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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 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 2nd Avenue, Detroit, Michigan   48226-1279
(Address of principal executive offices)   (Zip Code)

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

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

Title of each class   Name of each exchange on which registered

 
Common Stock, without par value, with contingent
     preferred stock purchase rights
  New York and Chicago Stock Exchanges
     
8.75% Equity Security Units   New York Stock Exchange
     
7.8% Trust Preferred Securities *   New York Stock Exchange


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

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

None

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

Yes [X]       No [  ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [   ]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes [X]    No [  ]

Based on the closing price on June 30, 2003, our most recently completed second quarter, the aggregate market value of our Common Stock held by non-affiliates was $6.2 billion.

At January 31, 2004, 168,849,506 shares of DTE Energy’s Common Stock, substantially all held by non-affiliates, were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information in DTE Energy Company’s definitive Proxy Statement for its 2004 Annual Meeting of Common Shareholders to be held April 29, 2004, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, not later than 120 days after the end of the Registrant’s fiscal year covered by this report on Form 10-K, is incorporated herein by reference to Part III (Items 10, 11, 12, 13 and 14) of this Form 10-K.



 


TABLE OF CONTENTS

Definitions
Forward-Looking Statements
Part I
Items 1. & 2. Business & Properties
Item 3. Legal Proceedings
Item 4. Submission of Matters to a Vote of Security Holders
Part II
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters
Item 6. Selected Financial Data
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Part III
Item 10. Directors and Executive Officers of the Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management
Item 13. Certain Relationships and Related Transactions
Item 14. Principal Accountant Fees and Services
Part IV
Item 15. Exhibits, Financial Statement Schedule and Reports on Form 8-K
Signatures
Exhibit Index
Computation of Ratio of Earnings
Consent of Deloitte & Touche LLP
Chief Executive Officer Section 302 Certification
Chief Financial Officer Section 302 Certification
Chief Executive Officer Section 906 Certification
Chief Financial Officer Section 906 Certification


Table of Contents

DTE Energy Company

Annual Report on Form 10-K
Year Ended December 31, 2003

Table of Contents

                           
                      Page
                     
Definitions
                    2  
Forward-Looking Statements
                    4  
Part I
                       
 
Items 1. & 2.
          Business & Properties     5  
 
Item 3.
          Legal Proceedings     26  
 
Item 4.
          Submission of Matters to a Vote of Security Holders     26  
Part II
                       
 
Item 5.
          Market for Registrant’s Common Equity and Related        
 
          Stockholder Matters     27  
 
Item 6.
          Selected Financial Data     28  
 
Item 7.
          Management’s Discussion and Analysis of Financial        
 
          Condition and Results of Operations     29  
 
Item 7A.
          Quantitative and Qualitative Disclosures About Market Risk     54  
 
Item 8.
          Financial Statements and Supplementary Data     56  
 
Item 9.
          Changes in and Disagreements with Accountants on        
 
          Accounting and Financial Disclosure     114  
 
Item 9A.
          Controls and Procedures     114  
Part III
                       
 
Item 10.
          Directors and Executive Officers of the Registrant     114  
 
Item 11.
          Executive Compensation     114  
 
Item 12.
          Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters
    114  
 
Item 13.
          Certain Relationships and Related Transactions     114  
 
Item 14.
          Principal Accountant Fees and Services     114  
Part IV
                       
 
Item 15.
          Exhibits, Financial Statement Schedules and Reports on Form 8-K     115  
Signatures
                    120  

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Definitions
     
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 that generally produces electricity at large power plants and transmits and distributes power over long distances. Distributed generation includes fuel cells, small gas turbine engines called micro- and mini-turbines, and other devices capable of producing up to two megawatts of power.
     
DTE Energy  
DTE Energy Company, 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)
     
MCN Energy  
MCN Energy Group Inc. and subsidiary companies that were merged into Enterprises
     
MichCon  
Michigan Consolidated Gas Company and subsidiary companies
     
MPSC   Michigan Public Service Commission
     
Non-regulated Subsidiary  
A subsidiary whose conditions of service, prices of goods and services and other operating related matters are not regulated by the MPSC or the FERC
     
NRC   Nuclear Regulatory Commission
     
PSCR  
A power supply cost recovery mechanism authorized by the MPSC that allowed Detroit Edison to recover through rates its fuel, fuel-related and purchased power expenses. The clause was suspended under Michigan’s restructuring legislation signed into law June 5, 2000, which lowered and froze electric customer rates. The clause was reinstated by the MPSC effective January 1, 2004.
     
