resources, Energy Distribution and Energy Gas). The balance of our business consists of Corporate & Other. Based on this structure, we set strategic goals, allocate resources and evaluate performance. Each business unit has regulated and non-regulated operations, and contributed to DTE Energy’s 2002 diluted earnings per share of $3.83. See Note 19 - Segment and Related Information, for financial information by segment for the last three years. A discussion of each business follows.

(DTE ENERGY OPERATIONS CHART)

ENERGY RESOURCES

Power Generation

Description

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

Weather, economic factors and electricity prices affect sales to customers. Our peak load and highest total system sales generally occur during the third quarter of the year driven by air conditioning and cooling-related demands. During 2002, sales to automotive and automotive-related customers accounted for approximately 13% of total Power Generation operating revenues. Power Generation sales are not dependent

upon a limited number of customers. The loss of any one or a few customers is not reasonably likely to have a material adverse effect on Power Generation.

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


			2002				2001				2000

(in Thousands of MWh)
Power Generated and Purchased
Power Plant Generation
	Fossil
		Coal		37,381	64	%		38,424	69	%		40,039	67	%
		Natural Gas		1,414	2			1,283	2			1,667	3
		Other		222	1			4	—			394	1
	Nuclear (Fermi 2)			9,301	16			8,555	16			8,239	14

				48,318	83			48,266	87			50,339	85
Purchased Power				9,807	17			7,482	13			8,877	15

System Output				58,125	100	%		55,748	100	%		59,216	100	%

Average Unit Cost ($/MWh)
Generation (1)			$	12.53			$	12.31			$	12.78

Purchased Power (2)			$	39.16			$	78.24			$	62.57

Overall Average Unit Cost			$	17.02			$	21.15			$	20.24

(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. We have short and long-term supply contracts for expected fuel and purchased power requirements as detailed in the following table:


		2003

		Contracted			Open

Expected Supply
	Coal		88	%		12	%
	Natural Gas		10	%		90	%
	Purchased Power		90	%		10	%

Detroit Edison’s generating capability is heavily dependent upon coal. The 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 and medium-term contracts with the balance to be obtained through short-term agreements and spot purchases. Detroit Edison has contracts with eight coal suppliers for a total purchase of up to 29.6 million tons of low-sulfur western coal to be delivered from 2003 through 2006. Detroit Edison also has contracts with three suppliers for the purchase of approximately 4.0 million tons of Appalachian coal to be delivered from 2003 through 2005. These existing long-term coal contracts 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 have long-term transportation contracts with companies to provide rail car 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 base-load power facilities.

Regulation

Detroit Edison’s Power Generation business is subject to the regulatory jurisdiction of the MPSC. 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 which affect our Power Generation operations. In 1996, the MPSC began an initiative designed to give all of Michigan’s electric customers added choices and the opportunity to benefit from lower electric generation costs resulting from competition. 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 residential customers through 2005 and for small business customers through 2004. The legislation and an MPSC order issued in 2001 established a methodology to enable Detroit Edison to recover costs related to its generation operations (stranded costs) 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 electric Customer Choice. The MPSC has determined that these costs 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.

Due to MPSC orders issued in 1997 and 1998, that altered the regulatory process in Michigan and provided a plan for transition to competition for the generation business of Detroit Edison, effective December 1998, Detroit Edison’s generation business no longer met the criteria of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” Since the June 2000 legislation was enacted into law and with the issuance of subsequent clarifying MPSC orders in 2001 and 2002, rates for retail customers and transition charges for electric Customer Choice customers will be set to recover Detroit Edison’s generation costs. Such costs will be billed and recovered from both retail and choice customers and thus satisfy the criteria of SFAS No. 71. In addition, we have the legislative authority to defer regulatory costs in 2002 and 2003 and to begin recovery of such costs starting in 2004 after the mandated rate freeze expires. As a result, we resumed application of SFAS No. 71 for our generation business in the fourth quarter of 2002.

In November 2002, the MPSC requested Michigan gas and electric utilities to justify why their retail rates should not be lowered due to potential personal property tax reductions. We have responded and await further MPSC action.

For additional information regarding our regulatory environment, see Note 6 - Regulatory Matters.

Properties

Detroit Edison owns generating properties and facilities that are all 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, 2002 are as follows:


			Summer Net
		Location by	Rated Capability (1) (2)
		Michigan
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		200		1.8		1999
	Greenwood	St. Clair		785		7.1		1979
	Harbor Beach	Huron		103		0.9		1968
	Marysville	St. Clair		167		1.5		1930, 1943 and 1947
	Monroe (4)	Monroe		3,000		27.1		1971, 1973 and 1974
	River Rouge	Wayne		510		4.6		1957 and 1958
	St. Clair	St. Clair		1,409		12.7		1953, 1954, 1959, 1961 and 1969
	Trenton Channel	Wayne		730		6.6		1949, 1968 and 1999

				7,930		71.6
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		10.1		1988
Hydroelectric Pumped Storage Ludington (6)		Mason		917		8.3		1973

				11,060		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 8 – Jointly Owned Utility Plant.

(4)		The Monroe Power Plant provided 33% of Detroit Edison’s total 2002 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. Detroit Edison leased 306 MW of Ludington to First Energy for the six-year period June 1, 1996 through May 31, 2002.

Strategy and Competition

Our strategy for Power Generation is to build upon Detroit Edison’s solid reputation. We will continue to strive to be the preferred electricity supplier in southeast Michigan. We believe that we can accomplish our goal by working with our customers and communities to be a reliable supplier of electricity. To control expenses, we plan to optimize our fuel blends and make investments in our generating plants that will reduce unplanned plant outages and improve operating efficiencies, thereby increasing generation output without proportional additional fuel requirements. 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.

Alternative suppliers of generation services in the retail and wholesale markets create competition in the electric generating business. Effective January 1, 2002, the electric Customer Choice program expanded in Michigan whereby all electric customers can choose to purchase their electricity from alternative suppliers. Approximately 6% of Detroit Edison’s retail generation sales were lost in 2002 as a result of customers participating in the electric Customer Choice program. We expect to lose between 10% to 13% of retail sales in 2003 as a result of customers choosing to participate in the program.

Energy Services

Description

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

Coal-Based Fuels

Coal-Based Fuels operations include producing synthetic fuel from nine synfuel plants and producing coke from three coke battery plants. Both processes 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. 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 that has characteristics similar to those of high-quality mined coal. The potential benefits of this process can include increased use of lower quality coal, improved coking qualities of the coal, reduced dust and air emissions, and improved material handling. During 2002, we sold a 95% interest in two of our synfuel projects.

The coke battery facilities produce coke that is used in blast furnaces within the steel industry. DTE Energy is one of the largest producers in the U.S. of coke for the steel industry. During 2001, we sold a 49% interest in two of our coke battery projects, and in 2002, consistent with the original purchase and sale agreement, our third coke battery project interest was reduced from 95% to 5%.


(Dollars in Millions)			2002		2001		2000

Coal-Based Fuels Statistics
	Synfuel Plants:
		Operational		9		5		2
		Tax Credits Generated (1)	$	180.2	$	64.1	$	11.7

	Coke Battery Plants:
		Operational		3		3		3
		Tax Credits Generated (1)	$	57.4	$	88.6	$	106.5

(1)

DTE Energy’s portion of total tax credits generated

On-Site Energy Projects

Energy Services owns and 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 services to industrial, commercial and institutional customers.

Merchant Generation

Energy Services develops and operates peaking and gas-fired electric generating plants. We have four electric generating plants in operation, all located in the Great Lakes region. We have contracts for approximately 39% of the 2003 output of these plants.

Properties

Coal-Based Fuels owns interest 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

100

Foundry Coke/Steel

DTE Belews Creek, LLC

Belews Creek, NC

100

Utility

DTE Utah, LLC

Price, UT

100

Industrial/Utility

DTE Indy Coke, LLC

Indianapolis, IN

100

Foundry Coke/Steel

DTE Clover, LLC

Bledsoe, KY

Utility

DTE Smith Branch, LLC

Pineville, WV

Steel/Export

DTE River Hill, LLC

Karthaus, PA

100

Utility

DTE Buckeye, LLC (2 plants)

Cheshire, OH

100

Utility

Coke Battery

EES Coke Battery Co.

River Rouge, MI

Steel

Indiana Harbor

East Chicago, IN

Steel

Burns Harbor

Burns Harbor, IN

Steel

On-Site Energy Projects owns and/or operates energy facilities throughout the United States. The significant properties are varied in both use and function and are listed below:


On-Site Energy Projects

Facility	Location	Type

PCI Enterprises	River Rouge, MI	Pulverized Coal
DTE Sparrows Point	Sparrows Point, MD	Pulverized Coal
DTE Northwind	Detroit, MI	Steam & Chilled Water
DTE Moraine	Moraine, OH	Compressed Air
DTE Tonawanda	Tonawanda, NY	Chilled & Waste Water
Metro Energy	Romulus, MI	Electricity, Hot and Chilled Water

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


Merchant Generation

Facility	Location	% Owned			Capacity (in MW)

Georgetown	Indianapolis, IN		100	%		240
River Rouge	Detroit, MI		100	%		240
Crete	Crete, IL		50	%		320
East China	East China Twp, MI		100	%		320

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 and merchant generating businesses. We continue to evaluate opportunities to sell interests in some or all of our synfuel plants.

We anticipate building around our core strengths in the markets where we operate. In determining which markets to compete in, 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, and then trend towards increased operational scale.

We plan to focus on the following areas for growth:

•		Acquisition of assets in the distressed energy market;

•		Expansion of on-site energy projects;

•		Select development of coal-fired generation; and

•		Development of 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 Company and CoEnergy Trading Company. We acquired CoEnergy Trading as part of the MCN Energy acquisition in May 2001. 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.

Regulation

There have been numerous events that impacted the energy trading business. These events led to increased oversight and scrutiny of the trading business by state and federal regulatory agencies.

Strategy and Competition

Our strategy for Energy Marketing & Trading is to execute on our vision of the role energy trading plays in delivering value-added services to our customers. Over the past year many of the major market players have either ceased as going concerns or are no longer engaged in the energy trading business. We seek to gradually expand 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 have risk management and credit policies to monitor and minimize risk.

Coal Services

Description

Coal Services specializes in minimizing energy production costs and maximizing reliability of supply for energy-intensive customers. We provide fuel, transportation and equipment management services tailored to the individual requirements of each customer. Our customers include electric utilities, merchant producers, integrated steel mills and large industrial producers with high energy requirements. We also operate a number of railcar maintenance and repair facilities serving coal transporters, as well as all other industries and rail car types.

2002

2001

2000

Coal Services

Tons of Coal Shipped (in Millions)

28.5

23.5

14.5

Properties

We lease approximately 2,800 rail cars. We own fixed and mobile railcar maintenance and repair facilities in Nebraska and Indiana.

Strategy and Competition

We plan to leverage our position as one of the top North American coal marketers and our reputation as an efficient manager of transportation assets. Certain trends are taking place within our industry that could have an impact on how we compete in the future. Industry consolidation in the mining business is resulting in fewer but larger mines. Consolidation in the railroad industry is reducing the number of rail companies we can contract with to transport coal for our customers. We plan to work with suppliers and the railroads to promote secure and competitive access to the energy requirements for our customers. We are also exploring a technology that removes clay and dirt from waste coal. If the technology is commercially practical, it could contribute significantly to earnings and provide 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. Biomass operations generate Section 29 tax credits that 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 migrating off-site and becoming a safety hazard or odor problem. 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 kilns for brick manufacturing.


(Dollars in Millions)	2002		2001		2000

Biomass
Landfill Sites		30		28		27
Gas Produced (in Bcf)		27.5		24.2		24.4
Tax Credits Generated (1)	$	12.9	$	11.9	$	11.4

(1)

DTE Energy’s portion of total tax credits generated

Properties

Biomass has 30 operating sites and other projects are under development. These sites are located throughout the continental U.S.

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 like natural gas, but we believe the environmental benefits of biomass along with reasonable and economic access to these landfill sites provide a platform for future growth.

ENERGY DISTRIBUTION

Power Distribution

Power Transmission (Discontinued Operation - Sold on February 28, 2003)

Description

The electric distribution services and the steam heating business of Detroit Edison and the electric transmission services of ITC (Discontinued Operation – Sold on February 28, 2003) comprise our regulated Power Distribution & Transmission businesses. This business transmits and distributes electricity generated by Energy Resources’ Power Generation business and alternative electric suppliers to Detroit Edison’s 2.1 million customers in southeastern Michigan. The transmission assets of ITC are operated by the Midwest Independent System Operator, a regional transmission operator responsible for evaluating and coordinating requests for transmission service on a non-discriminatory basis. In the fourth quarter of 2002, we entered into an agreement with Kohlberg, Kravis, Roberts & Co. and Trimaran Capital Partners, LLC to sell ITC for $610 million. The sale closed on February 28, 2003. The sale price can be increased or decreased based upon a review of ITC’s closing date balance sheet. Completion of this review is expected during the third quarter of 2003.

ITC will continue to provide transmission services to the Energy Distribution business at rates that will be recovered from Detroit Edison’s utility customers. In January 2003, we sold the steam heating business to Thermal Ventures II, LP.

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 cooling-related demands. Power Distribution’s sales are not dependent upon a limited number of customers. Additionally, customers participating in the electric Customer Choice program will not impact Power Distribution’s operating revenues or the number of customers served. The loss of any one or a few customers is not reasonably likely to have a material adverse effect on Power Distribution.


(in MWh)	2002		2001		2000

Electric Deliveries
Residential		15,958		14,503		13,903
Commercial		18,395		18,777		19,762
Industrial		13,590		14,430		16,090
Wholesale		2,249		2,159		2,277

		50,192		49,869		52,032
Electric Choice		3,510		1,268		202

Total Electric Deliveries		53,702		51,137		52,234

Regulation

Detroit Edison’s Power Distribution is subject to the regulatory jurisdiction of the MPSC. ITC’s transmission business is subject to the regulatory jurisdiction of the FERC. The MPSC and FERC have regulatory jurisdiction 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, for small business customers through 2004, and remaining customers through 2003. We expect the rates charged by ITC to remain at current levels through December 2004.

For additional information regarding our regulatory environment, see Note 6 – Regulatory Matters.

Properties

Detroit Edison owns and operates 662 distribution substations with a capacity of 30,843,000 kilovolt-amperes (kV) and 406,176 line transformers with a capacity of 24,493,806 kV amperes. 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, 2002 are as follows:


Electric Distribution	Circuit Miles

Operating Voltage – kV	Overhead		Underground

4.8 kV to 13.2 kV		27,429		11,510
24 kV		102		696
40 kV		2,350		328
120 kV		77		13

		29,958		12,547

ITC owns and operates 40 transmission stations with a capacity of 20,250,000 kV amperes. Circuit miles of transmission lines owned and in service as of December 31, 2002 are as follows:


Electric Transmission (Discontinued Operation)
	Circuit Miles

Operating Voltage – kV	Overhead		Underground

120 kV		1,491		118
230 kV		86		—
345 kV		963		7

		2,540		125

Detroit Edison and Consumers Energy Company interchange energy through nine interconnections currently owned and operated by ITC and Michigan Electric Transmission Company (METC). Detroit Edison and Consumers Energy Company also have interchange agreements that permit the exchange of electric energy through 12 ITC and METC owned interconnections with First Energy, Indiana Michigan Power Company, Northern Indiana Public Service Company and Ontario Hydro Services Company. In addition, Detroit Edison has interchange agreements for the exchange of electric energy with Michigan South Central Power Agency and the City of Wyandotte.

Strategy and Competition

Our strategy is to build upon Detroit Edison’s solid reputation of being a reliable distributor of electricity. We plan to focus on improving the quality of customer service and lowering operating costs by improving operating efficiencies as well as 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 is consistent with our strategic view that maximization of shareholder value and high levels of customer service are best achieved with assets we own, operate and exercise significant control. The sale was completed on February 28, 2003 and ITC will continue to provide transmission services to the Energy Distribution business. As Detroit Edison’s rates are designed to recover transmission costs, billings to Detroit Edison from ITC will be recovered from Detroit Edison’s utility customers. Rates charged by ITC to Detroit Edison are expected to remain at current levels through December 2004. Thereafter, rates would be subject to normal FERC regulation and market forces.

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

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, market and distribute a broad portfolio of distributed generation products, provide application engineering, and monitor and manage system operations. Distributed generation units seek to generate safe, clean, reliable power at or near the point of use, rather than at large central power stations, which can provide very high efficiencies due to effective use of waste heat. Distributed generation products use a range of technologies, including internal combustion engines, external combustion engines, mini-turbines and fuel cells.

Distribution Generation has steadily increased the number of completed projects each year. The table below details the number of projects completed in the past three years.

2002

2001

2000

Distributed Generation Projects Completed

876

319

Strategy and Competition

Our goal is to become a significant player in the distributed generation market, providing one-stop shopping that meets customers’ total energy needs. Key milestones toward this success include full commercialization of our internal combustion engine-driven products as well as our monitoring and system management operations. Additionally, we are completing the development of our first turbine-powered product. Our North American sales structure is in place and we are continuing to expand our support capabilities (both direct and with partners). Important objectives beyond North America will be the continued development of marketing relationships in Europe, Korea and Japan.

Competition in the distributed generation business currently is provided by other distributors of stand-by generators. We compete on the basis of cost and seek to better meet customer needs with our enhanced offerings including turn-key installations, project management, after sale service and system management operation. We anticipate increased future competition, including the entry of new competitors, for continuous duty products and services. To compete effectively, we develop proprietary products and services that are sold through our existing distribution channels in North America and exclusive arrangements in international markets.

ENERGY GAS

Gas Distribution

Description

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


(in Millions)		2002		2001(1)

Gas Revenues
	Gas Sales	$	1,104	$	491
	End-user Transportation		122		50
	Intermediate Transportation		49		26
	Other		94		48

		$	1,369	$	615

(in Bcf)
Gas Deliveries
	Gas Sales		170		95
	End-user Transportation		170		81
	Intermediate Transportation		492		304

			832		480

(1)

Includes the operations of MichCon from the May 31, 2001 acquisition date.

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 utilizes MichCon’s pipeline network to transport the gas to the customer’s 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.

We obtain our natural gas supply from various sources in different geographic areas under agreements that vary in both pricing and terms.


		2003

Gas Distribution
Contracted Supply
	Fixed Price Purchases		62	%
	Market Price Purchases		38	%

			100	%

Supply under contract represents approximately 89% of the expected 157 Bcf of supply requirements in 2003. We expect to meet the balance of gas supply requirements through open market purchases. 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. The local utility would continue to transport the natural gas supply to the customers’ facilities, thereby retaining distribution margins. In December 2001, the MPSC issued an order that continues the gas Customer Choice program on a permanent and expanding basis beginning with the conclusion of the three-year temporary program on March 31, 2002. Under the expanded program, beginning April 1, 2002, up to approximately 40% of customers could elect to purchase gas from suppliers other than MichCon. Beginning in April 2003, up to approximately 60% of customers could participate, and beginning April 2004, all 1.2 million of MichCon’s gas customers could choose to participate. MichCon will continue to transport and deliver the gas to the participating customers’ premises at prices that generate favorable margins.

Under the December 2001 MPSC order, MichCon returned to a gas cost recovery (GCR) mechanism in January 2002 upon termination of its temporary Gas Sales Program. The GCR permits MichCon to pass the cost of natural gas to its customers. Under the Gas Sales Program, the MPSC suspended the GCR mechanism and MichCon’s sales rates included a gas commodity component that was fixed at $2.95 per thousand cubic feet (Mcf). Under this program, MichCon incurred commodity price risk associated with its ability to secure gas supplies at prices less than $2.95 per Mcf. Beginning in January 2002, MichCon’s gas sales rates include a gas commodity component designed to recover its actual gas costs.

For additional information regarding our regulatory environment, see Note 6 - Regulatory Matters.

Properties

MichCon owns distribution, transmission and storage properties and facilities that are all located in the state of Michigan. At December 31, 2002, MichCon’s distribution system included 17,774 miles of distribution mains, 1,136,863 service lines and 1,241,516 active meters. MichCon owns 2,581 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 and high-value energy services within Michigan. We expect modest growth and to control costs in order to provide customers high-quality service at competitive prices.

Competition in the gas business primarily involves 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.

Exploration & Production

Description

The Exploration & Production (E&P) business owns one of the industry’s largest Antrim gas reserve bases. Our emphasis is on developing and producing the 400 Bcf of proved reserves we owned as of December 31, 2002 predominantly located in northern Michigan. We drilled 90 wells (78 net of interest of others) in 2002. Wells drilled in the Antrim shale formations have high success rates and low drilling costs, and are therefore considered low risk.

Properties

The Michigan properties had 24.2 Bcf equivalents of production in 2002. E&P does not anticipate adding a significant amount of new reserves to its 400 Bcf of proven reserves at December 31, 2002.

Strategy

The E&P business is aggressively managing its Michigan oil and gas producing assets to optimize returns on investment. We have operator responsibilities for our Michigan properties with the goal of lowering the costs of producing reserves. E&P has rights to 86,050 acres (69,977 net of interest of others) of undeveloped leases. During 2003, E&P plans to continue developing this acreage and anticipates selling nearly all of its gas production to DTE Energy’s Energy Marketing & Trading segment. In addition, in order to leverage our E&P capabilities and the skills and experience of other non-regulated businesses, we are exploring opportunities in the coal bed methane gas production business.

Pipelines & Processing

Description

The Pipelines & Processing business has partnership interests in two interstate transmission pipelines, Portland Natural Gas Transmission System (Portland) and Vector Pipeline (Vector), seven carbon dioxide processing facilities and a 9.7 Bcf natural gas storage field. Additionally, we have contract rights to a 42.5 Bcf natural gas storage field. The assets of the Pipelines & Processing business are primarily supported by the Energy Marketing & Trading segment.

Properties

Pipelines & Processing

Property Classification

% Owned

Description

Location

Pipelines

Portland Pipeline

295-mile pipeline with 216

Northeast U.S.

MMcf per day capacity

Vector Pipeline

348-mile pipeline with 1,000

Midwest

MMcf per day capacity

Processing Plants

202 MMcf per day capacity

Northern Michigan

Storage

Washington 28

9.7 Bcf of storage capacity

Washington Twp, MI

Washington 10

—

42.5 Bcf of storage capacity

Washington Twp, MI

Strategy and Competition

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 United States to occur within the Mid-Atlantic and New England regions. These regions currently lack the pipeline capacity and low-cost storage necessary to deliver gas volumes to meet growing demand. Portland and Vector are interstate pipeline projects that are intended to fill a large portion of that need, and are complemented by Energy Gas’ significant storage capacity. 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 52.2 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.

CORPORATE & OTHER

Description

Corporate & Other includes administrative and general expenses, and interest costs that have not been allocated to regulated and non-regulated businesses. Corporate & Other also includes various other non-regulated investments, including assets held for sale and in emerging energy technologies.

Strategy and Competition

Our energy technology 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. Our largest investment is in Plug Power Inc., a company that designs and develops on-site electric fuel cell power generation systems. In 2002, we invested $9 million in five emerging energy companies and $2 million in three energy technology 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

6		Regulatory Matters
7		Nuclear Operations
16		Commitments and Contingencies

Detroit Edison

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

The U.S. Environmental Protection Agency (EPA) issued ozone transport regulations and air quality standards relating to ozone and particulate air pollution. The new rules have led to additional controls on fossil-fueled power plants to reduce nitrogen oxides, sulfur dioxide, carbon dioxide and particulate emissions. To comply with these new controls, Detroit Edison has spent approximately $460 million through December 2002 and estimates that it will incur an additional $300 to $400 million of future capital expenditures over the next five to eight years to satisfy these 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. We cannot predict the future impact of this issue upon Detroit Edison.

Detroit Edison is required to demonstrate that the cooling water intake structures at all of its facilities minimize adverse environmental impact. Detroit Edison filed such demonstrations and in the event of a final adverse decision, may be required to install additional control technologies to further minimize the impact.

Various state and federal laws regulate Detroit Edison’s handling, storage and disposal of its waste materials. The EPA and the Michigan Department of Environmental Quality (MDEQ) have aggressive programs to manage the clean up of contaminated property. Detroit Edison has extensive land holdings and, from time to time, must investigate claims of improperly disposed contaminants. Detroit Edison anticipates it will be periodically included in these types of environmental proceedings.

MichCon and Citizens

Prior to the construction of major natural gas pipelines, gas for heating and other uses was manufactured from processes involving coal, coke or oil. Enterprises (MichCon and Citizens, a wholly owned utility located in Adrian, Michigan) owns, or previously owned, 17 such former manufactured gas plant (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 is conducting more extensive investigations at three of the sites. Enterprises has received MDEQ closure of one site and a determination that it is not a responsible party for two other sites. 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-regulated affiliates are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants. We believe these non-regulated affiliates are in substantial compliance with all environmental requirements.

RISK FACTORS

There are various risks associated with the operations of DTE Energy’s regulated and non-regulated 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.

Weather – Weather significantly affects our 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.

Regional and national economic conditions – 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.

Environmental laws and liability – We are subject to numerous environmental regulations. These regulations govern air emissions, water quality, wastewater discharge, solid waste, 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, including issues related to global warming. 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.

Operation of nuclear facilities – 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 than can significantly impact the performance and cost of operating a nuclear facility.

Section 29 tax credits – We have generated Section 29 tax credits from our synfuel, coke battery and biomass operations. Generating Section 29 tax credits is important to minimizing our income tax expense. We have received favorable private letter rulings on 7 of our 9 synfuel plants and expect the remaining two in 2003. The generation of tax credits is subject to review by the Internal Revenue Service. If we failed to prevail through the administrative and legal process, there could be additional tax liabilities owed for previously taken Section 29 tax credits which could impact our earnings and cash flows. The value of future credits generated may be affected by new tax legislation. The combination of overall industry audits of Section 29 credits, supply and demand for tax credits and new tax legislation could hinder our plan to sell interests in tax credit properties which could have an impact on our earnings and cash flows.

Rate regulation – We operate in a regulated industry. Our rates are set by the MPSC and cannot be increased without their authorization. We may be impacted by new regulations or interpretations by the MPSC, 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 may require us to incur additional expenses.

Competition – Deregulation and restructuring in the electric and gas industry, including customer choice programs could result in increased competition and unrecovered costs that could affect the financial condition, results of operations or cash flows of our regulated businesses.

Supply and price of raw materials – We are dependent on coal for much of our electrical generating capacity. Price fluctuation and 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 regulated gas customers. We have hedging policies in place to mitigate negative fluctuations in commodity supply prices.

Labor relations – Unions represent a majority of our employees. A union choosing to strike as a negotiating tactic could have an impact on our business.

Unplanned outages – Unforeseen maintenance may be required to safely produce electricity or comply with environmental regulations. This occurrence could result in spot market purchases of electricity in excess of our costs of generation.

Access to capital markets and interest rates – 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.

Upstream 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 – 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.

Credit ratings – Increased scrutiny of the energy industry and regulatory changes could result in credit agencies reexamining our credit rating. A change in our rating could restrict our ability to access capital markets at attractive rates and increase our borrowing costs.

Property insurance – While we seek to adequately insure our property, catastrophic damage as a result of acts of God, terrorism, war or a combination of significant unforeseen items occurring at one time could impact our operations and economic losses might not be covered in full by insurance.

Terrorism – Damage to downstream infrastructure or our own assets by terrorist groups would impact our operations. At Fermi 2, we have already increased security as a result of an NRC order and further security increases are expected. Additionally, we may assist other energy companies if terrorists were to strike their energy facilities.

Energy trading markets – Recent 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.

EMPLOYEES

The table below shows our employees as of December 31, 2002:


	Represented		Non-represented		Total

Detroit Edison		4,346		3,873		8,219
MichCon		1,508		738		2,246
Other		22		608		630

Total		5,876		5,219		11,095

There are several bargaining units for our represented employees. Of the 5,876 represented employees, 4,919 are under contracts that expire in June or October 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.		53		Chairman of the Board, Chief Executive Officer, President, Chief Operating Officer		8-1-98
Gerard M. Anderson		44		Group President, Energy Resources		5-31-01
Robert J. Buckler		53		Group President, Energy Distribution		5-31-01
Stephen E. Ewing		58		Group President, Energy Gas		5-31-01
David E. Meador		45		Senior Vice President and Chief Financial Officer		5-31-01
Bruce D. Peterson		46		Senior Vice President and General Counsel		6-25-02
S. Martin Taylor		62		Senior Vice President		4-28-99
Susan M. Beale		54		Vice President and Corporate Secretary		12-11-95
Daniel G. Brudzynski		42		Vice President and Controller		2-8-01

(1)

As of December 31, 2002

Under our By-Laws, 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. Peterson and Ewing, 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. He joined Hunton & Williams in 1982 and later rejoined that firm in 1988 after serving in the U.S. Foreign Service, Department of State.

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 permissible 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 three insurance policies providing aggregate coverage in the amount of $100 million.

Selected Financial Data

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


		(in Millions, except per share amounts)	2002		2001(1)		2000		1999		1998

Operating Revenues			$	6,729	$	5,787	$	4,638	$	4,499	$	4,174
Net Income
	Regulated operations		$	418	$	203	$	427	$	434	$	412
	Non-regulated operations (3)			168		109		41		49		31

	Income from continuing operations (2)			586		312		468		483		443
	Discontinued operations (4)(5)			46		20		—		—		—

Net Income			$	632	$	332	$	468	$	483	$	443

Diluted Earnings Per Share (2)
	Regulated operations		$	2.53	$	1.32	$	2.99	$	3.00	$	2.83
	Non-regulated operations (3)			1.02		.71		.28		.33		.22

	Diluted earnings per share from continuing operations (2)			3.55		2.03		3.27		3.33		3.05
	Discontinued operations (4)(5)			.28		.13		—		—		—

Diluted Earnings Per Share			$	3.83	$	2.16	$	3.27	$	3.33	$	3.05

Dividends Declared Per Share of Common Stock			$	2.06	$	2.06	$	2.06	$	2.06	$	2.06
At year end:
Total Assets			$	19,238	$	18,881	$	12,656	$	12,316	$	12,088
Long-Term Debt Obligations, including capital leases			$	7,514	$	7,654	$	4,039	$	4,091	$	4,323
Redeemable Preferred Stock			$	271	$	274	$	—	$	—	$	—
Shareholders’ Equity			$	4,565	$	4,589	$	4,009	$	3,909	$	3,698

(1)		Includes the operations of MCN Energy from the May 31, 2001 acquisition date.

(2)		2001 earnings were favorably impacted by $3 million or $.02 per share due to an accounting change.

(3)		Includes Corporate & Other.

(4)		Represents the operations of ITC that were sold on February 28, 2003.

(5)		2001 reflects seven months of activity from June 1, 2001 through December 31, 2001.

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

RESULTS OF OPERATIONS

Diluted Earnings Per Share Increased - Our earnings in 2002 were $632 million, or $3.83 per diluted share, compared to earnings of $332 million, or $2.16 per diluted share in 2001. The comparability of earnings was impacted by merger and restructuring charges and goodwill amortization associated with the MCN Energy merger that reduced 2001 after-tax earnings by $204 million, or $1.32 per diluted share. Earnings were also affected by improved margins in our regulated Energy Resources business, a full year of contributions from our Energy Gas business that was acquired in May 2001 in conjunction with the MCN Energy acquisition and increased contribution from our non-regulated businesses, primarily synfuels. Partially offsetting these improvements were higher operation and maintenance expenses, and interest expense. The issuance of 29 million shares of DTE Energy common stock in conjunction with the May 2001 MCN Energy acquisition, net of 10.5 million shares repurchased in 2001, and the issuance of 6.325 million shares in June 2002, also impacted the earnings per share comparison.

Earnings in 2001 decreased $136 million, or $1.11 per diluted share from 2000. As previously discussed, the earnings decline was due to significant merger and restructuring charges and goodwill amortization recorded in 2001. Additionally, merger and restructuring charges were recorded in 2000 reducing income by $16 million, or $.12 per diluted share. Excluding merger and restructuring charges and goodwill amortization, earnings reflect contributions from our Energy Gas business and from our non-regulated businesses. Partially offsetting these improvements were increased interest on long-term debt and lower margins from regulated electricity operations.

Strategic direction – We are committed to increasing our annual earnings at a 6% average rate. Our growth strategy is to strengthen the core electric and gas utilities, add to our portfolio of non-regulated businesses and leverage investments in energy technology. Non-regulated growth is expected to shift over the next few years from profits from tax advantaged coal-based fuels businesses that generate Section 29 tax credits to growth from energy technologies, on-site energy projects, generation projects, energy trading, coal services, waste coal recovery and coal bed methane.

We operate our businesses through three strategic business units (Energy Resources, Energy Distribution and Energy Gas). Each business unit has regulated and non-regulated operations. The balance of our business consists of Corporate & Other. Based on this structure, we set strategic goals, allocate resources and evaluate performance.


(in Millions, except per share data)			2002			2001(1)			2000

Net Income (Loss)
Energy Resources
	Regulated - Power Generation		$	241		$	149		$	252

	Non-regulated
		Energy Services		182			115			100
		Energy Marketing & Trading		25			44			10
		Other		7			6			(7	)

	Total Non-regulated			214			165			103

				455			314			355

Energy Distribution
	Regulated - Power Distribution			111			92			175
	Non-regulated			(16	)		(10	)		(10	)

				95			82			165

Energy Gas
	Regulated - Gas Distribution			66			(38	)		—
	Non-regulated			26			11			—

				92			(27	)		—

Corporate & Other				(56	)		(57	)		(52	)

Total Net Income
	Regulated			418			203			427
	Non-regulated (2)			168			109			41

	Income from continuing operations			586			312			468
	Discontinued operations (3)			46			20			—

			$	632		$	332		$	468

Diluted Earnings Per Share
Regulated			$	2.53		$	1.32		$	2.99
Non-regulated (2)				1.02			.71			.28

Income from continuing operations				3.55			2.03			3.27
Discontinued operations (3)				.28			.13			—

Net Income			$	3.83		$	2.16		$	3.27

(1)		2001 earnings were favorably impacted by $3 million, or $.02 per share, due to an accounting change.

(2)		Includes Corporate & Other.

(3)		Represents the operations of ITC that were sold on February 28, 2003. (Note 4)

ENERGY RESOURCES

Power Generation

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

Factors impacting income: Power Generation earnings increased $92 million in 2002 and decreased $103 million in 2001, compared to the prior year. Merger and restructuring charges of $34 million (net of tax) recorded in 2001 impact the comparability of results relative to 2002 and 2000. As subsequently discussed, these results reflect changes in gross margins, increased operation and maintenance expenses, lower depreciation and amortization expenses and reduced property taxes.


	2002			2001			2000
(in Millions)
Operating Revenues	$	2,711		$	2,788		$	2,911
Fuel and Purchased Power		(1,048	)		(1,231	)		(1,242	)

Gross Margin		1,663			1,557			1,669
Operation and Maintenance		(626	)		(571	)		(492	)
Depreciation and Amortization		(331	)		(385	)		(468	)
Taxes other than Income		(156	)		(148	)		(176	)
Merger and restructuring charges		—			(52	)		—

Operating Income		550			401			533
Other Income and (Deductions)		(189	)		(184	)		(161	)
Income Tax Provision		(120	)		(65	)		(120	)
Cumulative Effect of Accounting Change (Note 15)		—			(3	)		—

Net Income	$	241		$	149		$	252

Operating Income as a Percent of Operating Revenues		20	%		14	%		18	%

Gross margins in 2002 improved $106 million due primarily to significantly lower purchased power costs, partially offset by reduced operating revenues. Average purchased power cost per unit in 2002 declined $39.08 per Megawatthour (MWh) from 2001 levels. The decline in revenues was due to a full year impact of a 5% legislatively mandated rate reduction for commercial and industrial customers that began in April 2001. Revenues from wholesale customers were reduced reflecting lower power prices. Revenues from retail customers were affected by customers switching to alternative suppliers under the electric Customer Choice program (Note 6). Partially offsetting these revenue reductions was the impact of weather, resulting in a 10% increase in cooling demand during 2002.

Gross margins in 2001 declined by $112 million reflecting lower operating revenues, slightly offset by lower fuel and purchased power costs. The reduced operating revenues were due to the impact of an economic recession, the electric Customer Choice program and securitization. Sales rates for commercial and industrial customers were lowered by the 5% rate reduction in April 2001. Commercial and industrial sales decreased due to increased participation of customers in the electric Customer Choice program. Industrial sales also reflect reduced auto and steel production, and the end of a special energy sales agreement with a large steel manufacturer in March of 2001. Partially offsetting these declines were increased revenues from residential and wholesale customers as well as higher revenues from providing other energy related services. Residential customer revenues reflect higher demand resulting from weather, partially offset by the impact of a 5% rate reduction that began in June 2000. Revenues from wholesale customers increased due to gains from settling forward sales contracts. The sales contracts were entered into to effectively close forward purchase contracts that hedged power supply costs. Accordingly, the gains from forward sales contracts were substantially offset by losses from forward purchase contracts, which are recorded as part of fuel and purchased power costs. Fuel and purchased power costs were also affected by lower system output resulting from reduced electric sales, as well as the result of using a more favorable power supply mix. The supply mix reflects an increased usage of lower-cost power from our generating plants and reduced usage of higher-cost purchased power.


(in Thousands of MWh)			2002				2001				2000

Power Generated and Purchased
Power Plant Generation
	Fossil
		Coal		37,381	64	%		38,424	69	%		40,039	67	%
		Natural Gas		1,414	2			1,283	2			1,667	3
		Other		222	1			4	—			394	1
	Nuclear (Fermi 2)			9,301	16			8,555	16			8,239	14

				48,318	83			48,266	87			50,339	85
Purchased Power				9,807	17			7,482	13			8,877	15

System Output				58,125	100	%		55,748	100	%		59,216	100	%

Average Unit Cost ($/MWh)
Generation (1)			$	12.53			$	12.31			$	12.78

Purchased Power (2)			$	39.16			$	78.24			$	62.57

Overall Average Unit Cost			$	17.02			$	21.15			$	20.24

(1) Represents fuel costs associated with power plants

(2) Includes amounts associated with hedging activities

Operation and maintenance expense increased $55 million in 2002 and $79 million in 2001. Expense in both periods reflect an increase in planned and unplanned maintenance and reliability work for our power generation facilities, which reduces random outages at power plants and our reliance on purchased power. Both periods also include higher employee pension and health care benefit costs, costs allocated from DTE Energy corporate for corporate support services, as well as the cost of funding the low income and energy efficiency fund. The funding of the low income and energy efficiency program was required under Michigan legislation and is recovered in current sales rates.

Depreciation and amortization expense decreased $54 million in 2002 and $83 million in 2001. The declines reflect the extension of the amortization period from seven years to 14 years for certain regulatory assets that were securitized in 2001. See Note 6 – Regulatory Matters.

Taxes other than income increased $8 million in 2002 and decreased $28 million in 2001. The 2001 decrease was due to lower property taxes resulting from new valuation tables approved by the Michigan State Tax Commission (STC). Several local taxing jurisdictions have taken legal action against the state of Michigan to prevent the STC from implementing the new valuation tables. See Note 16 – Commitments and Contingencies.

Merger and restructuring charges represent costs associated with a work force reduction plan. The plan included early retirement incentives and voluntary separation agreements for employees in overlapping corporate support areas.

Outlook – Electric restructuring is expected to continue to result in increased customer choice in the retail electric generation business. Effective January 1, 2002, the electric Customer Choice program in Michigan was expanded to allow all electric customers to purchase their electricity from suppliers other than their local utility. As a result of customers choosing to participate in the electric Customer Choice program Detroit Edison lost 6% of retail sales in 2002 and estimates losing 10% to 13% of such sales in 2003. If Detroit Edison is unable to recover its fixed costs from retail customers due to lost sales under electric Customer Choice (stranded costs), Michigan law allows for the recovery of all such amounts from electric Customer Choice customers. Detroit Edison recorded a $21 million regulatory asset in 2002 representing stranded costs and other recoverable costs under Michigan legislation. The regulatory asset was calculated based on a refinement to the methodology approved by the Michigan Public Service Commission (MPSC). The regulatory asset will be subject to review in future regulatory proceedings and we cannot predict the outcome of this matter. See Note 6 – Regulatory Matters.

Operating results are expected to vary as a result of various external factors such as weather, changes in economic conditions and the level of customer participation in the electric Customer Choice program.

Energy Services

Energy Services is comprised of Coal-Based Fuels, On-Site Energy Projects and Merchant Generation. Coal-Based Fuels operations include producing synthetic fuel from nine synfuel plants and producing coke from three coke battery plants. Both processes generate tax credits under Section 29 of the Internal Revenue Code. On-Site Energy Projects include pulverized coal, power generation, steam production, chilled water, wastewater treatment and compressed air. Merchant Generation owns and operates four gas-fired peaking electric generating plants and develops and acquires gas and coal-fired generation.


		2002			2001			2000
(in Millions)
Operating Revenues
	Coal-Based Fuels	$	599		$	365		$	293
	On-Site Energy Projects		63			53			33
	Merchant Generation		20			16			12

			682			434			338
Fuel and Purchased Power			(380	)		(116	)		(61	)
Operation and Maintenance			(320	)		(323	)		(260	)
Depreciation, Depletion and Amortization			(23	)		(36	)		(29	)
Taxes other than Income			(14	)		(6	)		(1	)

Operating Loss			(55	)		(47	)		(13	)
Other Income and (Deductions)			(27	)		(11	)		(15	)
Income Tax Benefit			264			173			128

Net Income		$	182		$	115		$	100

Factors impacting income: Earnings increased $67 million in 2002 and $15 million in 2001. Both periods reflect an increase in synfuel production, partially offset by a reduction in coke battery ownership. Four new synfuel production facilities became operational in 2002, compared to three new facilities in 2001. We sold a 95% interest in two of our synfuel projects during 2002. Tax credits from coke battery production decreased in both years reflecting the sale of a 49% interest in two of our coke battery projects in 2001. In 2002, consistent with the original purchase and sale agreement, our interest in the third coke battery was reduced from 95% to 5%.

Operating revenues and expenses increased significantly in 2002 and 2001 reflecting higher synfuel production. Synfuel projects generate operating losses which are offset by the resulting tax credits.


			2002		2001		2000
(Dollars in Millions)
Coal-Based Fuels Statistics
	Synfuel Plants:
		Operational		9		5		2

		Tax Credits Generated (1)	$	180.2	$	64.1	$	11.7

	Coke Battery Plants:
		Operational		3		3		3

		Tax Credits Generated (1)	$	57.4	$	88.6	$	106.5

(1) DTE Energy’s portion of total tax credits generated

Outlook – Energy Services strategy is to continue leveraging our extensive energy-related operating experience, and construction management capability to develop and grow the on-site energy and merchant generating businesses. We continue to evaluate opportunities to sell interests in some or all of our synfuel plants. Sales of interests in synfuel projects allow us to accelerate cash flow while maintaining a stable net income base. Coke battery tax credits expired at two of our three facilities in 2002 and the synfuel tax credits are scheduled to expire in 2007.

Energy Marketing & Trading

Energy Marketing & Trading consists of the electric and gas marketing and trading operations of DTE Energy Trading Company and CoEnergy Trading Company, which was acquired as part of the MCN Energy acquisition in May 2001. Energy Marketing & Trading focuses on physical power marketing and structured transactions, as well as the enhancement of returns from DTE Energy’s natural gas pipeline and storage assets. To this end, Energy Marketing & Trading enters into forwards, futures, swaps and option contracts as part of its trading strategy.

Factors impacting income: Earnings decreased $19 million in 2002 and increased $34 million in 2001 due to varying mark-to-market gains resulting from changes in gas and electric prices. Commodity price risk of the Energy Marketing & Trading segment is managed by utilizing derivative financial contracts to offset the risk inherent in the segment’s portfolio of electric and gas supply and sales agreements. The segment’s objective is to enter into new transactions that can be hedged and profitable from an economic standpoint. Energy Marketing & Trading accounts for this risk minimization strategy by marking to market its commodity forwards and financial derivatives so they substantially offset. This fair value accounting better aligns financial reporting with the way the business is managed and its performance measured.

In 2001, Energy Marketing & Trading experienced earnings volatility as a result of its production-related gas supply as well as from open positions related to its long-term gas transportation and storage assets. The segment receives gas produced from DTE Energy’s Exploration & Production (E&P) operations which is used to meet its commitments under long- term contracts with cogeneration customers. The E&P gas does not qualify for mark-to-market accounting. Energy Marketing & Trading recorded a gain in 2001 totaling approximately $50 million, net of taxes, primarily attributable to marking to market sales contracts with power generation customers without recording an offsetting loss from marking to market the production-related gas supply. In December 2001, Energy Marketing & Trading entered into hedge transactions that substantially mitigate the earnings volatility related to the gas contracts with power generation customers.

Energy Marketing & Trading deploys a gas storage, marketing and trading strategy primarily utilizing the facilities owned and operated by DTE Energy. Employing a combination of physical and financial contracts, in conjunction with the injection and withdrawal capabilities of the storage fields, the segment is able to capture seasonal price spreads. As forward prices change, the timing of the physical flow of gas is optimized to obtain the highest margin. Trades under this strategy are marked to market against the forward curve. Through December 2002, physical gas in storage was marked to the current spot price under fair value accounting rules. This difference in accounting for forward trades and gas in storage resulted in earnings volatility in 2002 and 2001 when price changes in the spot month did not correspond with those in future delivery months. Gas in storage in December 2002 was priced at a spot market rate of $5.10 per thousand cubic feet (Mcf), compared to $2.77 per Mcf in December 2001 and a May 31, 2001, acquisition date rate of $4.10 per Mcf. Significantly smaller changes in forward prices occurred during these same periods. As a result, the mark-to-market gains and losses on gas inventory were only partially offset by mark-to-market losses and gains on the storage-related derivatives.

Outlook – Energy Marketing & Trading will seek to gradually expand this business in a manner consistent with and complementary to the growth of our other business segments. Gas storage and transportation capacity enhances its 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 capitalize on opportunities for expansion of its market base.

Energy Marketing & Trading manages commodity price risk by utilizing derivative financial contracts to more fully balance its portfolio of gas and electric supply and sales agreements. Energy Marketing & Trading attempts to maintain a balanced, or flat book from an economic standpoint. However, Energy Marketing & Trading will experience earnings volatility as a result of its gas inventories and associated hedges. As discussed in Note 2, effective January 1, 2003, gas inventory does not qualify for mark-to- market accounting as a result of the rescission of Financial Accounting Standards Board Emerging Issues Task Force (EITF) Issue No. 98-10.