Section 29 tax credits  
Tax credits as authorized under Section 29 of the Internal Revenue Code that are designed to stimulate investment in and development of alternate fuel sources.

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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 fuel produced through a process involving chemically modifying and binding particles of coal. Synfuels are used for power generation and coke production.
     
Units of Measurement    
     
Bcf   Billion cubic feet of gas
     
Bcfe  
Conversion metric of natural gas, the ratio as defined by the Securities and Exchange Commission of 6 Mcf of gas to 1 barrel of oil.
     
gWh   Gigawatthour of electricity
     
kWh   Kilowatthour of electricity
     
Mcf   Thousand cubic feet of gas
     
MMcf   Million cubic feet of gas
     
MW   Megawatt of electricity
     
MWh   Megawatthour of electricity

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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;
 
  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.

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Part I

Items 1. & 2. Business & Properties

GENERAL

In 1995, DTE Energy incorporated in the state of Michigan. Our regulated operations consist primarily of Detroit Edison and MichCon. We also have 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, except Section 9 (a) (2) that relates to the acquisition of securities of public utility companies and Section 33 that relates to the acquisition of foreign (non-U.S.) utility companies.

Detroit Edison is a Michigan corporation organized in 1903. Detroit Edison is a public utility subject to regulation by the MPSC and FERC and 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.

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 (which was subsequently merged into Enterprises), which was completed on May 31, 2001. See Note 3 for a further discussion of the MCN Energy acquisition. MichCon is a public utility subject to regulation by the MPSC. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to 1.2 million customers in a 14,700 square mile area throughout Michigan.

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

Our 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 10-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”, “our” or “Company” are to DTE Energy and its subsidiaries, collectively.

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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 2003 diluted earnings per share of $3.09. See Note 16 - Segment and Related Information, for financial information by segment for the last three years. A discussion of each business follows.

(FLOW 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, the NRC and the EPA. Electricity is generated from Detroit Edison’s numerous fossil plants, its hydroelectric pumped storage plant and its nuclear plant, and purchased from electricity generators, suppliers and wholesalers. The electricity we produce and purchase is sold to four major classes of customers: residential, commercial, industrial and wholesale, principally throughout Michigan, the Midwest and Ontario, Canada.

Weather, economic factors and electricity prices affect sales levels to customers. Our peak load and highest total system sales generally occur during the third quarter of the year driven by air conditioning and other cooling-related demands. Power generation sales are made to a diverse base of customers in both type and number; sales levels are not dependent on any small market segment. However, due to residential rate subsidization, less than 1% of the customers constitute approximately 80% of the power

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generation margin. Additionally, business customers who have elected to participate in the electric Customer Choice program are having a significant unfavorable effect on our financial performance.

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:

                                                     
    2003   2002   2001
(in Thousands of MWh)  
 
 
Power Generated and Purchased
                                               
Power Plant Generation
                                               
 
Fossil
                                               
   
Coal
    37,408       71 %     37,381       64 %     38,424       69 %
   
Natural Gas & Other
    644       1       1,636       3       1,287       2  
 
Nuclear (Fermi 2)
    8,114       16       9,301       16       8,555       16  
 
   
     
     
     
     
     
 
 
    46,166       88       48,318       83       48,266       87  
Purchased Power
    6,354       12       9,807       17       7,482       13  
 
   
     
     
             
         
System Output
    52,520       100 %     58,125       100 %     55,748       100 %
 
   
     
     
     
     
     
 
Average Unit Cost ($/MWh)
                                               
Generation (1)
  $ 12.89             $ 12.53             $ 12.31          
 
   
             
             
         
Purchased Power (2)
  $ 41.73             $ 39.16             $ 78.24          
 
   
             
             
         
Overall Average Unit Cost
  $ 16.38             $ 17.02             $ 21.15          
 
   
             
             
         


(1)   Represents fuel costs associated with power plants.
 
(2)   Includes amounts associated with hedging activities.