Non-regulated - Other

Our other non-regulated businesses are comprised of our Coal Services and Biomass units. Coal Services specializes in minimizing energy production costs and maximizing reliability of supply for energy-intensive use customers. Biomass develops, owns and operates landfill recovery systems in the U.S. Gas produced from these landfill sites qualifies for Section 29 tax credits.

Factors impacting income: Earnings rose $1 million in 2002 and $13 million in 2001, reflecting higher revenues from an increase in the shipment of coal, as well as an increase in revenues and tax credits resulting from an increase in gas produced.

Outlook – We expect to continue to grow our Coal Services and Biomass units. Biomass currently has 30 operating sites and other projects under development. Section 29 tax credits related to Biomass operations expire in 2007.

ENERGY DISTRIBUTION

Power Distribution

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


	2002			2001			2000
(in Millions)
Operating Revenues	$	1,227		$	1,199		$	1,218
Fuel and Purchased Power		(26	)		(10	)		(29	)
Operation and Maintenance		(533	)		(464	)		(460	)
Depreciation, Depletion and Amortization		(246	)		(246	)		(251	)
Taxes other than Income		(117	)		(119	)		(113	)
Merger and restructuring charges		—			(114	)		—

Operating Income		305			246			365
Other Income and (Deductions)		(136	)		(129	)		(129	)
Income Tax Provision		(58	)		(25	)		(61	)

Net Income	$	111		$	92		$	175

Operating Income as a Percent of Operating Revenues		25	%		21	%		30	%

Factors impacting income: Earnings increased $19 million in 2002 and decreased $83 million in 2001. The 2002 increase is due primarily to merger and restructuring charges in 2001 of $114 million, and higher operating revenues partially offset by $69 million of increased operating and maintenance expenses. Operation and maintenance expenses were affected by expenses associated with restoring power to customers who lost service during two catastrophic storms during 2002, as well as heat-related maintenance expenses due to prolonged periods of above normal summer temperatures and the related stress placed on the distribution system. Additionally, operation and maintenance expenses reflect increased costs associated with customer service process improvements, uncollectible accounts expense, and employee benefit expenses. Operating revenues increased due primarily to higher residential sales attributable to greater cooling demand.

The decrease in 2001 earnings is due primarily to merger and restructuring costs and a 5% rate reduction that began in June 2000, partially offset by higher weather related residential sales in 2001.

Below are volumes associated with the regulated power distribution business:


	2002		2001		2000
(in Thousands of MWh)
Electric Deliveries
Residential		15,958		14,503		13,903
Commercial		18,395		18,777		19,762
Industrial		13,590		14,430		16,090
Wholesale		2,249		2,159		2,277

		50,192		49,869		52,032
Electric Choice		3,510		1,268		202

Total Electric Deliveries		53,702		51,137		52,234

Outlook – Regulated electric system deliveries are expected to continue to increase in 2003 due to continued territory and economic growth. Operating results are expected to vary as a result of various external factors such as weather, changes in economic conditions and the severity and frequency of storms. In January 2003, we sold our steam business and will record a net of tax loss in the 2003 first quarter of approximately $13 million.

Power Transmission – Discontinued Operations

Power Transmission operations transmit electricity generated by Energy Resources and alternative electric suppliers. The transmission assets of ITC are operated by the Midwest Independent System Operator, a regional transmission operator. In the fourth quarter of 2002, we entered into an agreement to sell ITC for approximately $610 million. The sale closed on February 28, 2003 and generated a preliminary net of tax gain of approximately $69 million. Accordingly, the operations of the Power Transmission business are reflected as a discontinued operation.

Power Transmission earnings increased $26 million in 2002. The earnings comparison is affected by the formation of ITC and it subsequently becoming a wholly-owned subsidiary of DTE Corporate on May 31, 2001. Accordingly, 2001 results only include seven months of operations.

Prior to May 31, 2001, Detroit Edison owned and operated the transmission assets of ITC, which were vertically integrated with its other operations. Accordingly, revenues, expenses and cash flows associated with these transmission assets were bundled with Detroit Edison’s Power Distribution operations. Significant changes in regulation over the past few years required Detroit Edison to cede operating control of its transmission assets to an independent system operator or to sell its transmission assets. In response to these new requirements we formed ITC and transferred our transmission assets to this wholly-owned subsidiary with the intent of divesting ITC. Effective June 1, 2001, the transmission assets of ITC

were transferred to DTE Corporate and its revenues, expenses and cash flows were separately monitored to measure its financial and operating performance. Accordingly, the presentation of discontinued operations in the consolidated statement of operations reflects the results of ITC after May 31, 2001. The financial results of the transmission business prior to June 1, 2001 are included as part of the Power Distribution segment.

The improvement in earnings in 2002 compared to 2001 is also due to higher revenues reflecting an increase in electric deliveries driven by an increase in cooling demand.

Several Midwest utilities seek to recover lost transmission revenues associated with the creation of multiple regional transmission organizations in the Midwest. Positions advocated by several parties in a Federal Energy Regulatory Commission (FERC) proceeding could require that Detroit Edison and its customers be responsible for increased transmission costs. Detroit Edison continues to actively participate in this proceeding and depending upon the outcome would subsequently seek rate recovery of these costs.

Non-Regulated

Non-regulated energy distribution operations consist primarily of DTE Energy Technologies that markets and distributes a broad portfolio of distributed generation products, provides application engineering, and monitors and manages system operations.

Factors impacting income: Losses increased $6 million during 2002 due primarily to expenses associated with the establishment of new sales offices in the distributed generation business.

Outlook – DTE Energy Technologies expects to continue the expansion of its product portfolios and support capabilities in North America and the development of marketing relationships in other parts of the world. We plan to develop and launch new products in 2003 that are critical to our plan to increase revenues and generate operating profits by 2004.

ENERGY GAS

Gas Distribution

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


	2002			2001			2000
(in Millions)
Operating Revenues	$	1,369		$	615		$	—
Fuel and Purchased Power		(774	)		(304	)		—

Gross Margins		595			311			—
Operation and Maintenance		(297	)		(194	)		—
Depreciation, Depletion and Amortization		(104	)		(61	)		—
Taxes other than Income		(51	)		(24	)		—
Merger and restructuring charges		—			(81	)		—

Operating Income		143			(49	)		—
Other Income and (Deductions)		(41	)		(38	)		—
Income Tax Benefit (Provision)		(36	)		49			—

Net Income	$	66		$	(38	)	$	—

Operating Income as a Percent of Operating Revenues		10	%		n/m	%		—	%

n/m - not meaningful

Factors impacting income: Gas Distribution had income of $66 million in 2002 compared to a loss of $38 million in 2001. The significant improvement in 2002 reflects a full year of operations from MichCon, which was acquired in conjunction with the MCN Energy merger in May 2001. In contrast to 2001, the 2002 results include the January through April period when demand for natural gas is at its highest. Additionally, the 2001 period includes $81 million of merger and restructuring costs.

Warmer than normal weather during 2002 and 2001 reduced Gas Distribution’s earnings by $11 million and $13 million, respectively. Operations and maintenance expenses in 2002 were affected by higher uncollectible accounts expense, employee benefit expenses, and costs associated with customer service process improvements.

The pro-forma impact of the MCN Energy acquisition on DTE Energy is discussed in Note 4 – Acquisitions and Dispositions.

Outlook – Gas restructuring is expected to continue to result in increased customer choice in the gas sales business. In December 2001, the MPSC issued an order that continues the gas Customer Choice program on a permanent and expanding basis beginning with the conclusion of the three-year temporary program on March 31, 2002. Under the expanded program, beginning April 1, 2002, up to approximately 40% of customers could elect to purchase gas from suppliers other than MichCon. Beginning in April 2003, up to approximately 60% of customers could participate and beginning April 2004, all 1.2 million of MichCon’s gas customers could choose to participate. 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. As of December 2002, approximately 190,000 customers were participating in the gas Customer Choice program.

Under the MPSC order, MichCon returned to a gas cost recovery (GCR) mechanism upon termination of its three-year experimental Gas Sales Program in December 2001. Under the GCR mechanism, the gas commodity component of MichCon’s sales rates is designed to recover the actual costs of gas purchases. In December 2001, the MPSC issued an order permitting MichCon to implement GCR factors up to $3.62 per 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 will be subject to the 2002 GCR reconciliation process. In July 2002, in response to a petition for rehearing filed by the Michigan Attorney General, the MPSC directed the parties to address MichCon’s implementation of the December 2001 order and the impact of that implementation on rates charged to MichCon’s customers. Also, in July 2002, an MPSC Administrative Law Judge (ALJ) issued a Proposal for Decision on MichCon’s 2002 GCR plan case. In that decision the ALJ recommended adoption of the MPSC Staff’s proposed $26.5 million reduction in gas cost due to MichCon’s decision to utilize storage gas during 2001 that resulted in a gas inventory decrement for the 2001 calendar year. On March 12, 2003, the MPSC ordered MichCon to reduce revenues by $26.5 million for purposes of calculating the 2002 GCR expense in the 2002 GCR reconciliation proceeding. See Note 6 - Regulatory Matters – Gas Industry Restructuring and Note 21 Subsequent Event – Regulatory Matters – Gas Industry Restructuring.

Gas Distribution’s future operating results will vary as a result of weather and changes in economic conditions.

Non-regulated

Non-regulated operations include the gas and oil Exploration & Production business, and the gas Pipelines & Processing business. E&P produces gas from proven reserves owned in northern Michigan and sells the gas to the Energy Marketing & Trading segment. Pipelines & Processing has partnership interests in two interstate transmission pipelines, seven carbon dioxide processing facilities and a natural gas storage field. The assets of these businesses primarily support the Energy Marketing & Trading segment.

Factors impacting income: Earnings were $26 million in 2002 compared with $11 million in 2001. The results reflect a full year of operations of the E&P and Pipeline & Processing businesses that were acquired in conjunction with the MCN Energy acquisition in May 2001.

Outlook – We expect to further develop our gas production properties in northern Michigan and our pipelines, processing and storage assets to support other DTE Energy businesses. Additionally, we expect to continue exploring opportunities in the coal bed methane gas production business to leverage our E&P capabilities, skills and experience.

CORPORATE & OTHER

Corporate & Other had a loss of $56 million in 2002 compared with a loss of $57 million in 2001. Results in 2002 reflect higher interest expense resulting from increased debt and a full year impact of corporate debt assumed in the MCN Energy acquisition. Additionally, 2002 results reflect a reserve of $11 million (pre-tax) for the possible loss associated with direct loans to and the guarantee of debt of a technology investment. Losses in 2001 include merger and restructuring charges and the amortization of goodwill associated with the MCN Energy acquisition.

CAPITAL RESOURCES AND LIQUIDITY


			2002			2001			2000
(in Millions)
Cash and Cash Equivalents
Cash Flow From (Used For)
	Operating activities:
		Net income, depreciation, depletion and amortization	$	1,391		$	1,127		$	1,226
		Merger and restructuring charges		—			215			—
		Deferred income taxes		(208	)		(7	)		(133	)
		Working capital and other		(209	)		(524	)		(78	)

				974			811			1,015
	Investing activities (1)			(1,115	)		(2,286	)		(674	)
	Financing activities (2)			6			1,679			(310	)

Net Increase (Decrease) in Cash and Cash Equivalents			$	(135	)	$	204		$	31

(1)		Includes acquisition of MCN Energy in 2001.

(2)		Includes $1.75 billion of securitization bonds issued in 2001.

Operating Activities

Our consolidated net cash from operating activities increased $163 million in 2002 and decreased $204 million in 2001. We use cash derived from operating activities to maintain and expand our core electric and gas utility businesses and to grow our non-regulated businesses. In addition, we use cash from operations to retire long-term debt and pay dividends. The increase in 2002 was attributable to higher net income, after adjusting for noncash items (depreciation, amortization and deferred taxes), partially offset by higher working capital requirements. Working capital requirements reflect an increase in accounts receivable and gas inventories. Accounts receivable collections were slowed in our utility business due to billing issues associated with our new combined billing system that have been resolved. The decline in 2001 resulted primarily from lower earnings, after adjusting for noncash items including merger and restructuring charges, and higher working capital requirements. Working capital was affected by the seasonal requirements in the second half of 2001 of the gas business where cash is used to finance increases in gas inventories and customer accounts receivable.

Outlook – We expect our cash flow from operations will increase in 2003 due to earnings growth, and by better managing our working capital requirements, including the continued focus of reducing past due accounts receivable. These expected improvements will be partially offset by a $222 million contribution to our pension plan in January 2003.

Investing Activities

Our net cash used for investing activities decreased $1.2 billion in 2002 and increased $1.6 billion in 2001. The cash consideration portion of the MCN Energy acquisition totaled $1.2 billion and impacts the comparison of the periods. In 2002, capital expenditures in regulated and non-regulated businesses were lower, partially offset by reduced proceeds from the sale of non-strategic assets. In 2001, higher regulated capital expenditures at Detroit Edison were due to new air quality regulations that require reductions in nitrogen oxide levels as discussed in the following “Environmental Matters” section.

Outlook – Our strategic direction anticipates base level capital investments and expenditures for existing businesses in 2003 totaling approximately $850 million, of which approximately $700 million will be in regulated gas and electric operations and the remaining $150 million in non-regulated businesses. Approximately $100 million of the regulated capital expenditures will be incurred by our Power Generation business to comply with new ozone and air quality regulations. Investments in new non-regulated growth businesses could push actual capital investments and expenditures over $1 billion. The actual level of non-regulated investments and expenditures will depend on new market opportunities. We also sold ITC in 2003 for $610 million.

The proposed level of investments and expenditures in future years is expected to be financed primarily with internally generated funds, including proceeds from the sale of non-strategic assets. We will evaluate divesting of assets and investments that do not meet certain return criteria or are not consistent with our strategic direction to maximize shareholder value.

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

Financing Activities

Our consolidated net cash related to financing activities decreased $1.7 billion in 2002 and increased $2 billion in 2001. The 2001 issuance of $1.75 billion of securitization bonds and the 2001 issuance of $1.35 billion of long-term debt to finance the acquisition of MCN Energy impacts the comparison of the periods. In 2002, proceeds from the issuance of debt and common stock were used for the redemption of higher cost debt and to reduce short-term borrowings. In 2001, proceeds from the issuance of securitization bonds and other Detroit Edison and MichCon debt were used to repay debt and repurchase our common stock. Details of 2002 financing activities follows:

•		In January 2002, DTE Energy Trust I, a wholly owned trust of the company, issued $180 million of 7.8% Trust Preferred Securities. The proceeds were used to redeem the 8-5/8% Trust Originated Preferred Securities and the 9-3/8% Redeemable Cumulative Preferred Securities.

•		In April 2002, DTE Energy issued $200 million of 6.65% senior notes, due 2009. The proceeds were used to retire MCN Energy Enterprises Remarketable Securities that had an aggregate principal amount of $100 million, and to reduce short-term borrowings.

•		In June 2002, DTE Energy issued 6.9 million equity-linked security units at $25 per unit. An equity security unit consists of a stock purchase contract and a senior note of DTE Energy. DTE Energy used the net proceeds of $167 million from this issuance for general corporate purposes, including the repayment of short-term borrowings.

•		In June 2002, DTE Energy also issued 6.325 million shares of common stock at $43.25 per share, grossing $273.6 million. Net proceeds from the common stock offering were $265 million and were used for general corporate purposes.

•		In October 2002, Detroit Edison issued $225 million of 5.20% senior notes, due 2012, and $225 million of 6.35% senior notes, due 2032. The proceeds were used for general corporate purposes, including debt redemptions and the repayment of short-term borrowings.

•		In December 2002, Detroit Edison issued $64 million of 5.45% tax exempt bonds and $56 million of 5.25% tax exempt bonds, due 2032. The proceeds were used for the refunding of tax exempt bonds and to finance costs to be incurred for pollution control facilities at our power plants.

In October 2002, DTE Energy, Detroit Edison and MichCon entered into separate revolving credit facilities with a syndicate of banks totaling $1.2 billion. Our revolving credit facilities contain customary covenants. One important aspect of these agreements requires us to maintain a debt to total capitalization ratio of not more than .65 to 1, and an “earnings before interest, taxes, depreciation and amortization” to interest ratio of no less than 2 to 1. See Note 13 - Short-Term Credit Arrangements and Borrowings.

DTE Energy, Detroit Edison and MichCon have effective shelf registrations with the SEC that allow for the issuance of up to $1.9 billion of debt and equity securities.

In February 2003, MichCon issued $200 million of 5.7% senior notes, due in 2033. The proceeds were used for debt redemption.

Outlook – Our capitalization objective is to maintain our credit ratings through a strong balance sheet. Our capitalization objective is a 50% to 55% leverage target (excluding certain debt, principally securitization debt.) We have issued guarantees for the benefit of various non-regulated subsidiary transactions. We do not anticipate any credit rating downgrades, however in the event that our credit rating is downgraded below investment grade certain of these guarantees would require us to post cash or letters of credit valued at approximately $200 million at December 31, 2002.

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 post retirement costs, and the allowance for doubtful accounts.

Regulation

A significant portion of our business is subject to regulation. Detroit Edison, MichCon and ITC 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 noncash loss would be as follows:


(in millions)
Regulated Entity

MichCon	$	(28	)
Detroit Edison (1)		(27	)
ITC (2)		(6	)

Total	$	(61	)

(1)		Excludes securitized regulatory assets

(2)		Discontinued operation that was sold on February 28, 2003.

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.

Risk Management and Trading Activities

All derivatives are recorded at fair value and shown as “Assets or 1iabilities 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.” 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. Effective in 2003, fair value measurements must be evidenced by similar transactions in the marketplace.

Section 29 Tax Credits

We have generated Section 29 tax credits from our synfuel, coke battery and biomass operations. Seven of our synthetic fuel facilities have received favorable private letter rulings from the Internal Revenue Service (IRS) with respect to their operations. The remaining two rulings have been requested and are expected in 2003. These tax credits are subject to review by the IRS and if we fail to prevail through the administrative and legal process, there could be a significant tax liability owed for previously taken Section 29 tax credits. Our portion of tax credits generated was $250 million in 2002, up from $165 million in 2001 and $130 million in 2000. 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. 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 estimates involve judgments based on a broad range of information and historical results. 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, 2002, our goodwill totaled $2.1 billion and we determined that no impairment exists.

Pension and Postretirement Costs

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

We had pension income for qualified pension plans of $9 million in 2002 and pension expense of $159 million in 2001 and $9 million in 2000. Postretirement benefits expense for all plans was $70 million in 2002, $104 million in 2001 and $44 million in 2000. Pension and postretirement benefits expense is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on our plan assets of 9.0% at December 31, 2002. In developing our expected long-term rate of return assumption, we evaluated input from our consultants, including their review of asset class return expectations as well as long-term inflation assumptions. Projected returns by such consultants 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 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 that 9% is a reasonable long-term rate of return on our plan assets, despite the recent financial market downturn. 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 plan assets for pension benefits 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 losses due to the recent unfavorable performance of the financial markets. As of December 31, 2002, we had cumulative losses of approximately $375 million which remain to be recognized in the calculation of the market-related value of assets. These unrecognized net losses may result in increases in our future pension expense.

The discount rate that we utilize for determining future pension and postretirement benefit obligations is based on a review of long-term 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 7.25% at December 31, 2001 to 6.75% at December 31, 2002. Due to recent financial market performance, lower discount rates and increased health care trend rates we estimate that our 2003 pension expense will approximate $70 million and our postretirement benefit expense will approximate $141 million. We have also made modifications to the pension and postretirement benefit plans to mitigate the earnings impact of the higher costs. Future actual pension and postretirement benefit expense will depend on future investment performance, changes in future discount rates and various other factors related to plan design.

Lowering the expected long-term rate of return on our pension plan assets by 0.5% would have increased our 2002 pension expense by approximately $12 million and our postretirement benefit expense by $3 million. Lowering the discount rate and the salary increase assumptions by 0.5% would have increased our pension expense for 2002 by approximately $3 million. Lowering the discount rate and the health care cost trend assumptions by 0.5% would have decreased our postretirement benefit expense for 2002 by approximately $4 million.

The market value of our pension and postretirement benefit plan assets has been affected by sharp declines in the financial markets since 2000. The value of our plan assets has decreased from $2.8 billion at December 31, 2001, to $2.4 billion at December 31, 2002. The investment performance returns and declining discount rates have required us to recognize at December 31, 2002, an additional minimum pension liability of $855 million, an intangible asset of $57 million and an entry to other comprehensive loss (shareholders’ equity) of $518 million, net of tax. The additional minimum pension liability and related accounting entries would 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 will increase in future years without a substantial recovery in the financial markets. We made a $35 million cash contribution to the pension plan in 2002 and a $222 million cash contribution in January 2003. We also contributed $33 million to the postretirement plans in 2002, and expect to contribute $80 million by the end of 2003.

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. With the implementation of a new integrated billing system in late 2001, we encountered billing issues that resulted in an MPSC inquiry. We filed a plan with the MPSC in March 2002 addressing customer billing complaints. While we have resolved the primary billing issues, we may encounter difficulty in collecting past due receivables. As a result, our allowance for doubtful accounts increased in 2002. We believe the allowance for doubtful accounts is based on reasonable estimates, however; failure to collect our past due receivables could unfavorably affect operating results and cash flow.

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. 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. The National Energy Policy Development Group is reviewing the EPA’s interpretation and application of regulations for new source review requirements. We expect this review to focus on the ability of fossil-fueled plant owners to perform plant maintenance without additional significant environmentally related modifications. While we anticipate continued ability to economically maintain our plants, the outcome of this governmental review cannot be predicted.

EPA ozone transport regulations and final new air quality standards relating to ozone and particulate air pollution will impact us. Detroit Edison has spent approximately $460 million through December 2002 and estimates that it will incur approximately $300 million to $400 million of future capital expenditures over the next five to eight years to comply.

NEW ACCOUNTING PRONOUNCEMENTS

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

CONTRACTUAL OBLIGATIONS

The following table reflects the payments due to others for contractual obligations existing at December 31, 2002:


				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	$	6,576	$	920	$	793	$	644	$	4,219
	Securitization bonds		1,673		88		185		215		1,185
	Equity-linked securities		191		6		185		—		—
	Capital lease obligations		127		16		24		25		62
Operating leases			328		40		80		71		137
Electric & gas purchase obligations			2,078		709		576		277		516
Other long-term obligations			683		110		182		70		321

Total Obligations		$	11,656	$	1,889	$	2,025	$	1,302	$	6,440

We expect 2003 capital expenditures will approximate $850 million. Certain commitments have been made in connection with such capital expenditures and are excluded from the above table.

FAIR VALUE OF CONTRACTS

Roll-Forward of Mark to Market Energy Contract Net Assets

The following table provides details on changes in our mark-to-market (MTM) net asset or (liability) position during 2002.


		Proprietary			Structured			Owned
(in Millions)		Trading (1)			Contracts (2)			Assets (3)			Total

Energy Marketing & Trading Segment
	MTM at December 31, 2001	$	(4	)	$	(171	)	$	42		$	(133	)
	Reclassification to realized at settlement of contract		1			16			(45	)		(28	)
	Reclassification to Liabilities from Transportation and Storage Contracts (4)		—			155			—			155
	Net change in option premiums		11			—			1			12
	Other changes in fair value		7			19			(48	)		(22	)

	MTM at December 31, 2002	$	15		$	19		$	(50	)		(16	)

Other DTE Energy Segments												(100	)

											$	(116	)

(1)		“Proprietary Trading” represents derivative activity transacted with the intent of capturing profits on forward price movements.