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

                 
    2004
   
Expected Supply   Contracted   Open
   
 
Coal
    79 %     21 %
Natural Gas
    29 %     71 %
Purchased Power
    89 %     11 %

Power Generation’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 contracts with the balance to be obtained through short-term agreements and spot purchases. Detroit Edison has contracts with three coal suppliers for a total purchase of up to 28 million tons of low-sulfur western coal to be delivered from 2004 through 2008. Detroit Edison also has a contract with a supplier for the purchase of approximately 4 million tons of Appalachian coal to be delivered from 2004 through 2006. 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 own and lease a fleet of rail cars and have long-term transportation contracts with companies to provide rail and vessel services for delivery of purchased coal to our generating facilities.

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

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Regulation

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

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

In 2000, the Michigan Legislature enacted legislation that reduced electric rates by 5% and reaffirmed January 2002 as the date for full implementation of the electric Customer Choice program. This legislation also contained provisions freezing rates through 2003 and preventing rate increases for 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 stranded costs related to its generation operations that may not otherwise be recoverable due to electric Customer Choice related lost sales and margins. The legislation also provides for the recovery of the costs associated with the implementation of electric Customer Choice program. 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 electric Customer Choice 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. The recovery of these costs is dependent on authorization from the MPSC. As a result, we resumed application of SFAS No. 71 for our generation business in the fourth quarter of 2002.

In June 2003, Detroit Edison filed an application with the MPSC for a change in retail electric rates, resumption of the Power Supply Cost Recovery (PSCR) mechanism, and recovery of net stranded costs. Detroit Edison is specifically requesting authority to increase rates by $427 million annually with a three-year phase in as customers’ rate caps expire. In February 2004, the MPSC authorized an interim base rate increase of $248 million annually.

For additional information regarding our regulatory environment, see Note 4 - Regulatory Matters.

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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, 2003 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     215       1.9     1999    
 
Greenwood
  St. Clair     785       7.1     1979    
 
Harbor Beach
  Huron     103       0.9     1968    
 
Marysville
  St. Clair     84       0.8     1930, 1943 and 1947
 
Monroe (4)
  Monroe     3,045       27.6     1971, 1973 and 1974
 
River Rouge
  Wayne     510       4.6     1957 and 1958
 
St. Clair
  St. Clair     1,415       12.8     1953, 1954, 1959, 1961 and 1969
 
Trenton Channel
  Wayne     730       6.6     1949, 1968 and 1999
 
           
     
         
 
            7,913       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    
 
           
     
         
 
            11,043       100.0 %        
 
           
     
         


(1)   Summer net rated capabilities of generating units in service are based on periodic load tests and are changed depending on operating experience, the physical condition of units, environmental control limitations and customer requirements for steam, which otherwise would be used for electric generation.
 
(2)   Excludes one oil-fueled unit, St. Clair Unit No. 5 (250 MW), in cold standby status.
 
(3)   The Belle River capability represents Detroit Edison’s entitlement to 81.39% of the capacity and energy of the plant. See Note 6 – Jointly Owned Utility Plant.
 
(4)   The Monroe Power Plant provided 38% of Detroit Edison’s total 2003 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.

Strategy and Competition

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

Effective January 1, 2002, the electric Customer Choice program expanded in Michigan whereby all of the Company’s electric customers can choose to purchase their electricity from alternative suppliers of generation services. Detroit Edison lost 16% of retail sales in 2003 and 6% of such sales in 2002 as a result of customers choosing to purchase power from alternative suppliers under the electric Customer Choice program. If regulatory or legislative changes are not made, we expect to lose between 17% to 20% of retail sales in 2004 as a result of customers choosing to participate in the program. Customers participating in the electric Customer Choice program consist primarily of industrial and large

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commercial customers. There is a significant price difference in the wholesale and retail markets, which only allows for partial offset of the lost revenue from customer choice migration. We will continue to aggressively utilize the wholesale market to sell the generation made available by the electric Customer Choice 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. We have private letter rulings from the IRS for all of our synfuel plants. Synfuel-related Section 29 tax credits expire in 2007. Section 29 tax credits for two of our three coke batteries expired at the end of 2002 with the third expiring in 2007.