(2)		“Structured Contracts” represent derivative activity transacted with the intent to capture profits by originating substantially hedged positions with wholesale energy marketers, utilities, retail aggregators and end-users. Although transactions are generally executed with a buyer and seller simultaneously, some positions remain open until a suitable offsetting trade can be executed.

(3)		“Owned Assets” represent derivative activity associated with assets owned by DTE Energy, including forward sales of gas production and trades associated with owned transportation and storage capacity. Derivatives are generally executed with the intent of locking in and optimizing profits without creating additional risk.

(4)		Represents transportation contracts that no longer meet the definition of a derivative. The fair value of such contracts were frozen and are being amortized to income over the remaining contract terms.


	Proprietary			Structured			Owned
(in Millions)	Trading			Contracts			Assets			Eliminations			Total

Current assets	$	62		$	68		$	65		$	(10	)	$	185
Noncurrent assets		18			33			114			(16	)		149

Total MTM assets		80			101			179			(26	)		334

Current liabilities		(49	)		(58	)		(96	)		9			(194	)
Noncurrent liabilities		(16	)		(24	)		(133	)		17			(156	)

Total MTM liabilities		(65	)		(82	)		(229	)		26			(350	)

Total MTM net assets (liabilities)	$	15		$	19		$	(50	)	$	—		$	(16	)

Maturity and source of fair value of MTM energy contract net assets

The table below shows the maturity and source of how we derived the MTM positions of our energy contracts.


																				Total
(in Millions)																	Beyond 5			Fair
Source of Fair Value		2003			2004			2005			2006			2007			Years			Value

Proprietary Trading
	Actively quoted prices (1)	$	13		$	(6	)	$	(3	)	$	—		$	—		$	—		$	4
	Prices by external sources (2)		—			6			3			—			2			—			11

			13			—			—			—			2			—			15

Structured Contracts
	Actively quoted prices (1)		9			5			—			—			—			—			14
	Prices by external sources (2)		—			—			1			1			1			2			5

			9			5			1			1			1			2			19

Owned Assets
	Actively quoted prices (1)		(30	)		(14	)		(8	)		(4	)		—			—			(56	)
	Prices by external sources (2)		—			12			11			2			(6	)		(13	)		6

			(30	)		(2	)		3			(2	)		(6	)		(13	)		(50	)

Total		$	(8	)	$	3		$	4		$	(1	)	$	(3	)	$	(11	)	$	(16	)

(1)		“Actively quoted prices” represent our position where we developed forward price curves using published New York Mercantile Exchange (NYMEX) prices, over the counter (OTC) gas and power quotes. The NYMEX publishes gas futures prices for the next six years.

(2)		“Prices by external sources” represent our forward positions in power at points where OTC broker quotes are not always available. We value these positions against internally developed forward market price curves that are constantly validated and recalibrated against OTC broker quotes for closely correlated points. This category also includes “strip” transactions whose prices are obtained from external sources and then modeled to daily or monthly prices as appropriate.

Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Risk Management and Trading Activities

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. See Note 15 – Financial and Other Derivative Instruments for further discussion.

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).

Summary of Sensitivity Analysis

We performed a sensitivity analysis calculating the impact of changes in fair values utilizing applicable forward commodity rates or changes in interest rates if they occurred at December 31, 2002:


(in Millions)
Activity	Increase of 10%			Decrease of 10 %			Change in the fair value of

Gas Contracts	$	(21	)	$	7		Commodity contracts
Power Contracts	$	3		$	(1	)	Commodity contracts
Interest Rate Risk	$	(229	)	$	245		Long term debt

Credit Risk

We purchase and sell electricity, gas and coke to numerous companies operating in the steel, automotive, energy and retail industries. During 2002 and 2001, a number of customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code, including certain Enron Corporation affiliates, National Steel Company and Bethlehem Steel Company. At December 31, 2002, we had approximately $65 million of accounts receivable and approximately $40 million of accounts payable with these bankrupt companies. 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 are not expected to have a material effect on our financial statements in the period they are resolved.

Financial Statements and Supplementary Data

The following consolidated financial statements and schedules are included herein.


		Page

Independent Auditors’ Report			47
Consolidated Statement of Operations			48
Consolidated Statement of Financial Position			49
Consolidated Statement of Cash Flows			51
Consolidated Statement of Changes in Shareholders’ Equity and Comprehensive Income			52
Notes to Consolidated Financial Statements
Note 1	Significant Accounting Policies		53
Note 2	New Accounting Pronouncements		59
Note 3	Change in Accounting for Regulation		64
Note 4	Acquisitions and Dispositions		64
Note 5	Merger and Restructuring Charges		66
Note 6	Regulatory Matters		67
Note 7	Nuclear Operations		71
Note 8	Jointly Owned Utility Plant		72
Note 9	Income Taxes		73
Note 10	Common Stock and Earnings Per Share		74
Note 11	Preferred Securities		75
Note 12	Long Term Debt		77
Note 13	Short-Term Credit Arrangements and Borrowings		79
Note 14	Capital and Operating Leases		80
Note 15	Financial and Other Derivative Instruments		81
Note 16	Commitments and Contingencies		83
Note 17	Retirement Benefits and Trusteed Assets		86
Note 18	Stock-based Compensation		91
Note 19	Segment and Related Information		93
Note 20	Supplementary Quarterly Financial Information		97
Note 21	Subsequent Event – Regulatory Matters - Gas Industry Restructuring		97
Note 22	Consolidating Financial Statements		98
Schedule II – Valuation and Qualifying Accounts			106

INDEPENDENT AUDITORS’ REPORT

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, 2002 and 2001 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, 2002. Our audits also included the financial statement schedule Schedule II. 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 auditing standards generally accepted in the United States of America. 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, 2002 and 2001 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 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, the Company changed its method of accounting for goodwill and energy trading contracts in 2002. Also as discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for derivative instruments and hedging activities in 2001.

/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan
February 11, 2003 (March 12, 2003 as to Note 21 and July 10, 2003 as to Note 2 – Asset Retirement Obligations and Note 4 – Disposition of International Transmission Company – Discontinued Operation)

DTE ENERGY COMPANY
CONSOLIDATED STATEMENT OF OPERATIONS


				Year Ended December 31
(in Millions, Except per Share Amounts)				2002			2001			2000

Operating Revenues				$	6,729		$	5,787		$	4,638

Operating Expenses
	Fuel, purchased power and gas				2,099			1,919			1,305
	Operation and maintenance				2,510			1,848			1,424
	Depreciation, depletion and amortization				737			782			758
	Taxes other than income				352			305			296
	Merger and restructuring charges (Note 5)				—			268			25

					5,698			5,122			3,808

Operating Income					1,031			665			830

Other Income and Deductions
	Interest expense				544			467			336
	Preferred stock dividends of subsidiaries				25			15			—
	Interest income				(29	)		(22	)		(9	)
	Other income				(62	)		(60	)		(4	)
	Other expenses				51			75			30

					529			475			353

Income Before Income Taxes					502			190			477
Income Tax Provision (Benefit) (Note 9)					(84	)		(119	)		9

Income from Continuing Operations					586			309			468
Income from Discontinued Operations of ITC, net of tax (Note 4)					46			20			—
Cumulative Effect of Accounting Change, net of tax (Note 15)					—			3			—

Net Income				$	632		$	332		$	468

Basic Earnings per Common Share (Note 10)
		Income from continuing operations		$	3.57		$	2.02		$	3.27
		Income from discontinued operations of ITC, net of tax			.28			.13			—
		Cumulative effect of accounting change			—			.02			—

			Total	$	3.85		$	2.17		$	3.27

Diluted Earnings per Common Share (Note 10)
		Income from continuing operations		$	3.55		$	2.01		$	3.27
		Income from discontinued operations of ITC, net of tax			.28			.13			—
		Cumulative effect of accounting change			—			.02			—

			Total	$	3.83		$	2.16		$	3.27

Average Common Shares
		Basic			164			153			143
		Diluted			165			154			143
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

(in Millions)			2002			2001

ASSETS
Current Assets
	Cash and cash equivalents		$	133		$	268
	Restricted cash			237			157
	Accounts receivable
		Customer (less allowance for doubtful accounts of $82 and $57, respectively)		902			745
		Accrued unbilled revenues		296			242
		Other		237			261
	Inventories
		Fuel and gas		413			345
		Materials and supplies		163			160
	Assets from risk management and trading activities			224			191
	Other			159			110

				2,764			2,479

Investments
	Nuclear decommissioning trust funds			417			417
	Other			487			625

				904			1,042

Property
	Property, plant and equipment			17,862			17,073
	Less accumulated depreciation and depletion			(8,049	)		(7,524	)

				9,813			9,549

Other Assets
	Goodwill (Note 4)			2,119			2,003
	Regulatory assets (Note 6)			1,197			1,189
	Securitized regulatory assets			1,613			1,692
	Assets from risk management and trading activities			152			150
	Prepaid pension assets			172			435
	Other			504			342

				5,757			5,811

Total Assets			$	19,238		$	18,881

See Notes to Consolidated Financial Statements

DTE ENERGY COMPANY
CONSOLIDATED STATEMENT OF FINANCIAL POSITION


		December 31

(in Millions, Except Shares)		2002			2001

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
	Accounts payable	$	647		$	581
	Accrued interest		115			117
	Dividends payable		90			84
	Accrued payroll		49			108
	Short-term borrowings		414			681
	Current portion long-term debt, including capital leases		1,018			517
	Liabilities from risk management and trading activities		284			216
	Other		596			523

			3,213			2,827

Other Liabilities
	Deferred income taxes		916			1,486
	Regulatory liabilities		179			187
	Unamortized investment tax credit		168			180
	Liabilities from risk management and trading activities		208			310
	Liabilities from transportation and storage contracts		523			373
	Accrued pension liability		582			32
	Nuclear decommissioning		416			412
	Other		683			557

			3,675			3,537

Long-Term Debt (Note 12)
	Mortgage bonds, notes and other		5,656			5,892
	Securitization bonds		1,585			1,673
	Equity-linked securities		191			—
	Capital lease obligations		82			89

			7,514			7,654

Commitments and Contingencies (Notes 6, 7 and 16)
Obligated Mandatorily Redeemable Preferred Securities of Subsidiaries Holding Solely Debentures of DTE Energy or Enterprises			271			274

Shareholders’ Equity
	Common stock, without par value, 400,000,000 shares authorized, 167,462,430 and 161,133,959 shares issued and outstanding, respectively		3,052			2,811
	Retained earnings		2,132			1,846
	Accumulated other comprehensive loss		(619	)		(68	)

			4,565			4,589

Total Liabilities and Shareholders’ Equity		$	19,238		$	18,881

See Notes to Consolidated Financial Statements

DTE ENERGY COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS


			Year Ended December 31

(in Millions)			2002			2001			2000

Operating Activities
	Net income		$	632		$	332		$	468
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation, depletion and amortization		759			795			758
		Merger and restructuring charges		—			215			—
		Deferred income taxes		(208	)		(7	)		(133	)
		Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		(209	)		(524	)		(78	)

		Net cash from operating activities		974			811			1,015

Investing Activities
	Plant and equipment expenditures – regulated			(794	)		(776	)		(586	)
	Plant and equipment expenditures – non-regulated			(190	)		(320	)		(163	)
	Acquisition of MCN Energy, net of cash acquired			—			(1,212	)		—
	Proceeds from sales of assets			41			216			—
	Restricted cash for debt redemptions			(79	)		(70	)		43
	Other investments			(93	)		(124	)		32

	Net cash used for investing activities			(1,115	)		(2,286	)		(674	)

Financing Activities
	Issuance of long-term debt			958			4,254			273
	Redemption of long-term debt			(613	)		(1,423	)		(331	)
	Issuance of preferred securities			180			—			—
	Redemption of preferred securities			(180	)		—			—
	Short-term borrowings, net			(267	)		(282	)		116
	Capital lease obligations			(12	)		(107	)		(2	)
	Issuance of common stock			265			—			—
	Repurchase of common stock			(9	)		(438	)		(70	)
	Capital additions from synfuel partners			22			—			—
	Dividends on common stock			(338	)		(325	)		(296	)

	Net cash from (used for) financing activities			6			1,679			(310	)

Net Increase (Decrease) in Cash and Cash Equivalents				(135	)		204			31
Cash and Cash Equivalents at Beginning of Period				268			64			33

Cash and Cash Equivalents at End of Period			$	133		$	268		$	64

See Notes to Consolidated Financial Statements

DTE ENERGY COMPANY
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY AND
COMPREHENSIVE INCOME


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

Balance, December 31, 1999			145,041		$	1,943		$	1,959		$	—		$	3,902

	Net income		—			—			468			—			468
	Dividends declared on common stock		—			—			(294	)		—			(294	)
	Repurchase and retirement of common stock		(2,390	)		(32	)		(39	)		—			(71	)
	Unearned stock compensation		—			1			—			—			1
	Other		—			—			3			—			3

Balance, December 31, 2000			142,651			1,912			2,097			—			4,009

	Net income		—			—			332			—			332
	Issuance of new shares		29,017			1,060			—			—			1,060
	Dividends declared on common stock		—			—			(324	)		—			(324	)
	Repurchase and retirement of common stock		(10,534	)		(155	)		(270	)		—			(425	)
	Unearned stock compensation		—			(6	)		—			—			(6	)
	Other		—			—			11			—			11
	Net change in unrealized losses on Derivatives, net of tax		—			—			—			(69	)		(69	)
	Net change in unrealized gain on Investments, net of tax		—			—			—			1			1

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											(518	)		(518	)
	Other		—			(28	)		(3	)					(31	)
	Net change in unrealized losses on Derivatives, net of tax		—			—			—			(33	)		(33	)

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

We did not have other comprehensive income (loss) in 2000. The following table displays comprehensive income (loss) for 2002 and 2001:


(in Millions)			2002			2001

Net income			$	632		$	332

Other comprehensive income (loss), net of tax:
	Net unrealized losses on derivatives:
		Cumulative effect of a change in accounting principle, net of taxes of $24		—			(42	)
		Losses arising during the period, net of taxes of $32 and $29, respectively		(60	)		(53	)
		Amounts reclassified to earnings, net of taxes of $15 and $14, respectively		27			26

				(33	)		(69	)
	Net change in unrealized gain on investments, net of taxes of $1			—			1
	Pension obligations, net of taxes of $280			(518	)		—

Comprehensive income			$	81		$	264

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. DTE Energy was incorporated in Michigan in 1995 and is the parent company of the following subsidiaries:

•		Detroit Edison Company;

•		International Transmission Company (ITC);

•		DTE Enterprises Inc. (Enterprises); and

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

Detroit Edison is a regulated Michigan public utility engaged in the generation, purchase, distribution and sale of electric energy to 2.1 million customers in southeast Michigan.

ITC is regulated by the Federal Energy Regulatory Commission (FERC) for the transmission of electric energy. In December 2002, we entered into a definitive agreement to sell ITC. The sale of ITC closed on February 28, 2003. See Note 4 for more detail.

On May 31, 2001, DTE Energy completed the acquisition of MCN Energy, now referred to as Enterprises. See Note 4 for further discussion. Enterprises is an exempt holding company under the Public Utility Holding Company Act of 1935. Enterprises is a Michigan corporation primarily engaged in natural gas production, gathering, processing, transmission, storage, distribution and energy marketing. Enterprises largest subsidiary is MichCon, a natural gas utility serving 1.2 million customers throughout the state of Michigan.

Both Detroit Edison and MichCon are regulated by the Michigan Public Service Commission (MPSC). Detroit Edison is also regulated by the FERC.

References in this report to “we”, “us” and “our” 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. The company eliminates all intercompany balances and transactions.

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, expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from our estimates.

We reclassified some prior year balances to match the 2002 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, gas and steam heating services provided but unbilled at the end of each month. Under agreement with the MPSC, Detroit Edison is not allowed to raise rates through 2003. Through December 2001, MichCon’s rates included a component for cost of gas sold that was fixed at $2.95 per thousand cubic feet (Mcf). In 2002, MichCon implemented a gas cost recovery (GCR) mechanism that will recover the prudent and reasonable cost of gas sold subject to annual proceedings before the MPSC.

Through December 2002, our Energy Marketing & Trading segment recorded in revenues unrealized gains and losses on energy trading contracts (commodity forwards and financial derivatives) and corresponding physical positions. The recognition of unrealized gains and losses associated with energy trading activities was required under the Financial Accounting Standards Board (FASB) Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Energy Trading Activities and Risk Management Activities.” With the rescission of EITF Issue No. 98-10 in the third quarter of 2002, the recognition of unrealized gains and losses is only permitted on energy trading contracts meeting the definition of a derivative under Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Accordingly, the company no longer records unrealized gains and losses on physical positions utilized in our energy trading operations as discussed in the “Inventories” policy and Note 2 – New Accounting Pronouncements.

EITF Issue No. 98-10, permitted either gross or net presentation of mark to market gains and losses on energy trading contracts (including those to be physically settled) in the consolidated statement of operations. Based on discussions held at the June 2002 meeting of the EITF and statements made by the SEC staff, we concluded that net presentation is preferable. In the past we presented such amounts on a gross basis. As of December 31, 2002, we have presented such amounts on a net basis, and all presented prior periods have been reclassified on a consistent basis.

Comprehensive Income

We comply with 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. Significant amounts recorded to comprehensive income include minimum pension liabilities as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions,” and unrealized gains and losses associated with cash flow hedging activities under SFAS No. 133.

Inventories

Fuel inventory and materials and supplies at Detroit Edison, MichCon and other subsidiaries are valued at average cost.

Gas inventory at MichCon is determined using the last-in, first-out (LIFO) method. At December 31, 2002, the replacement cost of gas remaining in storage exceeded the $55 million LIFO cost by $187 million. At December 31, 2001, the replacement cost exceeded the $6.2 million LIFO cost by $90.9 million. During 2001, MichCon liquidated 2.1 billion cubic feet (Bcf) of prior years’ LIFO layers at an average cost of $0.39 per Mcf. MichCon’s average gas purchase rate in 2001 was $2.83 per Mcf higher than the average LIFO liquidation rate. Applying LIFO cost in valuing the liquidation, as opposed to

using the average purchase rate, decreased 2001 cost of gas by $5.8 million and increased earnings by $3.8 million, net of taxes.

Through December 2002, the Energy Marketing & Trading segment used the fair value method to price gas inventories. To comply with new accounting requirements resulting from the rescission of EITF Issue No. 98-10, the Energy Marketing & Trading segment changed to the average cost method for its gas inventories, effective January 2003.

Property, Retirement and Maintenance, and Depreciation and Depletion

Summary of property by classification as of December 31:


(in Millions)			2002			2001

Property, Plant and Equipment
	Electric Utility
		Generation	$	6,515		$	6,165
		Distribution		5,606			5,407
		Transmission (1)		813			802

	Total Electric Utility			12,934			12,374

	Gas Utility
		Distribution		1,903			1,852
		Storage		212			208
		Other		906			903

	Total Gas Utility			3,021			2,963

	Non-regulated and other			1,907			1,736

Total Property, Plant and Equipment				17,862			17,073

Less Accumulated Depreciation and Depletion
	Electric Utility
		Generation		(3,117	)		(2,948	)
		Distribution		(2,207	)		(2,062	)
		Transmission (1)		(425	)		(407	)

	Total Electric Utility			(5,749	)		(5,417	)

	Gas Utility
		Distribution		(1,127	)		(1,070	)
		Storage		(98	)		(97	)
		Other		(491	)		(459	)

	Total Gas Utility			(1,716	)		(1,626	)

	Non-regulated and other			(584	)		(481	)

Total Accumulated Depreciation and Depletion				(8,049	)		(7,524	)

Net Property, Plant and Equipment			$	9,813		$	9,549

(1)

Represents the operations of ITC that was sold on February 28, 2003.

Property is stated at cost and includes construction-related labor and materials. The cost of properties retired plus removal costs, 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 $25 million of expenses related to the anticipated Fermi 2 refueling outage scheduled for 2003 are being accrued on a pro-rata basis over an 18-month period that began in November 2001.

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 2002, 2001 and 2000. The composite depreciation rate for MichCon was 3.6% in 2002 and 3.9% in 2001.

The average estimated useful life for each class of property, plant and equipment as of December 31, 2002 follows:


Estimated Useful Lives in Years

Utility	Generation		Distribution		Transmission

Electric		39		37		36	(1)
Gas		N/A		26		29

(1)

The electric transmission assets were sold on February 28, 2003.

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

Natural Gas and Oil Exploration and Production

We follow the successful efforts method of accounting for investments in oil and gas properties. Under the successful efforts method, we capitalize the costs of property acquisitions, successful exploratory wells, development costs, support equipment and facilities. When a well is classified as non-productive, costs associated with that well are expensed. We also expense production costs, overheads, and exploration costs other than for exploratory drilling. Depreciation and depletion of proven oil and gas properties are determined using the units-of-production method over the life of the proven reserves.

Long-Lived Assets

Long-lived assets that we own 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.

Software Costs

We capitalize the cost of software developed for internal use. These costs are amortized on a straight-line basis over five years. Amortization begins when the software project is complete.

Excise and Sales Taxes

We record the billing of excise and sales taxes as receivables with an offsetting payable to the applicable taxing authority, with no impact on the 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 Detroit Edison and MichCon, 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-regulated operations are charged to earnings.

Stock-Based Compensation

We have a stock-based employee compensation plan, which is described in Note 19. 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 net income, 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)		2002			2001			2000

Net Income As Reported		$	632		$	332		$	468
Less: Total Stock-based Expense (1)			(7	)		(9	)		(2	)

Pro Forma Net Income		$	625		$	323		$	466

Earnings Per Share
	Basic – as reported	$	3.85		$	2.17		$	3.27

	Basic – pro forma	$	3.81		$	2.11		$	3.26

	Diluted – as reported	$	3.83		$	2.16		$	3.27

	Diluted – pro forma	$	3.79		$	2.10		$	3.25

(1)

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

Issuance of Stock by Equity Investees

DTE Energy and Mechanical Technology Incorporated formed Plug Power Inc. to design and develop on-site electric fuel cell power generation systems. In 1999, Plug Power completed an initial public offering (IPO) of common stock at $15 per share. After the IPO, we owned approximately 32% of Plug Power’s outstanding common stock. Since Plug Power is considered a development stage company, generally accepted accounting principles require us to record gains and losses from Plug Power stock issuances as an adjustment to equity. As a result of Plug Power’s IPO, we recorded an increase of $44 million in our investment and an after-tax increase of $28 million to equity in 1999. In July 2001, Plug Power completed a second public offering of common stock at $12 per share. After this public offering, we owned approximately 28% of Plug Power’s outstanding common stock and recorded an increase of $17 million in our investment and an after-tax increase of $11 million to equity.

Consolidated Statement of Cash Flows

We consider investments purchased with a maturity of three months or less to be cash equivalents. Cash contractually designated for debt service is classified as restricted cash.