The synthetic fuel process involves chemically modifying and binding particles of coal to produce a fuel that is used for power generation and coke production. The modification involves a three-step process that produces a solid synthetic fuel product. During 2002, we sold a 95% interest in two of our synfuel plants, and in 2003, we sold a 99% interest in one of our synfuel plants and a 59% interest in two other plants. In January 2004, we sold an additional 40% interest in two of the previously sold plants, reducing our interest to 1%. We continue to consolidate these projects due to our controlling influence.

The coke battery facilities produce coke that is used in blast furnaces within the steel industry. DTE Energy is one of the largest 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%.

                             
    2003   2002   2001
(Dollars in Millions)  
 
 
Coal-Based Fuels Statistics
                       
 
Synfuel Plants:
                       
   
Operational
    9       9       5  
   
Tax Credits Generated (1)
  $ 227.7     $ 180.2     $ 64.1  
 
Coke Battery Plants:
                       
   
Operational
    3       3       3  
   
Tax Credits Generated (1)
  $ 2.5     $ 57.4     $ 88.6  

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

On-Site Energy Projects

Energy Services owns and/or operates on-site facilities, including pulverized coal injection, power generation, steam production, chilled water, wastewater treatment and compressed air. Many of these facilities deliver utility 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

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approximately 33% of the 2004 and 2005 output of these plants and lesser amounts contracted through 2008.

Properties

As of December 31, 2003, Coal-Based Fuels owns interests in and operates nine synfuel plants at eight production sites. Additionally, we have interests in three coke battery facilities in the United States, two of which we operate.

Coal-Based Fuels

                                   
Facility   Location   % Owned           Industry Served

 
 
         
Synthetic Fuels
                               
 
DTE Red Mountain, LLC
  Tarrant, AL     100       %     Foundry Coke/Steel
 
DTE Belews Creek, LLC
  Belews Creek, NC     1       %     Utility
 
DTE Utah, LLC
  Price, UT     100       %     Industrial/Utility
 
DTE Indy Coke, LLC
  Moundsville, WV     100       %     Utility
 
DTE Clover, LLC
  Bledsoe, KY     5       %     Utility
 
DTE Smith Branch, LLC
  Pineville, WV     5       %     Steel/Export
 
DTE River Hill, LLC
  Karthaus, PA     100       %     Utility
 
DTE Buckeye, LLC (2 plants)
  Cheshire, OH     41 (1)     %     Utility
Coke Battery
                               
 
EES Coke Battery Co.
  River Rouge, MI     51       %     Steel
 
Indiana Harbor Coke Co., LP
  East Chicago, IN     5       %     Steel
 
DTE Burns Harbor LLC
  Burns Harbor, IN     51       %     Steel

(1)   An additional 40% interest was sold in January 2004.

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

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)

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

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Strategy and Competition

Our strategy for Energy Services is to continue leveraging our extensive energy-related operating experience and project management capability to develop and grow the on-site energy business. We continue to evaluate opportunities to sell interests in all of our synfuel plants in 2004. We also continue to pursue opportunities to provide asset management and operations services to third parties.

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

We plan to focus on the following areas for growth:

    Optimization of our synfuel portfolio;
 
    Providing operating services to owners of power plants;
 
    Expansion of on-site energy projects; 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. We acquired CoEnergy 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.

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. Many of the former major market players have either ceased as going concerns or are no longer engaged in the energy trading business. We seek to manage this business in a manner consistent with and complementary to the growth of our other business segments. We plan to focus on physical marketing and the optimization of our portfolio of energy assets. We have risk management and credit policies to monitor and minimize risk.

Coal Services

Description

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

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Coal Services   2003   2002   2001
   
 
 
Tons of Coal Shipped (in Millions)
    32.0       28.5       23.5  

Properties

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

Strategy and Competition

We continue to leverage our position as one of the top North American coal marketers and our reputation as an efficient manager of transportation assets. Trends such as railroad and mining consolidation and the financial uncertainty of many mining firms could have an impact on how we compete in the future. We will continue to work with suppliers and the railroads to promote secure and competitive access to the energy requirements of our customers.