(in Millions)		2002			2001			2000

Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
	Accounts receivable, net	$	(157	)	$	17		$	(118	)
	Accrued unbilled receivables		(54	)		(19	)		(22	)
	Accrued gas cost recovery revenue		(5	)		(14	)		—
	Inventories		(71	)		(76	)		8
	Accounts payables		66			(178	)		134
	Income taxes payable		(8	)		(105	)		34
	General taxes		(36	)		22			5
	Risk management and trading activities		69			(80	)		8
	Other		(13	)		(91	)		(127	)

		$	(209	)	$	(524	)	$	(78	)

Other cash and non-cash investing and financing activities for the years ended December 31 were as follows:


(in Millions)		2002		2001		2000

Supplementary Cash Flow Information
	Interest paid (excluding interest capitalized)	$	551	$	409	$	334
	Income taxes paid		167		45		104
Noncash Investing and Financing Activities
	Notes received from sale of property		217		—		—
	Issuance of equity-linked securities		21		—		—
	Issuance of common stock for acquisition of MCN Energy		—		1,060		—

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


Note		Title

2		New Accounting Pronouncements
6		Regulatory Matters
9		Income Taxes
15		Financial and Other Derivative Instruments
17		Retirement Benefits and Trusteed Assets

NOTE 2 – NEW ACCOUNTING PRONOUNCEMENTS

Derivatives

Effective January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 establishes accounting and reporting standards for derivative instruments and for hedging activities. SFAS No. 133 requires that companies recognize all derivatives as either assets or liabilities measured at fair value on the statement of financial position. SFAS No. 133 provides an exception for certain contracts that qualify as “normal purchases and sales.” To qualify for this exception, certain criteria must be met, including a high probability the contract will result in physical delivery. See Note 15 – Financial and Other Derivative Instruments for additional information.

Business Combinations

Effective July 1, 2001 we adopted SFAS No. 141, “Business Combinations.” SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001. The adoption of SFAS No. 141 did not have an impact on the consolidated financial statements.

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 be separately disclosed from other intangible assets in the balance sheet. Additionally under this statement, goodwill is no longer amortized, but must be reviewed at least annually for impairment. The provisions of this accounting standard also require the completion of a transitional impairment test within six months of adoption, with any impairment treated as a cumulative effect of a change in accounting principle. We completed the transitional goodwill impairment test as of January 1, 2002 and the annual goodwill impairment test as of October 1, 2002 and determined that no impairment existed.

In accordance with SFAS No. 142, we discontinued the amortization of goodwill effective January 1, 2002. A reconciliation of previously reported net income and earnings per share to the amounts adjusted for the exclusion of goodwill amortization follows:


	Years Ended December 31,

(in Millions, except per share amounts)	2001		2000

Net Income
As reported	$	332	$	468
Add: Goodwill amortization		31		2

As adjusted	$	363	$	470

Basic Earnings Per Share
As reported	$	2.17	$	3.27
Add: Goodwill amortization		.20		.01

As adjusted	$	2.37	$	3.28

Diluted Earnings Per Share
As reported	$	2.16	$	3.27
Add: Goodwill amortization		.20		.01

As adjusted	$	2.36	$	3.28

In connection with the adoption of SFAS No. 142, we also reassessed the useful lives and the classification of identifiable intangible assets and determined that they continue to be appropriate. Our intangible assets consist primarily of software and are subject to amortization. Intangible assets amortization expense was $46 million in 2002 and $48 million in 2001. There were no material acquisitions of intangible assets during 2002. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2002 were $519 million and $313 million, respectively. Amortization expense of intangible assets is estimated to be $46 million annually for 2003 through 2007.

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. It applies to legal obligations associated with the retirement of long-lived assets resulting from the acquisition, construction, development and (or) the normal operation of a long-lived asset. When a new liability is recorded, an entity will capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

We have 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 regulated 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 will be deferring such differences under SFAS No. 71.

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. We also recorded a cumulative effect amount related to regulated operations as a regulatory asset of $221 million, and a cumulative effect charge against earnings of $11 million for 2003.

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


	(in Millions)
	Net		Diluted
Year	Income		Earnings per Share

2002	$	4.8	$	.03
2001	$	4.2	$	.03
2000	$	3.7	$	.03

The pro forma effect of the asset retirement obligation had SFAS No. 143 been adopted for all periods presented would increase reported liabilities as follows:


(in Millions)
December 31, 2002	$	815
December 31, 2001	$	807
December 31, 2000	$	781

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 January 1, 2003 we estimate that we had approximately $700 million of previously accrued asset removal costs related to our regulated operations, for other than legal obligations, included in accumulated depreciation.

Long-Lived Assets

SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.” This statement establishes a single accounting model for long-lived assets to be disposed of by sale, whether previously held and used, or newly acquired. We adopted this statement on January 1, 2002, with no impact on the consolidated financial statements.

Reporting Gains and Losses from Extinguishment of Debt and Accounting for Leases

SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” eliminates SFAS No. 4 “Reporting Gains and Losses from Extinguishment of Debt” and allows for only those gains or loses on the extinguishment of debt that meet the criteria of extraordinary items to be treated as such in the financial statements. SFAS No. 145 also amends SFAS No. 13 “Accounting for Leases” to require sale-leaseback accounting for certain lease transactions. We adopted the provisions of this statement in 2002 with no impact on the consolidated financial statements.

Exit and Disposal Activities

SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” requires that the liability for costs associated with exit or disposal activities be recognized when incurred, rather than at the date of a commitment to an exit or disposal plan. Application of SFAS No. 146 is required prospectively for exit or disposal activities entered into on or after January 1, 2003.

Stock-Based Compensation

SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure – an amendment to FASB No. 123,” provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this statement requires prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results.

Energy Trading Contracts

EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” permitted either gross or net presentation of mark to market gains and losses on energy trading contracts (including those to be physically settled) in the consolidated statement of operations. Based on discussions held at the June 2002 meeting of the EITF and statements made by the SEC staff, we concluded that net presentation is preferable. In the past we presented such amounts on a gross basis. As of December 31, 2002, we have presented such amounts on a net basis, and all presented prior periods have been reclassified on a consistent basis.

The table below details the impact of the change in reporting gains and losses on energy trading contracts on our consolidated operating revenues and fuel, purchased power and gas expenses. This reclassification had no impact on margins and net income.


(in Millions)	2002			2001			2000

Revenues:
Operating Revenues – Gross	$	9,882		$	7,845		$	5,597
Less: Reclassification		(3,153	)		(2,058	)		(959	)

Operating Revenues – Net	$	6,729		$	5,787		$	4,638

Expenses:
Fuel, Purchased Power and Gas – Gross	$	5,252		$	3,977		$	2,264
Less: Reclassification		(3,153	)		(2,058	)		(959	)

Fuel, Purchased Power and Gas – Net	$	2,099		$	1,919		$	1,305

Under 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. As discussed above in the note, 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 and sets forth conditions in which a derivative instrument may be designated as a hedge. 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 would be accounted for under settlement accounting, effective October 25, 2002 for new contracts and effective January 1, 2003 for existing contracts.

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

Effective January 1, 2003, DTE Energy no longer applies EITF Issue No. 98-10 to energy contracts and ARB 43 to gas inventory. As a result of discontinuing the application of these accounting principles, we expect to record a cumulative effect of accounting change that will reduce net income for the first quarter of 2003 by approximately $18 million.

Guarantor’s Accounting and Disclosure

FASB Interpretation No. 45 requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. It also requires disclosure in interim and annual financial statements of its obligations under certain guarantees it has issued. The initial recognition and measurement provisions of Interpretation No. 45 are to be applied prospectively to guarantees issued or modified after December 31, 2002. The disclosure requirements are effective for financial statements for periods ending after December 15, 2002.

In certain circumstances we enter contractual guarantees. We may guarantee another entity’s obligation in the event they fail 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 $100 million at December 31, 2002.

Parent Company Guarantee of Subsidiary Obligations

We have issued guarantees for the benefit of various non-regulated 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 $200 million at December 31, 2002. This estimated amount fluctuates based upon the provisions and maturities of the underlying agreements.

Sale of Tax Credit Properties

We have provided certain guarantees and indemnities (guarantees) in conjunction with the sales of interests in two of our synfuel facilities. The guarantees cover general commercial, environmental and tax-related exposure and will survive until 90 days after expiration of all applicable statue of limitations, or indefinitely, depending on the nature of the guaranty. We are unable to estimate our maximum liability under the guarantees as our exposure is contingent upon the occurrence of certain events, including the amount of tax credits generated.

Consolidation of Variable Interest Entities

FASB Interpretation No. 46 requires variable interest entities, previously referred to as special-purpose entities or off-balance sheet structures, to be consolidated by a company if that company is subject to a majority of the risk of loss from the entity’s activities or is entitled to receive a majority of the entity’s returns or both. The consolidation provisions of Interpretation No. 46 apply immediately to variable interest entities created after January 31, 2003 and to existing entities in the first fiscal year or interim period beginning after June 15, 2003. Certain disclosure provisions apply in financial statements issued after January 31, 2003.

We believe that it is reasonably possible that we will consolidate the following entities upon the adoption of FASB Interpretation No. 46 in the third quarter of 2003.

In 1997, Enterprises’ 50%-owned partnership, Washington 10 Storage Partnership (Washington 10), entered into a leveraged lease transaction to finance the conversion of a depleted natural gas reservoir into a 42 Bcf storage facility. The storage facility began operations in mid-1999 and cost $160 million to develop. Enterprises has entered into a contract with Washington 10 to market 100% of the capacity of the storage field through 2029. Under the terms of the marketing contract, Enterprises is obligated to generate sufficient revenues to cover Washington 10’s lease payments and certain operating costs, which average approximately $15 million annually.

In 1999, a trust was established to acquire certain railcars and other coal transportation-related equipment for lease to Detroit Edison. The trust issued $101 million of secured notes and trust certificates, due in 2009, to finance the railcars and other equipment. Detroit Edison is unconditionally obligated to make rental payments in amounts that are sufficient to pay all payments of principal and interest on the notes and the yield on the certificates. Title to the railcars and other equipment will not transfer to Detroit Edison at the end of the lease term and there are no options to renew the lease at its expiration. The lease agreement includes an option on the part of Detroit Edison to purchase the equipment at the end of the lease term. If the purchase option is not exercised, Detroit Edison must make a termination payment equal to the unamortized note balance and will be responsible for arranging an orderly disposition of the railcars and equipment.

NOTE 3 – CHANGE IN ACCOUNTING FOR REGULATION

In 1998, based on MPSC Orders, the Power Generation business of Detroit Edison started transitioning to market-based rates with the start of a customer choice program. In compliance with EITF Issue No. 97-4, “Deregulation of the Pricing of Electricity”, we ceased application of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”, for the generation business in 1998. Since that time, there have been significant legislative and regulatory changes in Michigan that have resulted in our generation business being fully regulated with cost-based ratemaking.

On June 5, 2000, the Customer Choice and Electric Reliability Act (PA 141) was enacted into law providing the regulatory framework to maintain cost-based rates for retail customers and ensuring the recovery of all amounts of generation-related stranded costs from choice customers. Subsequent MPSC Orders required a cost-based methodology to set a transition charge applicable to choice customers for recovery of our stranded costs. Since rates for retail customers and transition charges for choice customers are set by the regulator, recover Detroit Edison’s generation costs and are billed and recovered from retail and choice customers, the criteria of SFAS No. 71 are satisfied. In addition, we have both the legislative and regulatory authority to defer regulatory costs and to begin recovery of such costs starting in 2004 after the PA 141 mandated rate freeze expires. As a result of discussions with the SEC staff, the SEC has no objection to Detroit Edison resuming application of SFAS No. 71 for its generation business. Detroit Edison applied SFAS No. 71 starting in the fourth quarter of 2002 and recorded $15 million of additional regulatory assets for the equity component of Allowance for Funds Used During Construction and costs related to reacquired debt that was refinanced with lower cost debt. Included in the $15 million regulatory asset is $11 million of recoverable regulatory assets not recognized prior to the 2002 fourth quarter application of SFAS No. 71. Prior period financial statements have not been restated due to the immaterial effect of retroactively applying SFAS No. 71 to Detroit Edison’s generation business.

NOTE 4 – ACQUISITIONS AND DISPOSITIONS

Acquisition of MCN Energy

On May 31, 2001, DTE Energy completed the acquisition of MCN Energy by acquiring all of its outstanding shares of common stock for a combination of cash and shares of our common stock. See Note 10 – Common Stock and Earnings per Share herein for additional information. We purchased the outstanding common stock of MCN Energy for $2.3 billion and assumed existing MCN Energy debt and preferred securities of $1.5 billion.

We accounted for the acquisition using the purchase method and accordingly allocated the purchase price to the fair value of the assets acquired and liabilities assumed. The excess of the purchase price over the fair value of net assets acquired totaled $2.1 billion and was classified as goodwill. We began amortizing goodwill on June 1, 2001, on a straight-line basis using a 40-year life. In accordance with the adoption of SFAS No. 142 on January 1, 2002, the amortization of goodwill ceased, and goodwill is tested for impairment on an annual basis.

The following unaudited pro forma summary presents information about the company as if the acquisition became effective at the beginning of the respective periods. The pro forma amounts include the impact of certain adjustments, such as acquiring the operations of MCN Energy and issuing $1.35 billion of debt and 29 million shares of common stock to finance the acquisition. The pro forma amounts do not reflect the benefits from synergies we are receiving as a result of combining operations, do not reflect the actual results that would have occurred had the companies been combined for the periods presented, and are not necessarily indicative of future results of operations of the combined companies.


		Pro Forma

		Year Ended December 31

(in Millions, except per share amounts)		2001		2000

Operating revenues		$	9,393	$	8,388
Income before accounting change		$	534	$	426
Net income		$	537	$	426
Basic earnings per share:
	Before accounting change	$	3.23	$	2.48
	Total	$	3.25	$	2.48
Diluted earnings per share:
	Before accounting change	$	3.21	$	2.48
	Total	$	3.23	$	2.48

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition:


(in Millions)		At May 31, 2001

Current assets, net of cash acquired			$	853
Investments				52
Property, plant and equipment, net				1,628
Assets held for sale				245
Goodwill				2,077
Other assets				1,216

	Total assets acquired			6,071

Current liabilities				(1,472	)
Intangible liabilities				(390	)
Other liabilities				(721	)
Preferred securities				(273	)
Long-term debt				(940	)

	Total liabilities assumed			(3,796	)

	Net assets acquired		$	2,275

Disposition of Detroit Edison’s Steam Heating Business

In January 2003, we sold the steam heating business of Detroit Edison to Thermal Ventures II, LLP. This disposition is consistent with DTE Energy’s strategy of divestiture of non-strategic assets. Due to the continuing involvement of Detroit Edison in the steam heating business, including the commitment to purchase $176 million in steam for resale through 2008, fund certain capital improvements and guarantee the buyer’s credit facility, we will record a net of tax loss of approximately $13 million in the first quarter of 2003. As a result of our 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, net income of $3 million in 2001 and a net loss of $18 million in 2000. See Note 16 – Commitments and Contingencies.

Disposition of International Transmission Company – Discontinued Operation

In December 2002, we entered into a definitive agreement with affiliates of Kohlberg Kravis Roberts & Co. and Trimaran Capital Partners, LLC providing for the sale of ITC for approximately $610 million in cash. The sale closed on February 28, 2003 and generated a preliminary net of tax gain of $69 million

that was recorded in the first quarter of 2003. The sale price can be increased or decreased based upon a review of ITC’s closing date balance sheet. This review and adjustment is expected to be completed during the third quarter of 2003.

As provided in FERC regulations, Detroit Edison will continue to have fair and open access to Michigan’s electric transmission network following the sale. The ITC electric transmission system will continue to be operated by the Midwest Independent System Operator, a regional transmission operator. Under the terms of the sale agreement, ITC will seek FERC approval to cap transmission rates charged to Detroit Edison’s customers at current levels until December 31, 2004. Thereafter, rates would be subject to adjustment by the FERC.

Prior to May 31, 2001, Detroit Edison owned and operated the transmission assets of ITC, which were vertically integrated with its other operations. Accordingly, revenues, expenses and cash flows associated with these transmission assets were bundled with the Energy Distribution — Regulated Power Distribution & Transmission segment and were not separately identifiable. Effective June 1, 2001, the transmission assets of ITC were transferred to DTE Corporate and its revenues, expenses and cash flows were separately monitored to measure its financial and operating performance. Accordingly, the presentation of discontinued operations in the consolidated statement of operations reflects the results of ITC after May 31, 2001.

SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” provides that the results of operations of a component of an entity that has been disposed of should be reported as a discontinued operation when the operations and cash flows of the component have been eliminated from the ongoing operations of the entity and the entity will not have any significant continuing involvement in the operations of the component after the disposal transaction. As a result, we have reported the operations of ITC as a discontinued operation for the years ended December 31, as shown in the following table:


(In Millions)	2002		2001 (3)		2000

Revenues (1)	$	138	$	64	$	—
Expenses (2)		64		33		—

Operating income		74		31		—
Operating expenses		3		2
Income taxes		25		9		—

Income from discontinued operations	$	46	$	20	$	—

(1)		Includes intercompany revenues of $118 million for 2002 and $60 million for 2001.

(2)		Excludes general corporate overhead costs that were previously allocated to ITC. For 2002 the imputed interest was $4 million and in 2001 it was $1 million.

(3)		Reflects seven months of activity from June 1, 2001 through December 31, 2001.

ITC had net property of $388 million and $395 million at December 31, 2002 and 2001, respectively. In conjunction with the sale of ITC, approximately $44 million of goodwill allocated to this segment was written off. After consideration of this goodwill write-off, the preliminary net of tax gain was $69 million.

NOTE 5 – MERGER AND RESTRUCTURING CHARGES

On May 31, 2001, we completed the acquisition of MCN Energy. The following costs were incurred:


(In Millions)	2001		2000

Merger related	$	27	$	25
Restructuring		241		—

Total pre-tax	$	268	$	25

Total net of tax	$	175	$	16

Merger related charges represent systems integration, relocation, legal, accounting and consulting costs. Restructuring charges were primarily associated with a work force reduction plan. The plan included early retirement incentives and voluntary separation agreements for 1,186 employees, primarily in overlapping corporate support areas. Approximately $53 million of the merger and restructuring charges

were paid as of December 31, 2001 and remaining benefit payments have been or will be paid from retirement plans.

NOTE 6 - REGULATORY MATTERS

Regulation

Detroit Edison and MichCon are subject to the regulatory jurisdiction of the MPSC, which 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 is also regulated by the FERC with respect to financing authorization and wholesale electric activities.

The operations of Detroit Edison, MichCon, and ITC meet the criteria of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” This accounting standard recognizes the cost-based ratemaking process, which 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 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. Management believes that currently available facts support the continued application of SFAS No. 71 to these businesses. 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 businesses and require the write-off of the portion of any regulatory asset or liability that was no longer probable of recovery through regulated rates.

Regulatory Assets and Liabilities

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


(in Millions)			2002		2001

Assets
	Securitized regulatory assets		$	1,613	$	1,692
	Recoverable income taxes related to securitized regulatory assets			884		942
	Other recoverable income taxes			118		123
	Stranded costs and other costs recoverable under PA 141			21		—
	Unamortized loss on reacquired debt			36		37
	Electric Choice implementation costs			76		53
	Deferred environmental costs			29		29
	Other			33		5

		Total Assets	$	2,810	$	2,881

Liabilities
	Refundable income taxes		$	142	$	144
	Excess securitized savings			37		43

		Total Liabilities	$	179	$	187

Electric Industry Restructuring

Electric Rates, Customer Choice and Stranded Costs - In June 2000, PA 141 became effective. PA 141 provided Detroit Edison with the right to recover stranded costs, codified and established January 1, 2002 as the date for full implementation of the MPSC’s existing Electric Choice program, and required the

MPSC to reduce residential electric rates by 5%. At that time, Public Act 142 (PA 142) also became effective. PA 142 provided for the recovery through securitization of “qualified costs” which consist of an electric utility’s regulatory assets, plus various costs, associated with, or resulting from, the establishment of a competitive electric market and the issuance of securitization bonds.

Acting pursuant to PA 141, in an order issued in June 2000, the MPSC reduced Detroit Edison’s residential electric rates by 5% and imposed a rate freeze for all classes of customers through 2003. In April 2001, commercial and industrial rates were lowered by 5% as a result of savings derived from the issuance of securitization bonds in March 2001, as subsequently discussed.

The legislation also contains provisions freezing rates through 2003 and preventing rate increases for residential customers through 2005 and for small business customers through 2004. Certain costs may be deferred and recovered once rates can be increased. This rate cap may be lifted when certain market test provisions are met, specifically, when an electric utility has no more than 30% of generation capacity in its relevant market, with consideration for capacity needed to meet a utility’s responsibility to serve its retail customers. Statewide, multi-utility transmission system improvements also are required. Detroit Edison expects that these market and transmission improvement conditions will be met, and the rate cap will not continue after the dates specified in the legislation.

As required by PA 141, the MPSC conducted a proceeding to develop a methodology for calculating the 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 filing with the MPSC comparing 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, in its December 2001 order, also determined that Detroit Edison had no net stranded costs in 2000 and consequently established a zero net stranded cost transition charge for billing purposes in 2002. 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. The MPSC also determined that Detroit Edison should provide a full and offsetting credit for the securitization and tax charges applied to electric Customer Choice bills in 2002. In addition, the MPSC ordered an additional credit on bills equal to the 5% rate reduction realized by full service customers. Both credits were to be funded from savings derived from securitization. The December 2001 order, coupled with lower wholesale power prices in 2002, has encouraged additional customer participation in the electric Customer Choice program and has resulted in the loss of margins attributable to generation services. In May 2002, the MPSC denied Detroit Edison’s request for rehearing and clarification. In June 2002, Detroit Edison filed an appeal of the MPSC order at the Michigan Court of Appeals, challenging the legality of specific aspects of the MPSC order. The Court of Appeals has not yet issued a decision on this appeal.

In May 2002, Detroit Edison submitted its 2002 net stranded cost filing with the MPSC. The filing provides refinements to the MPSC Staff’s calculation of net stranded costs that was adopted in the December 2001 order, seeks more timely recovery of net stranded costs, and addresses issues raised by the continuation of securitization offsets and rate reduction equalization credits. Detroit Edison’s filing supports the following conclusions: (i) Detroit Edison had no net stranded costs in 2000 and $13 million of recoverable net stranded costs attributable to electric Customer Choice in 2001; (ii) Detroit Edison requested recovery of 2001 net stranded costs through the use of excess securitization savings; (iii) Detroit Edison expects to incur additional net stranded costs in 2002 and 2003 as a result of increased electric Customer Choice participation; and (iv) Detroit Edison recommended that a pro-forma or forward looking transition charge be approved for billing during the remainder of 2002 and for 2003 to eliminate the time lag between the occurrence and recovery of net stranded costs inherent in the methodology approved in the December 2001 order. In November 2002, the MPSC Staff and other interveners

submitted their 2002 net stranded cost filings. In the fourth quarter of 2002, Detroit Edison recorded a regulatory asset of $21 million representing 2002 net stranded costs and the deferral of other costs recoverable under PA 141. The effect of recording the regulatory asset increased 2002 earnings by $13 million, net of taxes. The MPSC has not yet acted upon this Detroit Edison filing.

In several orders issued in June 2000, the MPSC determined that adjusting rates for changes in fuel and purchased power expenses through continuance of the Power Supply Cost Recovery (PSCR) clause would be inconsistent with the rate freeze required by PA 141. Detroit Edison was not permitted to collect the 1998 PSCR under-recovery of $9 million, plus accrued interest of $3 million. Also, Detroit Edison was not required to refund approximately $55 million of liabilities for over-recoveries of PSCR expenses for 1999 and 2000, and disallowances under the performance standard mechanism for our Fermi 2 nuclear power plant. In January and March 2002, the Michigan Court of Appeals rejected appeals and motions for rehearing filed by parties opposing the MPSC’s actions in this proceeding. In March 2002, the Michigan Attorney General applied for leave to appeal at the Michigan Supreme Court. The court has issued an order indicating that it will not hear the case.

It is unclear at this time whether the PSCR clause will be suspended beyond 2003.

Securitization – In an order issued in November 2000 and clarified in January 2001, the MPSC approved the issuance of securitization bonds to recover qualified costs that include the unamortized investment in Fermi 2, costs of certain other regulatory assets, Electric Choice implementation costs, costs of issuing securitization bonds, and the costs of retiring securities with the proceeds of securitization. The order permits the collection of these qualifying costs from Detroit Edison’s customers.

Detroit Edison formed The Detroit Edison Securitization Funding LLC (Securitization LLC), a wholly owned subsidiary, for the purpose of securitizing its qualified costs. 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 Bonds mature over a 14-year period and have an annual average interest rate of 6.3% over the life of the bonds. Detroit Edison used the proceeds to retire debt and equity in approximately equal amounts. The company likewise retired approximately 50% debt and 50% equity with the proceeds received as the sole shareholder of Detroit Edison. Detroit Edison implemented a non-bypassable surcharge on its customer bills, effective March 26, 2001, for the purpose of collecting amounts sufficient to provide for the payment of interest and principal and the payment of income tax on the additional revenue from the surcharge. As a result of securitization, Detroit Edison established a regulatory asset for securitized costs including costs that had previously been recorded in other regulatory asset accounts.

The Securitization LLC is independent of Detroit Edison, as is its ownership of the qualified costs. Due to principles of consolidation, qualified costs sold by Detroit Edison to the Securitization LLC and the $1.75 billion of 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. Funds collected by Detroit Edison, acting in the capacity of a servicer for the Securitization LLC, are remitted to the trustee for the Securitization Bonds. Neither the qualified costs which were sold nor funds 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.

Gas Industry Restructuring

Through December 2001, MichCon was operating under an MPSC-approved Regulatory Reform Plan, which included a comprehensive experimental three-year gas Customer Choice program, a Gas Sales Program and an income sharing mechanism. MichCon returned to a GCR mechanism in January 2002 when the Gas Sales Program expired. Under the GCR mechanism, the gas commodity component of

MichCon’s gas sales rates is designed to recover the actual costs of gas purchases. In December 2001, the MPSC issued an order that permitted MichCon to implement GCR factors up to $3.62 per 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 will be subject to the 2002 GCR reconciliation process. As of December 31, 2002, MichCon has accrued a $22 million regulatory asset representing the under-recovery of actual gas costs incurred. In July 2002, in response to a petition for rehearing filed by the Michigan Attorney General, the MPSC directed the parties to address MichCon’s implementation of the December 2001 order and the impact of that implementation on rates charged to MichCon’s customers. Also, in July 2002, an MPSC Administrative Law Judge (ALJ) issued a Proposal for Decision on MichCon’s 2002 GCR plan case. In that decision the ALJ recommended adoption of the MPSC Staff’s proposed $26.5 million reduction in gas cost due to MichCon’s decision to utilize storage gas during 2001 that resulted in a gas inventory decrement for the 2001 calendar year. See Note 21 for information concerning a March 2003 MPSC order in this matter.

In December 2001, the MPSC also approved MichCon’s application for a voluntary, expanded permanent gas Customer Choice program, which replaced the experimental program that expired in March 2002. Effective April 2002, up to 40% of MichCon’s customers could elect to purchase gas from suppliers other than MichCon. Effective April 2003, up to 60% of customers would be eligible and by April 2004, all of MichCon’s 1.2 million customers can participate in the program. The MPSC also approved the use of deferred accounting for the recovery of implementation costs of the gas Customer Choice program. As of December 2002, approximately 190,000 customers are participating in the gas Customer Choice program.

As previously mentioned, MichCon was operating under a Regulatory Reform Plan through December 2001, which included an income sharing mechanism. The income sharing mechanism allowed customers to share in profits when actual returns on equity from utility operations exceed predetermined thresholds. Based on the MPSC approved formula, MichCon believes that no income sharing is required in 2001. In July 2002, the MPSC ordered a hearing be held to determine the appropriate treatment of $766,000 of pipeline refunds received by MichCon during 2001. MichCon does not agree with the MPSC Staff’s position that this amount should be refunded to customers.

Other

In accordance with a November 1997 MPSC order, Detroit Edison reduced rates by $53 million annually to reflect the scheduled reduction in the revenue requirement for Fermi 2. The $53 million reduction was effective in January 1999. In addition, the November 1997 MPSC order authorized the deferral of $30 million of storm damage costs and amortization and recovery of the costs over a 24-month period commencing January 1998. After various legal appeals, the Michigan Court of Appeals remanded back to the MPSC for hearing the November 1997 order. In December 2000, the MPSC issued an order reopening the case for hearing. The parties in the case have agreed to a stipulation of fact and waiver of hearing. In June 2002, the MPSC issued an order modifying its 1997 order that will require Detroit Edison to refund approximately $1.5 million after January 1, 2004. In July 2002, the Michigan Attorney General filed an appeal with the Michigan Court of Appeals regarding the June 2002 MPSC Order.

Management is 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 7 – NUCLEAR OPERATIONS

General

Fermi 2, our nuclear generating plant, began commercial operation in 1988. The Nuclear Regulatory Commission (NRC) has jurisdiction over the licensing and operation of Fermi 2. 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 6 - Regulatory Matters. Detroit Edison also owns Fermi 1, a nuclear plant that was shut down in 1972 and is currently being decommissioned.

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. Under the NEIL policies, Detroit Edison could be liable for maximum assessments of up to approximately $27 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.

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 three years of coverage.

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 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.

Public Liability Insurance

As required by federal law, Detroit Edison increased the amount of public liability insurance for a nuclear incident from $200 million to $300 million, effective January 1, 2003. For liabilities arising out of terrorist acts, the policy is now subject to one industry aggregate limit of $300 million. Further, under the Price-Anderson Amendments Act of 1988 (Act), deferred premium charges up to $84 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, however the provisions of the Act remain in effect for existing reactors. Legislation to extend the Act is currently under debate in Congress. President Bush has expressed his support to extend the Act. We cannot predict whether the legislation will pass the Congress.

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. During 2002, Detroit Edison collected $42 million and in 2001 and 2000, Detroit Edison collected a total of $38 million each year from customers for decommissioning and low-level radioactive waste disposal. Such amounts were recorded as components of depreciation, depletion and amortization expense, and in other liabilities. Net unrealized investment losses of $39 million and $23 million in 2002 and 2001, respectively, were recorded as adjustments to the nuclear decommissioning trust funds and other liabilities. At December 31, 2002, investments in the external trust consisted of approximately 42.7% in publicly traded equity securities, 43.7% in fixed debt instruments and 13.6% in cash equivalents. Investments in debt and equity securities held within the external trust are classified as “available for sale.”

At December 31, 2002 and 2001, Detroit Edison had reserves of $377 million and $372 million, respectively, for the future decommissioning of Fermi 2, and $22 million and $26 million, respectively, for the decommissioning of Fermi 1. Detroit Edison also had a reserve of $17 million for low-level radioactive waste disposal costs at December 31, 2002 and $14 million as of December 31, 2001. These reserves are included in other liabilities, with an equivalent amount invested in an external trust. It is estimated that the cost of decommissioning Fermi 2, when its license expires in 2025, will be $947 million in 2002 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 is expected to be complete by 2008.

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 one mill per net kilowatthour 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 has entered into litigation against the DOE for damages caused by the DOE not accepting spent nuclear fuel on a timely basis.

NOTE 8 - JOINTLY OWNED UTILITY PLANT

Detroit Edison’s share of jointly owned utility plants at December 31, 2002 was as follows:


			Ludington
			Hydroelectric
	Belle River		Pumped Storage

In-service date		1984-1985		1973
Ownership interest		*		49	%
Investment (in Millions)	$	1,021	$	196
Accumulated depreciation (in Millions)	$	478	$	108

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, 49% in certain transmission lines, 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 (1,026 MW) and is responsible for the same percentage of the plant’s operation, maintenance and capital improvements costs.

Ludington Hydroelectric Pumped Storage

Operation, maintenance and other expenses of the Ludington Hydroelectric Pumped Storage Plant (1,872 MW) are shared by Detroit Edison and Consumers Energy Company in proportion to their respective plant ownership interests.

NOTE 9 - INCOME TAXES

We file a consolidated federal income tax return.

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


(Dollars in Millions)	2002			2001			2000

Effective federal income tax rate		(16.7	)%		(62.6	)%		1.9	%

Income tax expense at 35% statutory rate	$	175		$	68		$	167
Section 29 tax credits		(250	)		(165	)		(130	)
Removal costs		—			1			(24	)
Investment tax credits		(9	)		(8	)		(10	)
Depreciation		2			(12	)		11
Goodwill amortization		—			10			—
Research expenditures tax credits		—			(7	)		—
Employee Stock Ownership Plan dividends		(4	)		(4	)		—
Other-net		2			(2	)		(5	)

Income taxes associated with continuing operations		(84	)		(119	)		9

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


(in Millions)		2002			2001			2000

Continuing Operations
	Current federal and other income tax expense	$	135		$	1		$	138
	Deferred federal income tax benefit		(219	)		(120	)		(129	)

			(84	)		(119	)		9
Discontinued operations			25			9			—

	Total	$	(59	)	$	(110	)	$	9

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. Section 29 tax credits earned but not utilized of $381 million are carried forward indefinitely as alternative minimum tax credits. We have received private letter rulings from the Internal Revenue Service (IRS) for all our tax credit properties, except for two synthetic fuel facilities, 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.

At December 31, 2002, we had a net operating loss carryforward of $326 million as a result of the MCN Energy acquisition expiring in 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 income tax assets (liabilities) were comprised of the following at December 31:


(in Millions)	2002			2001

Property	$	(1,179	)	$	(1,149	)
Securitized regulatory assets		(871	)		(909	)
Alternative minimum tax credit carryforward		381			274
Merger basis differences		186			213
Pension and benefits		216			(71	)
Net operating loss		114			148
Other		282			63

	$	(871	)	$	(1,431	)

Deferred income tax liabilities	$	(2,564	)	$	(2,479	)
Deferred income tax assets		1,693			1,048

	$	(871	)	$	(1,431	)

During 2002, the IRS completed and closed its audits of our federal income tax returns through 1995. The IRS is currently conducting audits of our federal income tax returns for the years 1996 and 1997. Audits of the MCN Energy federal income tax returns for 1995 through 1998 are being finalized. We believe that our accrued tax liabilities are adequate for all years.

NOTE 10 – COMMON STOCK AND EARNINGS PER SHARE

Common Stock

In June 2002, we issued 6.325 million shares of common stock at $43.25 per share, grossing $274 million. Net proceeds from the offering were approximately $265 million.

On May 31, 2001, we issued approximately 29 million shares of common stock, valued at $1.06 billion, as part of the consideration to purchase all of the outstanding common stock of MCN Energy. See Note 4 – Acquisitions and Dispositions. The newly issued shares were valued at the average market price of our common stock for a five-day period, including February 28, 2001, the announcement date of the revised merger agreement.

In 2001, DTE Energy repurchased approximately 10.5 million shares of common stock with a total cost of approximately $438 million.

Under the DTE Energy Company Long-Term Incentive Plan, we grant non-vested stock awards to management. At the time of grant, DTE Energy records 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 Plan

We have a Shareholders’ Rights Plan designed to maximize shareholders’ value should DTE Energy be acquired. The rights are attached to and trade with shares of DTE Energy’s common stock until they are exercisable upon certain triggering events. The rights expire in 2007.

Earnings per Share

We report both basic and diluted earnings per share. Basic earnings per share is computed by dividing net income 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 issuance of performance share awards. A reconciliation of both calculations is presented in the following table:


(in Thousands, except per share amounts)	2002		2001		2000

Basic Earnings per Share
Income from continuing operations	$	585,702	$	308,745	$	468,550
Average number of common shares outstanding		164,017		153,120		143,116

Earnings per share of common stock based on average number of shares outstanding	$	3.57	$	2.02	$	3.27

Diluted Earnings per Share
Income from continuing operations	$	585,702	$	308,745	$	468,550
Average number of common shares outstanding		164,017		153,120		143,116
Incremental shares from stock-based awards		750		639		149

Average number of dilutive shares outstanding		164,767		153,759		143,265

Earnings per share of common stock assuming issuance of incremental shares	$	3.55	$	2.01	$	3.27

Options to purchase approximately one million shares of common stock 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 securities anti-dilutive.

NOTE 11 - PREFERRED SECURITIES

DTE Energy and Enterprises-Obligated Mandatorily Redeemable Preferred Securities of Subsidiaries

Various trusts and a partnership (subsidiaries) were formed for the sole purpose of issuing preferred securities and lending the gross proceeds to their respective parent. The sole assets of the subsidiaries are debentures of the parent with terms similar to those of the related preferred securities. Summarized information for DTE Energy and Enterprises-obligated mandatorily redeemable preferred securities of wholly-owned subsidiaries of DTE Energy and Enterprises, holding solely debentures of the parent is as follows:


		December 31				Liquidation		Maturity of		Earliest
						Value		Underlying		Redemption
(in Millions, except per share amounts)		2002		2001		Per Share		Debentures		Date

MCN Financing I 8-5/8% Trust Originated Preferred Securities		$	—	$	77	$	25		2036		2001
	(3,200,000 preferred securities) Dividends payable quarterly
MCN Financing II 8-5/8% Trust Preferred Securities		$	97	$	98	$	25		2038		2003
	(4,000,000 preferred securities) Dividends payable quarterly
MCN Financing III 7.25% Preferred Securities		$	—	$	2	$	50		2002		2002
	(30,600 preferred securities) Dividends payable quarterly
MCN Michigan Ltd. Partnership 9-3/8% Redeemable Cumulative Preferred		$	—	$	97	$	25		2024		1999
	Securities (4,000,000 preferred securities) Dividends payable monthly
DTE Energy Trust I 7.8% Trust Preferred Securities		$	174		—	$	25		2032		2007
	(7,200,000 preferred securities) Dividends payable quarterly

		$	271	$	274

Each trust uses payments received on the debenture it holds to make cash distribution on the preferred securities it has issued.

The preferred securities allow us the right to extend interest payment periods on the debentures and, as a consequence, the subsidiaries can defer dividend payments on the preferred securities during any such interest payment period. 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.

In the event of default, holders of the preferred securities will be entitled to exercise and enforce the subsidiaries’ creditor rights against the parent, which may include acceleration of the principal amount due on the debentures. DTE Energy has issued certain guaranties with respect to payments on the preferred securities. These guaranties, when taken together with each parent’s obligations under the debentures, related indenture, subsidiary documents, provide full and unconditional guarantees of the subsidiaries’ obligations under the preferred securities.

Financing costs for these issuances were deferred and are reflected as a reduction in the carrying value of the preferred securities. These costs are being amortized using the straight-line method over the estimated lives of the related securities.

Preferred and Preference Securities – Authorized and Unissued

At December 31, 2002, DTE Energy had 5 million shares of preferred stock without par value authorized, with no shares issued. Of such amount, 1.6 million shares are reserved for issuance in accordance with the Shareholders’ Rights Plan.

At December 31, 2002, Detroit Edison had 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, 2002, Enterprises had 25 million shares of preferred stock without par value authorized, with no shares issued.

At December 31, 2002, 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.

NOTE 12 - LONG-TERM DEBT

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


(in Millions)		2002			2001

DTE Energy Debt, Unsecured
	6.7% due 2004 to 2038	$	1,948		$	1,748
Detroit Edison Taxable Debt, Principally Secured
	6.3% due 2003 to 2034		1,812			1,548
Detroit Edison Tax Exempt Revenue Bonds
	5.8% due 2004 to 2032		1,208			1,144
MichCon Taxable Debt, principally secured
	6.7% due 2003 to 2039		775			797
Quarterly Income Debt Securities
	7.5% due 2026 to 2028		385			385
Non-Recourse Debt
	8.1% due 2003 to 2017		119			196
Other Long-Term Debt			329			503

			6,576			6,321
Less amount due within one year			(920	)		(429	)

		$	5,656		$	5,892

Securitization Bonds		$	1,673		$	1,746
Less amount due within one year			(88	)		(73	)

		$	1,585		$	1,673

Equity-Linked Securities		$	191		$	—

During 2002 and 2001, we issued and repurchased long-term debt consisting of the following:

2002

•		Issued $200 million of DTE Energy senior notes bearing interest at 6.65 % and maturing in 2009

•		Issued $172.5 million of DTE Energy equity-linked debt securities as subsequently discussed

•		Issued $225 million of Detroit Edison senior notes bearing interest at 5.20 % and maturing in 2012

•		Issued $225 million of Detroit Edison senior notes bearing interest at 6.35 % and maturing in 2032

•		Issued $64 million of Detroit Edison tax exempt bonds bearing interest at 5.45% and issued $56 million of Detroit Edison tax exempt bonds bearing interest at 5.25%, both maturing in 2032.

2001

•

Issued $1.35 billion of DTE Energy debt in three series to finance the cash consideration of the MCN Energy acquisition

	•		$250 million of 6.00% senior notes due 2004

	•		$500 million of 6.45% senior notes due 2006

	•		$600 million of 7.05% senior notes due 2011

•		Issued $1.75 billion of Securitization Bonds by the Securitization LLC

•		Issued $200 million of MichCon senior secured notes bearing interest at 6.125% and maturing in 2008

•		Redeemed $1.3 billion of Detroit Edison debt, of which $1.1 billion represented unscheduled redemptions

•		Repurchased $40 million of MichCon mortgage bonds, due 2021

•		Entered into a Detroit Edison financing arrangement for certain equipment with a value of approximately $90 million. The arrangement has an implicit interest rate of 7.6% with a term of approximately nine years.

In the years 2003 - 2007, our long-term debt maturities are $1 billion, $464 million, $512 million, $685 million and $178 million, respectively.

Remarketable Securities

At December 31, 2002, $914 million of notes were subject to periodic remarketings, $575 million of which will take place in 2003. Amounts that will be remarketed in 2003 are included in the current portion of long-term debt. We direct the remarketing agents to remarket these securities at lowest interest rate necessary to produce a par bid. In the event that a remarketing fails, we would be required to purchase these securities.

Quarterly Income Debt Securities (QUIDS)

Each series of QUIDS provides that interest will be paid quarterly. However, Detroit Edison has the right to extend the interest payment period on the QUIDS for up to 20 consecutive interest payment periods. Interest would continue to accrue during the deferral period. If this right is exercised, Detroit Edison may not declare or pay dividends on, or redeem, purchase or acquire, any of its capital stock during the deferral period.

Equity-Linked Securities

In June 2002, we 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 have 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.

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 purchase contracts was charged to equity.

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 substantially all of their respective indebtedness.

NOTE 13 - SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

In October 2002, we entered into a $470 million, 364-day revolving facility and a $230 million, three-year revolving facility. These credit facilities can be used for general corporate purposes, but are primarily intended to provide liquidity for our commercial paper program. Important aspects of these agreements require us to maintain a debt to total capitalization ratio of not more than .65 to 1, and a “earnings before interest, taxes, depreciation and amortization” to interest ratio of no less than 2 to 1. Detroit Edison and MichCon entered into similar revolving credit facilities. Detroit Edison has a $135 million, 364-day facility and a $65 million, three-year facility. MichCon has a $200 million, 364-day facility and a $100 million, three-year facility. A delinquency greater than $25 million by either Detroit Edison or MichCon to any creditor will be considered a default under DTE Energy’s credit agreements. Commercial paper and borrowings outstanding were $414 million at December 31, 2002.

The weighted average interest rates for short-term borrowings were 1.7% and 2.8% at December 31, 2002 and 2001, respectively.

Detroit Edison has a $200 million short-term financing agreement secured by customer accounts receivable and unbilled revenues. There were no outstanding amounts under this financing agreement at December 31, 2002 and 2001.

NOTE 14 – CAPITAL AND OPERATING LEASES

Lessee – We lease various assets under capital and operating leases, including lake vessels, locomotives, coal cars, office buildings, a parking facility, a warehouse, computers, vehicles and other equipment. The lease arrangements expire at various dates through 2022 with renewal options extending beyond that date. Portions of the office buildings and parking facility are subleased to tenants.

Future minimum lease payments under non-cancelable leases at December 31, 2002 were:


	Capital			Operating
(in Millions)	Leases			Leases

2003	$	16		$	40
2004		12			40
2005		12			40
2006		14			37
2007		11			34
2008 and thereafter		62			137

Total minimum lease payments		127		$	328

Less imputed interest		(36	)

Present value of net minimum lease payments		91
Less current portion		(9	)

Non-current portion	$	82

Total minimum lease payments for operating leases have not been reduced by future minimum sublease rentals totaling $17 million under non-cancelable subleases expiring at various dates to 2019.

Rental expenses for operating leases was $40 million in 2002, $19 million in 2001 and $13 million in 2000.

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, 2002 were as follows:


(in Millions)
2003	$	9
2004		9
2005		9
2006		9
2007		9
Thereafter		116

Total minimum future lease receipts		161
Residual value of leased pipeline		40
Less – unearned income		(117	)

Net investment in capital lease		84
Less – current portion		(1	)

	$	83

NOTE 15 – FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

In 1998, FASB issued SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, establishes accounting and reporting standards for derivative instruments and hedging activities. 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 income when the forecasted transaction affects earnings.

•		If a cash flow hedge is discontinued because it is unlikely the forecasted transaction will not occur, net gains or losses are immediately recorded into earnings.

•		Special accounting is 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. The gain or loss on the underlying asset, liability or firm commitment is also recorded into earnings.

SFAS No. 133 requires that as of the date of initial adoption, the difference between the fair value of derivative instruments and the previous carrying amount of those derivatives be reported in net income or other comprehensive income as the cumulative effect of a change in accounting principle.

In 2001 we adopted SFAS No. 133. The financial statement impact of recording the various SFAS No. 133 transactions at January 1, 2001 was as follows:


		Increase
(in Millions)		(Decrease)

Financial Statement Line Item
Assets from risk management and trading activities		$	26
Liabilities from risk management and trading activities		$	85
Deferred income taxes payable		$	(20	)
Cumulative effect of a change in accounting principle:
	Other comprehensive loss	$	42
	Net income	$	3

Our primary market risk exposure is associated with commodity prices and interest rates. 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.

Credit Risk

We 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

During 2000, we entered into a series of interest rate swaps and treasury locks to limit our sensitivity to market interest rate risk associated with the issuance of long-term debt used to acquire MCN Energy. Such instruments were designated as cash flow hedges. In the first quarter of 2001, a loss of approximately $5 million was reclassified from accumulated other comprehensive loss into earnings. We made this decision since it was probable that certain transactions associated with the issuance of long-term debt would not occur within the originally anticipated time frame. This loss was reported as a component of interest expense in the consolidated statement of operations. In 2001, we issued long-term debt and terminated these hedges at a cost of $83 million. The corresponding loss on these instruments is included in other comprehensive loss. During the next 30 years, amounts recorded in other comprehensive loss will be reclassified to interest expense as the related interest affects earnings. In 2003 we estimate reclassifying $10 million of losses into interest expense.