We acquired the rights to a proprietary technology that produces high quality coal products from fine coal slurries that are typically discarded from coal mining operations. The technology has the additional benefit of improving the environment by allowing us to restore the land in accordance with reclamation requirements of each state. The technology produces a fine-coal fuel by removing mineral matter, clay-sized impurities and oxides from waste material. The fine-coal fuel can be used in power plants, as a feedstock for synthetic fuel production and for other industrial applications. Our first facility in Ohio became operational in late-2003 and has the capacity to produce more than 500,000 tons of fine coal per year. We are negotiating an agreement for a second facility and plan to site three to five additional facilities in 2004. We believe that the waste coal recovery business will contribute significantly to future earnings and provide significant environmental benefits.

Biomass

Description

Biomass develops, owns and operates landfill gas recovery systems in the U.S. Landfill gas, a by product 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 through 2007.

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

                         
                         
(Dollars in Millions)   2003   2002   2001
   
 
 
Biomass                        
Landfill Sites
    31       30       28  
Gas Produced (in Bcf)
    26.8       27.5       24.2  
Tax Credits Generated (1)
  $ 10.5     $ 12.9     $ 11.9  

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

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Properties

Biomass has 31 operating sites located in 14 states and other projects are under development.

Strategy and Competition

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

ENERGY DISTRIBUTION

Power Distribution

Description

The electric distribution services of Detroit Edison comprise our regulated Power Distribution business. This business distributes electricity generated by Energy Resources’ Power Generation business and alternative electric suppliers to Detroit Edison’s 2.1 million customers in southeastern Michigan. This business also shares, with the Gas Distribution segment, the customer service function for our utilities. Accordingly, costs associated with this function, including collections, our call center and uncollectable accounts receivable is shared between Power Distribution and Gas Distribution.

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

Weather and economic factors affect our sales and revenues. Similar to the Power Generation business, our peak load and highest total system sales generally occur during the third quarter of the year driven by air conditioning and 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 do 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)   2003   2002   2001
   
 
 
Electric Deliveries
                       
Residential
    15,074       15,958       14,503  
Commercial
    15,942       18,395       18,777  
Industrial
    12,254       13,590       14,430  
Wholesale
    2,241       2,249       2,159  
 
   
     
     
 
 
    45,511       50,192       49,869  
Electric Choice
    7,281       3,510       1,268  
 
   
     
     
 
Total Electric Deliveries
    52,792       53,702       51,137  
 
   
     
     
 

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Regulation

Detroit Edison’s Power Distribution is subject to the jurisdiction of the MPSC and the FERC, which have regulatory authority over rates, conditions of service and other operating-related matters. As previously discussed, Michigan legislation prevents Detroit Edison from increasing rates to residential customers through 2005 and for small business customers through 2004. By order of the FERC, rates charged by ITC will remain at current levels through December 2004.

In June 2003, Detroit Edison filed an application with the MPSC for a change in retail electric rates, resumption of the PSCR mechanism, and recovery of net stranded costs. In February 2004, the MPSC authorized an interim base rate increase of $248 million annually. See Note 4 for further discussion of the Electric Transitional Rate Plan filing.

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

For additional information regarding our regulatory environment, see Note 4 – Regulatory Matters.

Energy Assistance Programs

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

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

Properties

Detroit Edison owns and operates 663 distribution substations with a capacity of approximately 31,079,000 kilovolt-amperes (kVA) and approximately 407,000 line transformers with a capacity of approximately 24,542,000 kVA. Substantially all of the net utility properties of Detroit Edison are subject to the lien of its mortgage. Circuit miles of distribution lines owned and in service as of December 31, 2003 are as follows:

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Electric Distribution

                 
    Circuit Miles
   
Operating Voltage – Kilovolts (kV)   Overhead   Underground

 
 
4.8 kV to 13.2 kV
    27,916       12,745  
24 kV
    101       690  
40 kV
    2,341       325  
120 kV
    77       13  
 
   
     
 
 
    30,435       13,773  
 
   
     
 

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

Strategy and Competition

Our strategy focuses 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 that we own, operate and over which we exercise significant control. 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 will, by FERC order, 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 in the near term.

Distributed Generation

Description

Distributed Generation, primarily consisting of DTE Energy Technologies (Dtech), has investments in emerging technologies that complement our existing businesses. We currently develop, market and distribute a 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 also provide very high efficiencies due to effective use of waste heat. Distributed generation products can use a range of technologies, including internal combustion engines, external combustion engines, mini-turbines and fuel cells.