Commodity Price Risk

Regulated Operations

Detroit Edison uses forward energy, capacity, and futures contracts to manage changes in the price of electricity and natural gas. Certain contracts have been designated as cash flow hedges of forecasted purchases of power and natural gas. For the year ended December 31, 2002, Detroit Edison recorded a loss of $0.7 million, net of tax, in other comprehensive loss for these hedges. Amounts recorded in other comprehensive income will be reclassified to fuel, purchased power and gas expense as the forecasted purchases of electricity and natural gas affect earnings. During 2003 we estimate $2.1 million of existing losses will be reclassified to fuel, purchased power and gas expense. Two years is the maximum length of time Detroit Edison is hedging exposure to the variability of future cash flows. Ineffectiveness recognized in hedging relationships was immaterial for the year ended December 31, 2002.

In 2001, the FASB provided additional guidance on SFAS No. 133 for certain contracts in the power generation industry. In particular, issue No. C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity.” Since electricity cannot be readily stored in significant quantities, and the entity engaged in selling electricity is obligated to maintain sufficient capacity to meet the needs of customers, the FASB concluded an option contract for the purchase of electricity meeting certain criteria is eligible for the normal purchases and sales exception. Detroit Edison adopted this new guidance on July 1, 2001, classified certain contracts as normal, and began amortizing the previously recorded liability on option-like contracts over their remaining lives. Later in 2001, the FASB issued additional revisions to issue No. C15 which were effective in April 2002. The revised guidance differentiates traditional capacity contracts used by electric utilities to meet electric load and financial options on electricity. Traditional capacity contracts are eligible for settlement accounting under the normal purchases and sales exception. Financial options on electricity are not eligible for settlement accounting. Financial options on electricity are recorded at fair value on the statement of financial position using mark-to-market accounting. Certain of Detroit Edison’s forward electric contracts are considered “normal purchases and sales” and therefore are excluded from the scope of SFAS No. 133.

MichCon has firm-priced contracts for a substantial portion of its expected gas supply requirements through 2003. These contracts are designated and qualify for the “normal purchases” exception under SFAS No.133. Accordingly, MichCon does not account for such contracts as derivatives.

Non-Regulated Operations

Energy Marketing & 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. This risk minimization strategy is being accounted for by marking to market its commodity forwards and financial derivatives so they substantially offset. This fair value accounting better aligns financial reporting with the way the business is managed and its performance measured. Unrealized gains and losses resulting from marking to market commodity-related physical and financial derivatives utilized in trading operations are recorded as adjustments to revenues.

Although Energy Marketing & Trading attempts to maintain a balanced or flat book from an economic standpoint, it will experience earnings volatility as a result of its gas inventory and related hedges. Gas inventory does not qualify for mark to market accounting under generally accepted accounting principles.

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 and preferred securities:

2002

2001

Fair Value

Carrying Value

Fair Value

Carrying Value

Long-Term Debt

$ 8.9 billion

$ 8.2 billion

$ 8.2 billion

$ 8.1 billion

Preferred Securities

$291 million

$271 million

$283 million

$274 million

NOTE 16 - COMMITMENTS AND CONTINGENCIES

Personal Property Taxes

Detroit Edison, MichCon and other Michigan utilities have asserted that Michigan’s valuation tables result in the substantial overvaluation of utility personal property. Valuation tables established by the Michigan State Tax Commission (STC) are used to determine the taxable value of personal property based on the property’s age. In November 1999, the STC approved new valuation tables that more accurately recognize the value of a utility’s personal property. The new tables became effective in 2000 and are currently used to calculate property tax expense. However, several local taxing jurisdictions have taken legal action attempting to prevent the STC from implementing the new valuation tables and have continued to prepare assessments 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. The Michigan Court of Appeals has not yet issued a decision on this appeal.

Detroit Edison and MichCon record property tax expense based on the new tables. Detroit Edison and MichCon will seek to apply the new tables retroactively and to ultimately settle the pending tax appeals related to 1997 through 1999. This is a solution supported by the STC in the past. The legal action, along

with possible additional appeals by local taxing jurisdictions, is expected to delay any recoveries by Detroit Edison and MichCon.

Energy Gas Environmental Matters

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. None of these former MGP sites is on the National Priorities List prepared by the EPA.

Enterprises completed the administrative proceeding before the EPA regarding one of the former MGP sites. The site received closure from the EPA in 2002. Enterprises is remediating seven of the former MGP sites and conducting more extensive investigations at five other former MGP sites. In 1998, Enterprises received state closure of one of the former MGP sites. Additionally, the MDEQ has determined with respect to two other former MGP sites that Enterprises is not a responsible party for the purpose of assessing remediation expenditures. In September 2001, Enterprises was advised of one additional MGP site for which it has some responsibility. After review of the extent of the necessary environmental clean-up required, remediation costs for this site are not expected to exceed $500,000.

In 1984, Enterprises established a $12 million reserve for environmental investigation and remediation. 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. The findings of these investigations indicate that the estimated total expenditures for investigation and remediation activities for these sites could range from $30 million to $170 million based on undiscounted 1995 costs. As a result of these studies, Enterprises accrued an additional liability and a corresponding regulatory asset of $35 million during 1995.

During 2002, Enterprises spent $3 million investigating and remediating these former MGP sites. At December 31, 2002, the reserve balance was $22 million of which $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 believe 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.

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. In 2001, due to changes in estimated future replacement costs we reduced the reserve for future steam purchase commitments by $22 million. We purchased $37 million of steam and electricity in 2002, $41 million in 2001 and $35 million in 2000. We estimate annual steam and electric purchase commitments from 2003 until 2007 will

not exceed $46 million per year. As discussed in Note 4 – Acquisitions and Dispositions, in January 2003, we sold the steam heating business of Detroit Edison to Thermal Ventures II, LLP. Due to terms of the sale, Detroit Edison will remain contractually obligated to GDRRA until 2008 and will also record an additional liability of $20 million for future commitments.

The EPA has issued ozone transport regulations and final new air quality standards relating to ozone and particulate air pollution. In September 1998, the EPA issued a State Implementation Plan (SIP) call giving states a year to develop new regulations to limit nitrogen oxide emissions because of their contribution to ozone formation. Detroit Edison has spent approximately $460 million through December 2002 and estimates that it will incur approximately $300 million to $400 million of future capital expenditures over the next five to eight years. In March 2000, the U.S. Court of Appeals ruled in favor of the EPA’s SIP call regulations. The new air quality standards have been upheld in legal challenges in the U.S. Court of Appeals, but the U.S. Supreme Court has agreed to hear the appeal. Until the legal issues are resolved, management is unable to predict the full impact of the new air quality standards. 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, would be deferred in ratemaking, until after the expiration of the rate cap period, presently expected to end December 31, 2005.

In 1997, Enterprises’ 50%-owned partnership, Washington 10, entered into a leveraged lease transaction to finance the conversion of a depleted natural gas reservoir into a 42.5 Bcf storage facility. The storage facility began operations in mid-1999 and cost $160 million to develop. Enterprises has entered into a contract with Washington 10 to market 100% of the capacity of the storage field through 2029. Under the terms of the marketing contract, Enterprises is obligated to generate sufficient revenues to cover Washington 10’s lease payments and certain operating costs, which average approximately $15 million annually.

To ensure a reliable supply of natural gas at competitive prices, Enterprises has entered into long-term purchase and transportation contracts with various suppliers and producers. In general, purchases are under fixed price and volume contracts or formulas based on market prices. Enterprises has firm purchase commitments through 2010 for approximately 392 Bcf of gas. Enterprises expects that sales, based on warmer-than-normal weather, will exceed its minimum purchase commitments. Enterprises has long-term transportation and storage contracts with various companies expiring on various dates through the year 2016. Enterprises is also committed to pay demand charges of approximately $69 million during 2003 related to firm purchase and transportation agreements.

We have also entered into long-term fuel supply commitments of approximately $450 million at December 31, 2002. We estimate that 2003 base level capital expenditures will be $850 million. We have made commitments in connection with expected capital expenditures.

Other Contingencies

We purchase and sell electricity, gas and coke to numerous companies operating in the steel, automotive, energy and retail industries. During 2002 and 2001, a number of customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code, including certain Enron Corporation affiliates, National Steel Company and Bethlehem Steel Company. At December 31, 2002, we had approximately $65 million of accounts receivable and approximately $40 million of accounts payable with these bankrupt companies. 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.

We are involved in certain legal (including commercial matters), 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, 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 financial statements in the period they are resolved.

See Note 6 and Note 7 for a discussion of contingencies related to Regulatory Matters and Nuclear Operations.

NOTE 17 - RETIREMENT BENEFITS AND TRUSTEED ASSETS

Qualified Pension Plan Benefits

We have defined benefit retirement plans for eligible union and nonunion employees. Prior to December 31, 2001, we had three separate defined benefit retirement plans. Effective December 31, 2001, two of the defined benefit retirement plans merged into one plan. All of 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. In addition, one plan also offers 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, and additional amounts we deem appropriate.

Net pension cost (credit) for the years ended December 31 includes the following components:


	(in Millions)	2002			2001			2000

Service Cost		$	43		$	40		$	35
Interest Cost			162			140			107
Expected Return on Plan Assets			(223	)		(193	)		(139	)
Amortization of
	Net loss		2			—			—
	Prior service cost		9			10			10
	Net transition asset		(2	)		(5	)		(4	)
Special Termination Benefits (Note 5)			—			167			—

Net Pension Cost (Credit)		$	(9	)	$	159		$	9

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:


	(in Millions)	2002			2001

Accumulated Benefit Obligation at the End of the Period		$	2,299		$	2,023

Projected Benefit Obligation at the Beginning of the Period		$	2,219		$	1,540
Service Cost			43			40
Interest Cost			162			140
Actuarial Loss			235			103
Special Termination Benefits (Note 5)			—			167
Benefits Paid			(160	)		(206	)
MCN Energy Acquisition			—			481
Plan Amendments			—			(46	)

Projected Benefit Obligation at the End of the Period		$	2,499		$	2,219

Plan Assets at Fair Value at the Beginning of the Period		$	2,183		$	1,416
Actual Return on Plan Assets			(213	)		(36	)
Company Contributions			35			35
Benefits Paid			(160	)		(206	)
MCN Energy Acquisition			—			974

Plan Assets at Fair Value at the End of the Period		$	1,845		$	2,183

Funded Status of the Plans		$	(654	)	$	(36	)
Unrecognized
	Net loss		1,080			442
	Prior service cost		54			31
	Net transition asset		—			(2	)

Net Amount Recognized		$	480		$	435

Amount Recorded as:
Prepaid Pension Assets		$	172		$	435
Accrued Pension Liability			(531	)		—
Accumulated Other Comprehensive Loss			785			—
Intangible Asset			54			—

		$	480		$	435

Assumptions used in determining the projected benefit obligation at December 31 are listed below:


	2002			2001			2000

Discount rate		6.75	%		7.25	%		7.5	%
Annual increase in future compensation levels		4.0	%		4.0	%		4.0	%
Expected long-term rate of return on Plan assets		9.0	%		9.5	%		9.5	%

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 accumulated benefit obligation of the plan exceeds the fair value of plan assets. Under SFAS No. 87, we recorded an additional minimum pension liability of $839 million, ($531 million after netting the previously recognized prepaid pension asset associated with the non union plan), an intangible asset of $54 million and an other comprehensive loss of $785 million ($510 million after tax).

In January 2003, we made a $222 million cash contribution to our defined benefit retirement plans.

We also sponsor defined contribution retirement savings plans. Participation in one of these plans is available to substantially all union and nonunion employees. We match employee contributions up to certain predefined limits based upon eligible compensation and in certain plans, years of credited service. The cost of these plans was $25 million in 2002, $26 million in 2001 and $22 million in 2000.

Nonqualified Pension Benefit Plans

We maintain three 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 for the years ended December 31 includes the following components:


	(in Millions)	2002		2001		2000

Service Cost		$	1	$	1	$	1
Interest Cost			3		2		1
Amortization of
	Net loss		1		—		—
	Prior service cost		1		1		1
Special Termination Benefits (Note 5)			—		6		—

Net Pension Cost		$	6	$	10	$	3

The table below reconciles the obligations, assets and funded status of the plans as well as the amounts recognized as an accrued pension liability in the consolidated statement of financial position at December 31:


	(in Millions)	2002			2001

Accumulated Benefit Obligation at the End of the Period		$	49		$	39

Projected Benefit Obligation at the Beginning of the Period		$	42		$	22
Service Cost			1			1
Interest Cost			3			2
Actuarial Loss			7			2
Special Termination Benefits (Note 5)			—			6
Benefits Paid			(3	)		(4	)
MCN Energy Acquisition			—			13

Projected Benefit Obligation at the End of the Period		$	50		$	42

Plan Assets at Fair Value at the Beginning of the Period		$	—		$	—
Company Contributions			3			4
Benefits Paid			(3	)		(4	)

Plan Assets at Fair Value at the End of the Period		$	—		$	—

Funded Status of the Plans		$	(50	)	$	(42	)
Unrecognized
	Net loss		12			6
	Prior service cost		3			4

Net Amount Recognized		$	(35	)	$	(32	)

Amount Recorded as:
Accrued Pension Liability		$	(51	)	$	(32	)
Accumulated Other Comprehensive Loss			13			—
Intangible Asset			3			—

		$	(35	)	$	(32	)

Assumptions used in determining the projected benefit obligation at December 31 are listed below:


	2002			2001			2000

Discount rate		6.75	%		7.25	%		7.5	%
Annual increase in future compensation levels		4.0	%		4.0	%		4.0	%

Under SFAS No. 87, we recorded an additional minimum pension liability of $16 million, an intangible asset of $3 million and an other comprehensive loss of $13 million ($8 million after tax).

Other Postretirement Benefits

We provide certain postretirement health care and life insurance benefits for some employees who may become eligible for these benefits while working for us.

Net postretirement cost for the years ended December 31 includes the following components:


		2002			2001			2000
(in Millions)
Service Cost		$	30		$	27		$	22
Interest Cost			78			67			48
Expected Return on Plan Assets			(59	)		(57	)		(46	)
Amortization of
	Net loss		3			1			—
	Prior service cost		(1	)		—			—
	Net transition obligation		19			20			20
Special Termination Benefits (Note 5)			—			46			—

Net Postretirement Cost		$	70		$	104		$	44

The table below 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:


		2002			2001
(in Millions)
Accumulated Postretirement Benefit Obligation at the Beginning of the Period		$	1,127		$	751
Service Cost			30			27
Interest Cost			78			67
Actuarial Loss			326			62
Special Termination Benefits (Note 5)			—			46
MCN Energy Acquisition			—			236
Plan Amendments			—			(12	)
Benefits Paid			(67	)		(50	)

Accumulated Postretirement Benefit Obligation at the End of the Period		$	1,494		$	1,127

Plan Assets at Fair Value at the Beginning of the Period		$	624		$	517
Actual Return on Plan Assets			(60	)		(25	)
Company Contributions			33			11
Benefits Paid			(60	)		(54	)
MCN Energy Acquisition			—			175

Plan Assets at Fair Value at the End of the Period		$	537		$	624

Funded Status of the Plans		$	(957	)	$	(503	)
Unrecognized
	Net loss		641			187
	Prior service cost		(7	)		(12	)
	Net transition obligation		191			226

Accrued Postretirement Liability		$	(132	)	$	(102	)

Assumptions used in determining the projected benefit obligation at December 31 are listed below:


	2002			2001			2000

Discount rate		6.75	%		7.25	%		7.5	%
Expected long-term rate of return on Plan assets		9.0	%		9.5	%		9.0	%

Benefit costs were calculated assuming health care cost trend rates beginning at 10% for 2003 and decreasing to 5% in 2009 and thereafter for persons under age 65 and decreasing from 9% to 5% 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 $15 million. The accumulated benefit obligation would have increased by $118 million at December 31, 2002. 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 $13 million and would have decreased the accumulated benefit obligation by $106 million at December 31, 2002.

In 2003, DTE Energy amended its postretirement health care and life insurance plans to reduce benefits, modify eligibility criteria and increase retiree co-pays. The changes reduced the postretirement benefit obligation by $85 million and the expected 2003 postretirement costs by $21 million. The reduction in postretirement benefit obligation and costs is not reflected in the previous tables.

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.

NOTE 18 – STOCK-BASED COMPENSATION

The DTE Energy Company 2001 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 Board members. As of December 31, 2002, no performance units have been granted under the plan.

Prior to 2001, stock options, stock awards and performance shares were issued under the Long-Term Incentive Plan adopted in 1995.

Options

Options are exercisable at a rate according to the terms of the individual stock option award agreements. The options will 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 January 1, 2000 (194,371 exercisable)			999,075		$	37.03
	Granted		2,023,400		$	32.12
	Exercised		(10,750	)	$	28.50
	Canceled		(29,500	)	$	41.14

Outstanding at December 31, 2000 (442,431 exercisable)			2,982,225		$	33.69
	Granted		2,775,341		$	42.74
	Exercised		(402,442	)	$	32.31
	Canceled		(73,500	)	$	36.26

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 at a weighted average exercise price of $38.79)			5,480,595		$	39.87

The range of exercise prices for options outstanding at December 31, 2002, was $27.62 to $46.74. 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		1,333,880	$	31.83	6.86 years
$38.60 - $42.44		2,267,814	$	41.06	8.21 years
$42.60 - $44.54		875,540	$	42.68	8.36 years
$45.28 - $46.74		1,003,361	$	45.43	8.45 years

		5,480,595	$	39.87	7.95 years

We apply APB Opinion 25, “Accounting for Stock Issued to Employees.” Accordingly, no compensation expense has been recorded for options granted. As required by SFAS No. 123, “Accounting for Stock-Based Compensation,” we have determined fair value for these options at the date of grant using a Black-Scholes based option pricing model and the following assumptions:


	2002			2001			2000

Risk-free interest rate		5.33	%		5.40	%		6.57	%
Dividend yield		4.90	%		4.73	%		6.48	%
Expected volatility		19.79	%		19.78	%		18.51	%
Expected life	6 years			10 years			10 years
Fair value per option	$	6.25		$	8.81		$	5.19

Stock Awards

Under the plan, stock awards are granted and restricted for varying periods which currently do not exceed four years. Participants have all rights of a shareholder with respect to a stock award, including the right to receive dividends and vote the shares; provided, that during such period (i) a participant may not sell, transfer, pledge, exchange or otherwise dispose of shares granted pursuant to a stock award; (ii) we shall retain custody of the certificates evidencing shares granted pursuant to a stock award; and (iii) the participant will deliver to us a stock power with respect to each stock award.

The stock awards are recorded at cost which approximates the market 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:


	2002		2001		2000

Restricted common shares awarded		113,410		247,640		29,565
Weighted average market price of shares awarded	$	42.92	$	44.35	$	32.00
Compensation cost charged against income (in thousands)	$	4,101	$	2,484	$	1,130

Performance Share Awards

Under the plan, performance shares are awards stated with reference to a specified number of shares of common stock that entitles the holder to receive a cash payment or shares of common stock or a combination thereof. The final value of the award is determined by the achievement of certain performance objectives, as defined in the plan. The awards vest as of the end of a specified period. Beginning with the grant date, we account for performance share awards by accruing an amount based on the following: (i) the number of shares expected to be awarded based on the probable achievement of certain performance objectives, (ii) the market value of the shares, and (iii) the vesting period. For 2002 and 2001, we accrued compensation expense related to performance share awards totaling $3.6 million and $1.2 million, respectively.

During the applicable restriction 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, 2002, there were 422,249 performance share awards outstanding.

NOTE 19 - SEGMENT AND RELATED INFORMATION

Beginning in 2002, we realigned our internal and external financial reporting structure into three strategic business units (Energy Resources, Energy Distribution and Energy Gas) that have both regulated and non-regulated 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 nine reportable segments:

Energy Resources

•		Regulated — 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-regulated

	•		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, which was acquired as part of the MCN Energy acquisition. Energy Marketing & Trading enters into forwards, futures, swaps and option contracts as part of its trading strategy.

	•		Other non-regulated operations consist of businesses involved in coal services and landfill gas recovery.

Energy Distribution

•		Regulated — Power Distribution operations include the electric distribution services of Detroit Edison. Energy Distribution distributes electricity generated by Energy Resources to Detroit Edison’s 2.1 million residential, commercial and industrial customers.

•		Regulated — Power Transmission operations include electric transmission services of ITC. On February 28, 2003 we sold ITC for $610 million.

•		Non-regulated operations include businesses that market and distribute a broad portfolio of distributed generation products, provide application engineering, and monitor and manage system operations.

Energy Gas

•		Regulated 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-regulated operations include the exploration and production of gas and the gathering, processing and storing of gas. Certain pipeline and storage assets are primarily 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 regulated and non-regulated businesses. Corporate & Other also includes various other non-regulated operations, including investments in new emerging energy technologies.

Goodwill allocated to each segment was as follows at December 31, 2002:


(in Millions)
Energy Resources
	Regulated – Power Generation			$	406

	Non-Regulated
			Energy Services		43
			Energy Marketing & Trading		17
			Other		7

Total Non-Regulated					67

					473

Energy Distribution
		Regulated – Power Distribution			797
		Regulated – Power Transmission (Discontinued Operation)			44
		Non-Regulated			12

					853

Energy Gas
	Regulated – Gas Distribution				776
	Non-Regulated				17

					793

Total				$	2,119

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 loss in DTE Energy’s consolidated tax return. Inter-segment revenues are not material. Financial data of the business segments follows:


							Depreciation,
				Operating			Depletion &		Interest			Income			Net			Total			Capital
(in Millions)				Revenue			Amortization		Expense			Taxes			Income			Assets			Expenditures

2002
Energy Resources
	Regulated – Power Generation			$	2,711		$	331	$	184		$	120		$	241		$	7,356		$	395
	Non-Regulated
			Energy Services		682			23		16			(264	)		182			1,536			130
			Energy Marketing & Trading		681			3		15			13			25			822			—
			Other		102			9		4			(19	)		7			256			8

	Total Non-Regulated				1,465			35		35			(270	)		214			2,614			138

Total Energy Resources					4,176			366		219			(150	)		455			9,970			533
Energy Distribution
		Regulated – Power Distribution			1,227			246		126			58			111			4,048			296
		Non-Regulated			39			2		1			(9	)		(16	)		60			2

					1,266			248		127			49			95			4,108			298
Energy Gas
	Regulated – Gas Distribution				1,369			104		57			36			66			2,467			93
	Non-Regulated				87			19		6			14			26			427			32

					1,456			123		63			50			92			2,894			125
Corporate & Other					16			—		207			(32	)		(56	)		2,437			18
Reconciliation & Eliminations					(185	)		—		(72	)		(1	)		—			(691	)		—

Totals from Continuing Operations				$	6,729		$	737	$	544		$	(84	)		586			18,718			974

Discontinued Operations (Note 4)																46			520			10

Total															$	632		$	19,238		$	984

2001
Energy Resources
	Regulated – Power Generation			$	2,788		$	385	$	181		$	65		$	149		$	7,260		$	348
	Non-Regulated
			Energy Services		434			36		22			(173	)		115			1,185			257
			Energy Marketing & Trading		554			2		13			24			44			835			—
			Other		143			10		5			(15	)		6			206			—

	Total Non-Regulated				1,131			48		40			(164	)		165			2,226			257

Total Energy Resources					3,919			433		221			(99	)		314			9,486			605
Energy Distribution
		Regulated – Power Distribution			1,199			246		125			25			92			3,995			340
		Non-Regulated			21			1		1			(6	)		(10	)		66			5

					1,220			247		126			19			82			4,061			345
Energy Gas
	Regulated – Gas Distribution				615			61		34			(49	)		(38	)		2,496			66
	Non-Regulated				51			12		7			5			11			409			23

					666			73		41			(44	)		(27	)		2,905			89
Corporate & Other					11			29		112			(35	)		(57	)		2,401			35
Reconciliation & Eliminations					(29	)		—		(33	)		40			—			(449	)		—

Totals from Continuing Operations				$	5,787		$	782	$	467		$	(119	)		312			18,404			1,074

Discontinued Operations (Note 4)																20			477			22

Total															$	332		$	18,881		$	1,096


						Depreciation,
			Operating			Depletion &		Interest			Income			Net			Total			Capital
(in Millions)			Revenue			Amortization		Expense			Taxes			Income			Assets			Expenditures

2000
Energy Resources
	Regulated – Power Generation		$	2,911		$	468	$	159		$	120		$	252		$	7,085		$	195
	Non-Regulated
		Energy Services		338			29		28			(128	)		100			808			100
		Energy Marketing & Trading		26			—		—			5			10			468			—
		Other		137			8		5			(21	)		(7	)		216			63

	Total Non-Regulated			501			37		33			(144	)		103			1,492			163

Total Energy Resources				3,412			505		192			(24	)		355			8,577			358
Energy Distribution
		Regulated – Power Distribution & Transmission (Note 4)		1,218			251		118			61			175			3,900			389
	Non-Regulated			11			2		1			(6	)		(10	)		19			—

				1,229			253		119			55			165			3,919			389
Energy Gas
	Regulated – Gas Distribution			—			—		—			—			—			—			—
	Non-Regulated			—			—		—			—			—			—			—

				—			—		—			—			—			—			—
Corporate & Other				6			—		91			(13	)		(52	)		909			2
Reconciliation & Eliminations				(9	)		—		(66	)		(9	)		—			(749	)		—

Total			$	4,638		$	758	$	336		$	9		$	468		$	12,656		$	749

NOTE 20 – 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. In February 2003, we sold ITC which has been accounted for as a discontinued operation (Note 4).