The number of megawatts (MW) of distributed generation delivered has increased since 2001, while the average unit size has also increased. Dtech has begun to shift more of its focus on larger industrial and commercial markets and, in particular, on continuous rather than standby generation, and away from the relatively higher volume, smaller margin, residential and small commercial markets. The following table details the distributed generation capacity delivered for the past three years.

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    2003   2002   2001
   
 
 
Distributed Generation Capacity Delivered
  94 MW   89 MW   65 MW

Strategy and Competition

Our goal is to become a profitable participant in the emerging distributed generation market, providing one-stop shopping that meets customers’ total energy needs. Key milestones toward this success include full commercialization of our internal combustion engine-driven products as well as our monitoring and system operations management. Our sales structure is in place and we are continuing to expand our project support capabilities, both directly and with partners.

Our strategy is to increase our focus on our proprietary pre-engineered and packaged continuous generation products. Provisions in current as well as proposed federal and state laws are expected to provide us additional opportunities via tax credits, energy efficiency and renewable portfolio standards.

Competition in the distributed generation business comes from distributors and manufacturers of stand-by and continuous duty generators. The success of this business depends on the continued development of new products and the expansion of customer acceptance.

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. As previously discussed, this business also shares with the Power Distribution segment, the customer service function for our utilities.

The following table details sales and deliveries to these customers.

                           
(in Millions)   2003   2002   2001 (1)
     
 
 
Gas Revenues
                       
 
Gas Sales
  $ 1,242     $ 1,135     $ 491  
 
End-user Transportation
    136       122       50  
 
Intermediate Transportation
    51       48       26  
 
Other
    69       64       48  
 
   
     
     
 
 
  $ 1,498     $ 1,369     $ 615  
 
 
   
     
     
 
(in Bcf)
                       
Gas Deliveries
                       
 
Gas Sales
    181       174       95  
 
End-user Transportation
    152       171       81  
 
Intermediate Transportation
    576       492       304  
 
   
     
     
 
 
    909       837       480  
 
   
     
     
 


(1)   Includes the operations of MichCon from 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 utilize MichCon’s pipeline network to transport the gas to the customers’ facilities. Gas Distribution provides

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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.

           
      2004
     
Gas Distribution
       
Contracted Supply
       
 
Fixed Price Purchases
    33 %
 
Market Price Purchases
    67 %
 
   
 
 
    100 %
 
   
 

Supply under contract represents approximately 75% of the expected 180 Bcf of supply requirements in 2004. 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. Since MichCon continues to transport and deliver the gas to the participating customer premises at prices comparable to margins earned on gas sales, customers switching to other suppliers have little impact on MichCon’s earnings.

Under the December 2001 MPSC order, MichCon returned to a gas cost recovery (GCR) mechanism, effective January 2002. Under this mechanism, MichCon’s gas sales rates include a gas commodity component designed to recover its actual gas costs and therefore does not have a commodity price risk for prudently incurred gas costs. During 2001, MichCon was under a Gas Sales Program and incurred commodity price risk associated with its ability to secure gas supplies at prices less than $2.95 per Mcf.

In September 2003, MichCon filed an application with the MPSC for an increase in service and distribution charges (base rates) for its gas sales and transportation customers. The filing requests an

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overall increase in base rates of $194 million per year (approximately 7% increase, inclusive of gas costs), beginning January 1, 2005. MichCon has requested that the MPSC increase base rates by $154 million per year on an interim basis by April 1, 2004. The interim request is based on a projected revenue deficiency for the test year 2004.

For additional information regarding our regulatory environment, see Note 4 - Regulatory Matters.

Energy Assistance Programs

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

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

Properties

MichCon owns distribution, transmission and storage properties and facilities that are all located in the state of Michigan. At December 31, 2003, MichCon’s distribution system included approximately 18,000 miles of distribution mains, approximately 1,148,000 service lines and approximately 1,279,000 active meters. MichCon owns approximately 2,600 miles of transmission lines that deliver natural gas to the distribution districts and interconnect its storage fields with the sources of supply and the market areas. MichCon owns properties relating to four underground natural gas storage fields with an aggregate working gas storage capacity of approximately 124 Bcf. Substantially all of the net utility properties of MichCon are subject to the lien of its mortgage.