		First			Second			Third		Fourth
(in Millions, except per share amounts)		Quarter			Quarter			Quarter		Quarter		Year

2002
Operating Revenues		$	1,894		$	1,474		$	1,615	$	1,746	$	6,729
Operating Income		$	334		$	187		$	251	$	259	$	1,031
Net Income
	From continuing operations	$	192		$	61		$	139	$	194	$	586
	Discontinued operations		8			7			22		9		46

Total		$	200		$	68		$	161	$	203	$	632
Basic Earnings per Share
	From continuing operations	$	1.20		$	.38		$	.83	$	1.17	$	3.57
	Discontinued operations		.05			.04			.13		.05		.28

Total		$	1.25		$	.42		$	.96	$	1.22	$	3.85
Diluted Earnings per Share
	From continuing operations	$	1.19		$	.38		$	.83	$	1.16	$	3.55
	Discontinued operations		.05			.04			.13		.05		.28

Total		$	1.24		$	.42		$	.96	$	1.21	$	3.83
2001
Operating Revenues		$	1,161		$	1,306		$	1,583	$	1,737	$	5,787
Operating Income (Loss)		$	244		$	(91	)	$	196	$	316	$	665
Net Income (Loss)
	From continuing operations	$	138	(1)	$	(89	)	$	50	$	213	$	312	(1)
	Discontinued operations		—			2			13		5		20

Total		$	138	(1)	$	(87	)	$	63	$	218	$	332	(1)
Basic Earnings (Loss) per Share
	From continuing operations	$	.98	(1)	$	(.61	)	$	.30	$	1.37	$	2.04	(1)
	Discontinued operations		—			.01			.08		.04		.13

Total		$	.98	(1)	$	(.60	)	$	.38	$	1.41	$	2.17	(1)
Diluted Earnings (Loss) per Share
	From continuing operations	$	.97	(1)	$	(.61	)	$	.30	$	1.37	$	2.03	(1)
	Discontinued operations		—			.01			.08		.04		.13

Total		$	.97	(1)	$	(.60	)	$	.38	$	1.41	$	2.16	(1)

(1)

2001 earnings were favorably impacted by $3 million or $.02 per share due to an accounting change.

NOTE 21 – SUBSEQUENT EVENT – REGULATORY MATTERS – GAS INDUSTRY RESTRUCTURING

As discussed in Note 6 – Regulatory Matters – Gas Industry Restructuring, in July 2002, an MPSC Administrative Law Judge (ALJ) issued a Proposal for Decision on MichCon’s 2002 GCR plan case. In that decision the ALJ recommended adoption of the MPSC Staff’s proposed $26.5 million reduction in gas costs due to MichCon’s decision to utilize storage gas during 2001 that resulted in gas inventory decrement for the calendar year 2001. On March 12, 2003, the MPSC issued an order in MichCon’s 2002 GCR plan case. The MPSC ordered MichCon to reduce revenues by $26.5 million for purposes of calculating the 2002 GCR expense in the 2002 GCR reconciliation proceeding. Although we will reflect

a $26.5 million reduction in revenues in the first quarter of 2003, a final determination of actual 2002 revenue and expenses including any disallowances or adjustment will be decided in MichCon’s 2002 GCR reconciliation case.

NOTE 22 – CONSOLIDATING FINANCIAL STATEMENTS

Debt securities issued by Enterprises are subject to a full and unconditional guaranty by DTE Energy. The following DTE Energy consolidating financial statements are presented and include separately Corporate & Other, Enterprises and all other subsidiaries. Enterprises includes MichCon and other non-regulated gas subsidiaries. The other subsidiaries include Detroit Edison and other non-regulated electric subsidiaries.

DTE ENERGY COMPANY
CONSOLIDATING STATEMENTS OF OPERATIONS


			Year Ended December 31, 2002

			DTE									Eliminations
			Energy			DTE			Other			and			Consolidated
			Company			Enterprises			Subsidiaries			Reclasses			Total
(in Millions)
Operating Revenues			$	—		$	2,002		$	4,947		$	(220	)	$	6,729

Operating Expenses
	Fuel, purchased power and gas			—			1,284			1,024			(209	)		2,099
	Operation and maintenance			(90	)		334			2,274			(8	)		2,510
	Depreciation, depletion and amortization			—			125			612			—			737
	Taxes other than income			—			60			292			—			352

		Total Operating Expenses		(90	)		1,803			4,202			(217	)		5,698

Operating Income				90			199			745			(3	)		1,031

Other Income and Deductions
	Interest expense			171			91			331			(49	)		544
	Preferred stock dividends of subsidiaries			—			11			14			—			25
	Interest income			(35	)		(14	)		(29	)		49			(29	)
	Other income			(663	)		(28	)		(34	)		663			(62	)
	Other expenses			2			(1	)		52			(2	)		51

		Total Other Income and Deductions		(525	)		59			334			661			529

Income Before Income Taxes				615			140			411			(664	)		502
Income Tax Provision (Benefit)				(17	)		50			(116	)		(1	)		(84	)

Income from Continuing Operations				632			90			527			(663	)		586
Income from Discontinued Operations of ITC, net of tax				—			—			46			—			46

Net Income			$	632		$	90		$	573		$	(663	)	$	632

DTE ENERGY COMPANY
CONSOLIDATING STATEMENTS OF OPERATIONS


			Year Ended December 31, 2001

			DTE									Eliminations
			Energy			DTE			Other			and			Consolidated
			Company			Enterprises			Subsidiaries			Reclasses			Total
(in Millions)
Operating Revenues			$	—		$	1,122		$	4,677		$	(12	)	$	5,787

Operating Expenses
	Fuel, purchased power and gas			—			683			1,256			(20	)		1,919
	Operation and maintenance			(65	)		197			1,708			8			1,848
	Depreciation, depletion and amortization			—			104			678			—			782
	Taxes other than income			—			29			276			—			305
	Merger and restructuring charges			—			82			186			—			268

		Total Operating Expenses		(65	)		1,095			4,104			(12	)		5,122

Operating Income				65			27			573			—			665

Other Income and Deductions
	Interest expense			115			56			334			(38	)		467
	Preferred stock dividends of subsidiaries			—			15			—			—			15
	Interest income			(43	)		(9	)		(8	)		38			(22	)
	Other income			(339	)		1			(53	)		331			(60	)
	Other expenses			3			(1	)		70			3			75

		Total Other Income and Deductions		(264	)		62			343			334			475

Income (Loss) Before Income Taxes				329			(35	)		230			(334	)		190
Income Tax Benefit				(3	)		(5	)		(111	)		—			(119	)

Income from Continuing Operations				332			(30	)		341			(334	)		309
Income from Discontinued Operations of ITC, net of tax										20						20
Cumulative Effect of Accounting Change, net of tax				—			—			(3	)		6			3

Net Income (Loss)			$	332		$	(30	)	$	358		$	(328	)	$	332

100

DTE ENERGY COMPANY
CONSOLIDATING STATEMENTS OF FINANCIAL POSITION


			December 31, 2002

			DTE									Eliminations
			Energy			DTE			Other			and			Consolidated
(in Millions, Except Shares)			Company			Enterprises			Subsidiaries			Reclasses			Total

ASSETS
Current Assets
	Cash and cash equivalents		$	21		$	12		$	100		$	—		$	133
	Restricted cash			—			—			237			—			237
	Accounts receivable
		Customer, less allowance for doubtful accounts		—			301			601			—			902
		Accrued unbilled revenues		—			119			177			—			296
		Other		778			150			436			(1,127	)		237
	Inventories
		Fuel and gas		—			219			194			—			413
		Materials and supplies		—			19			144			—			163
	Assets from risk management and trading activities			—			78			146			—			224
	Other			22			118			21			(2	)		159

				821			1,016			2,056			(1,129	)		2,764

Investments
	Nuclear decommissioning trust funds			—			—			417			—			417
	Other			6,313			436			577			(6,839	)		487

				6,313			436			994			(6,839	)		904

Property
	Property, plant and equipment			—			3,679			14,186			(3	)		17,862
	Less accumulated depreciation and depletion			—			(2,051	)		(5,998	)		—			(8,049	)

				—			1,628			8,188			(3	)		9,813

Other Assets
	Goodwill			—			2,080			39			—			2,119
	Regulatory assets			—			45			1,152			—			1,197
	Securitized regulatory assets			—			—			1,613			—			1,613
	Assets from risk management and trading activities			—			133			19			—			152
	Prepaid pension assets			—			172			—			—			172
	Other			11			189			306			(2	)		504

				11			2,619			3,129			(2	)		5,757

Total Assets			$	7,145		$	5,699		$	14,367		$	(7,973	)	$	19,238

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
	Accounts payable		$	73		$	307		$	551		$	(284	)	$	647
	Accrued interest			17			18			83			(3	)		115
	Dividends payable			86			1			76			(73	)		90
	Accrued payroll			—			9			40			—			49
	Short-term borrowings			440			450			274			(750	)		414
	Current portion of long-term debt, including capital leases			400			259			359			—			1,018
	Liabilities from risk management and trading activities			—			159			126			(1	)		284
	Other			83			104			409			—			596

				1,099			1,307			1,918			(1,111	)		3,213

Other Liabilities
	Deferred income taxes			(339	)		(305	)		1,561			(1	)		916
	Regulatory liabilities			—			142			37			—			179
	Unamortized investment tax credit			—			22			146			—			168
	Liabilities from risk management and trading activities			—			199			9			—			208
	Liabilities from transportation and storage contracts			—			523			—			—			523
	Accrued pension liability			—			21			561			—			582
	Nuclear decommissioning			—			—			416			—			416
	Other			(104	)		146			1,032			(391	)		683

				(443	)		748			3,762			(392	)		3,675

Long-Term Debt
	Mortgage bonds, notes and other			1,733			738			3,371			(186	)		5,656
	Securitization bonds			—			—			1,585			—			1,585
	Equity-linked securities			191			—			—						191
	Capital lease obligations			—			2			80			—			82

				1,924			740			5,036			(186	)		7,514

Obligated Mandatorily Redeemable Preferred Securities of Subsidiaries Holding Solely Debentures of DTE Energy or Enterprises				—			97			174			—			271

Shareholders’ Equity
	Common stock, without par value, 400,000,000 shares authorized, 167,462,430 shares issued and outstanding			3,052			3,191			2,711			(5,902	)		3,052
	Retained earnings			2,132			(131	)		1,185			(1,054	)		2,132
	Accumulated other comprehensive loss			(619	)		(253	)		(419	)		672			(619	)

				4,565			2,807			3,477			(6,284	)		4,565

Total Liabilities and Shareholders’ Equity			$	7,145		$	5,699		$	14,367		$	(7,973	)	$	19,238

101

DTE ENERGY COMPANY
CONSOLIDATING STATEMENTS OF FINANCIAL POSITION


			December 31, 2001

			DTE									Eliminations
			Energy			DTE			Other			and			Consolidated
(in Millions, Except Shares)			Company			Enterprises			Subsidiaries			Reclasses			Total

ASSETS
Current Assets
	Cash and cash equivalents		$	8		$	9		$	251		$	—		$	268
	Restricted cash			—			—			157			—			157
	Accounts receivable
		Customer, less allowance for doubtful accounts		—			246			499			—			745
		Accrued unbilled revenues		—			112			130			—			242
		Other		358			184			415			(696	)		261
	Inventories
		Fuel and gas		—			143			202			—			345
		Materials and supplies		—			21			139			—			160
	Assets from risk management and trading activities			—			133			62			(4	)		191
	Other			25			82			3			—			110

				391			930			1,858			(700	)		2,479

Investments
	Nuclear decommissioning trust funds			—			—			417			—			417
	Other			6,466			366			448			(6,655	)		625

				6,466			366			865			(6,655	)		1,042

Property
	Property, plant and equipment			—			3,590			13,486			(3	)		17,073
	Less accumulated depreciation and depletion			—			(1,934	)		(5,590	)		—			(7,524	)

				—			1,656			7,896			(3	)		9,549

Other Assets
	Goodwill			—			1,968			35			—			2,003
	Regulatory assets			—			45			1,144			—			1,189
	Securitized regulatory assets			—			—			1,692			—			1,692
	Assets from risk management and trading activities			—			142			8			—			150
	Prepaid pension assets			—			329			106			—			435
	Other			11			351			(21	)		1			342

				11			2,835			2,964			1			5,811

Total Assets			$	6,868		$	5,787		$	13,583		$	(7,357	)	$	18,881

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
	Accounts payable		$	266		$	335		$	711		$	(731	)	$	581
	Accrued interest			10			22			85			—			117
	Dividends payable			83			1			74			(74	)		84
	Accrued payroll			—			9			99			—			108
	Short-term borrowings			425			666			287			(697	)		681
	Current portion of long-term debt, including capital leases			—			212			305			—			517
	Liabilities from risk management and trading activities			—			133			86			(3	)		216
	Other			25			67			431			—			523

				809			1,445			2,078			(1,505	)		2,827

Other Liabilities
	Deferred income taxes			(208	)		(218	)		1,912			—			1,486
	Regulatory liabilities			—			144			43			—			187
	Unamortized investment tax credit			—			24			156			—			180
	Liabilities from risk management and trading activities			—			302			8			—			310
	Liabilities from transportation and storage contracts			—			373			—			—			373
	Accrued pension liability			—			16			16			—			32
	Nuclear decommissioning			—			—			412			—			412
	Other			(70	)		171			464			(8	)		557

				(278	)		812			3,011			(8	)		3,537

Long-Term Debt
	Mortgage bonds, notes and other			1,748			1,000			3,144			—			5,892
	Securitization bonds			—			—			1,673			—			1,673
	Capital lease obligations			—			2			87			—			89

				1,748			1,002			4,904			—			7,654

Obligated Mandatorily Redeemable Preferred Securities of Subsidiaries Holding Solely Debentures of DTE Energy or Enterprises				—			274			—			—			274

Shareholders’ Equity
	Common stock, without par value, 400,000,000 shares authorized, 161,133,959 shares issued and outstanding			2,811			2,534			2,620			(5,154	)		2,811
	Retained earnings			1,846			(212	)		994			(782	)		1,846
	Accumulated other comprehensive loss			(68	)		(68	)		(24	)		92			(68	)

				4,589			2,254			3,590			(5,844	)		4,589

Total Liabilities and Shareholders’ Equity			$	6,868		$	5,787		$	13,583		$	(7,357	)	$	18,881

102

DTE ENERGY COMPANY
CONSOLIDATING STATEMENTS OF CASH FLOWS


			Year Ended December 31, 2002

			DTE			DTE						Eliminations
			Energy			Energy			Other			and			Consolidated
(in Millions)			Company			Enterprises			Subsidiaries			Reclasses			Total

Net Cash From (Used For) Operating Activities			$	515		$	228		$	1,141		$	(910	)	$	974

Investing Activities
	Plant and equipment expenditures regulated			—			(93	)		(701	)		—			(794	)
	Plant and equipment expenditures non-regulated			—			(32	)		(158	)		—			(190	)
	Proceeds from sale of assets			—			9			32			—			41
	Restricted cash for debt redemptions			—			—			(79	)		—			(79	)
	Capital contribution to subsidiary			(200	)		—			—			200			—
	Other investments			(601	)		19			(436	)		925			(93	)

		Net cash from (used for) investing activities		(801	)		(97	)		(1,342	)		1,125			(1,115	)

Financing Activities
	Issuance of long-term debt			367			—			591			—			958
	Redemption of long-term debt			(1	)		(213	)		(399	)		—			(613	)
	Issuance of preferred securities			—			—			180			—			180
	Redemption of preferred securities			—			(180	)		—			—			(180	)
	Short-term borrowings, net			15			66			(38	)		(310	)		(267	)
	Capital lease obligations			—			(1	)		(11	)		—			(12	)
	Capital contribution by parent company			—			200			—			(200	)		—
	Issuance of common stock, net			265			—			—			—			265
	Repurchase of common stock			(9	)		—			—			—			(9	)
	Capital additions from synfuel partners			—			—			22			—			22
	Dividends on common stock			(338	)		—			(295	)		295			(338	)

		Net cash from financing activities		299			(128	)		50			(215	)		6

Net Increase (Decrease) in Cash and Cash Equivalents				13			3			(151	)		—			(135	)
Cash and Cash Equivalents, Beginning of Period				8			9			251			—			268

Cash and Cash Equivalents, End of Period			$	21		$	12		$	100		$	—		$	133


			Year Ended December 31, 2001

Net Cash From (Used For) Operating Activities			$	275		$	(360	)	$	1,193		$	(297	)	$	811

Investing Activities
	Plant and equipment expenditures regulated			—			(66	)		(710	)		—			(776	)
	Plant and equipment expenditures non-regulated			—			(19	)		(301	)		—			(320	)
	Acquisition of MCN, net of cash acquired			(1,221	)		9			—			—			(1,212	)
	Proceeds from common stock redeemed by subsidiary			846			—			—			(846	)		—
	Proceeds from sale of assets			—			113			103			—			216
	Restricted cash for debt redemptions			—			—			(70	)		—			(70	)
	Other investments			—			—			(124	)		—			(124	)

		Net cash from (used for) investing activities		(375	)		37			(1,102	)		(846	)		(2,286	)

Financing Activities
	Issuance of long-term debt			1,350			200			2,704			—			4,254
	Redemption of long-term debt			—			(73	)		(1,350	)		—			(1,423	)
	Short-term borrowings, net			(494	)		205			16			(9	)		(282	)
	Capital lease obligations			—			—			(107	)		—			(107	)
	Repurchase of common stock			(438	)		—			(846	)		846			(438	)
	Dividends on common stock			(325	)		—			(306	)		306			(325	)

		Net cash from financing activities		93			332			111			1,143			1,679

Net Increase (Decrease) in Cash and Cash Equivalents				(7	)		9			202			—			204
Cash and Cash Equivalents, January 1, 2001				15			—			49			—			64

Cash and Cash Equivalents, December 31, 2001			$	8		$	9		$	251		$	—		$	268

103

DTE ENERGY COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES


					2002		2001		2000		1999		1998

					(Millions, except for ratio)
Earnings:
	Pretax earnings				$	502	$	190	$	480	$	546	$	600
		Add:
			Loss from equity investee			14		22		26		15		5
			Fixed charges			558		477		370		378		353
			Distributed income from equity investees			10		9		—		—		—

Net Earnings					$	1,084	$	698	$	876	$	939	$	958

Fixed charges:
		Interest expense			$	554	$	469	$	336	$	344	$	319
		Interest factor of rents				4		8		34		34		34

				Total fixed charges	$	558	$	477	$	370	$	378	$	353

Ratio of earnings to fixed charges						1.94		1.46		2.37		2.48		2.71

104

DTE ENERGY COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND
PREFERRED SECURITIES DIVIDENDS


					2002		2001		2000		1999		1998

					(Millions, except for ratio)
Earnings:
	Pretax earnings				$	502	$	190	$	480	$	546	$	600
		Add:
			Loss from equity investee			14		22		26		15		5
			Fixed charges			596		500		370		378		360
			Distributed income from equity investees			10		9		—		—		—

Net Earnings					$	1,122	$	721	$	876	$	939	$	965

Fixed charges:
		Interest expense			$	554	$	469	$	336	$	344	$	319
		Interest factor of rents				4		8		34		34		34
		Preferred stock dividend factor				38		23		—		—		7

				Total fixed charges	$	596	$	500	$	370	$	378	$	360

Ratio of earnings to fixed charges						1.88		1.44		2.37		2.48		2.68

105

DTE ENERGY COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS


		Year Ending December 31,

		2002			2001			2000

(in Thousands) Allowance for Doubtful Accounts (shown as Deduction from accounts receivable in the consolidated statement of financial position)
Balance at Beginning of Period		$	56,749		$	21,000		$	21,000
Additions:
	Charged to costs and expenses		44,714			35,490			18,219
	Balance acquired with MCN Energy acquisition		—			30,256			—
	Charged to other accounts (1)		15,268			11,346			3,677
Deductions (2)			(35,006	)		(41,343	)		(21,896	)

Balance At End of Period		$	81,725		$	56,749		$	21,000

Fermi 2 Refueling Outage Accrual (included in other Current liabilities in the consolidated statement of financial position)
Balance at Beginning of Period		$	1,167		$	9,789		$	18,221
Charged to costs and expenses			25,340			12,837			14,002
Deductions (3)			(1,402	)		(21,459	)		(22,434	)

Balance At End of Period		$	25,105		$	1,167		$	9,789

(1)		Collection of accounts previously written off.
(2)		Non-collectible accounts written off.
(3)		Actual amounts paid during the refueling outage.

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INDEPENDENT AUDITORS’ CONSENT

We consent to the incorporation by reference of our report dated February 11, 2003 (March 12, 2003 as to Note 21 and July 10, 2003 as to Note 2 — Asset Retirement Obligations and Note 4 — Disposition of International Transmission Company — Discontinued Operation ) (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the change in the method of accounting for goodwill and energy trading contracts in 2002 and derivative instruments and hedging activities in 2001), appearing in this Current Report on Form 8-K of DTE Energy Company in the following registration statements:


FORM	REGISTRATION
	NUMBER
Form S-3		333-99955
Form S-4		33-57545
Form S-4		383-89175
Form S-8		333-61992
Form S-8		333-62192
Form S-8		333-00023
Form S-8		333-47247

/s/ DELOITTE & TOUCHE LLP

July 14, 2003
Detroit, Michigan

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8-K SIGNATURE

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


		DTE ENERGY COMPANY

		(Registrant)

Date: July 14, 2003	By	/s/ DANIEL G. BRUDZYNSKI

		Daniel G. Brudzynski
		Chief Accounting Officer,
		Vice President and Controller

108