Strategy and competition

The strategy of the Gas Distribution business is to expand our role as the preferred provider of natural gas in Michigan. As a result of more efficient furnaces and appliances, we expect future revenues to remain at current levels or slightly decline. To partially offset these factors, we plan initiatives to expand our gas markets, as well as by continuing to provide energy-related services that capitalize on our expertise, capabilities and efficient systems. We also anticipate increased revenues through increased rates as a result of our rate case, which was filed on September 30, 2003 (see Note 4).

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.

Gas Production

Description

The Gas Production business owns one of the industry’s largest Antrim gas reserve bases predominantly located in the northern portion of the lower peninsula of Michigan. Our emphasis is on developing and producing the 351.9 Bcfe of proved reserves we owned as of December 31, 2003. We drilled 80 wells (68 net of interest of others) in 2003 with a success rate in excess of 90%. Wells drilled in the Antrim shale formation have high success rates and low drilling costs, and are therefore considered low risk.

Gas Production is also involved in the coal bed methane business which is a joint undertaking between Energy Gas and Energy Resources that leverages our gas capabilities with the skills and experience of other non-regulated businesses.

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Properties

The Michigan properties had 23.2 Bcfe of production in 2003. Gas Production does not anticipate adding a significant amount of new reserves to its 351.9 Bcfe of proven reserves at December 31, 2003.

Strategy

The Gas Production business is aggressively managing its Michigan gas producing assets to maximize returns on investment. We have operator responsibilities for our Michigan properties with the goal of optimizing the costs of producing reserves. Gas Production has rights to 94,866 acres (81,133 net of interest of others) of undeveloped leases. During 2004, Gas Production plans to continue developing this acreage.

In order to leverage our gas production capabilities and the skills and experience of other non-regulated businesses, we will continue to invest in opportunities in the coal bed methane business. As of December 31, 2003, the coal bed methane business has rights to 4,034 acres (3,156 net of interest of others) of undeveloped leases in Oklahoma. During 2004, the coal bed methane business plans to drill its first operated wells in Oklahoma.

Gas Storage, Pipelines & Processing

Description

The Gas Storage, Pipelines & Processing business has partnership interests in an interstate transmission pipeline, Vector Pipeline (Vector), seven carbon dioxide processing facilities and a 9.7 Bcf natural gas storage field. Additionally, we lease a 42.5 Bcf natural gas storage field located in Michigan.

Properties

                           
Gas Storage, Pipelines                        
& Processing                        
Property Classification   % Owned   Description   Location

 
 
 
Pipelines
                       
 
Vector Pipeline
    40 %   348-mile pipeline with   Midwest
 
          1,000 MMcf per day capacity        
Processing Plants
    90 %   197 MMcf per day capacity   Northern Michigan
Storage
                       
 
Washington 28
    50 %   9.7 Bcf of storage capacity   Washington Twp, MI
 
Washington 10
    %   42.5 Bcf of storage capacity   Washington Twp, MI

Strategy and Competition

Gas Storage, Pipelines & Processing focuses on opportunities in the Midwest-to-Northeast region that supply natural gas to meet growing demand. We expect much of the growth in the demand for natural gas in the 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. Vector is an interstate pipeline that is intended to fill a large portion of that need, and is complemented by Energy Gas’ significant storage capacity. Gas Storage, Pipelines & Processing has interests in seven processing plants that extract carbon dioxide from Antrim gas production making it suitable for transportation to nearby markets. Additionally, we have contract rights in natural gas storage fields, capable of storing up to 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.

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CORPORATE & OTHER

Description

Corporate & Other includes the administrative and general expenses of various corporate support functions such as accounting, legal and information technology. These functions essentially support the entire company and the related costs are allocated to the various segments based on services utilized. Additionally, Corporate & Other holds certain non-regulated debt and 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.

ENVIRONMENTAL MATTERS

We are subject to extensive environmental regulation. Additional costs may result as the effects of various chemicals on the environment are studied and governmental regulations are developed and implemented. We expect to continue recovering environmental costs related to utility operations through rates charged to our customers. Greater details on environmental issues are provided in the following Notes to the Consolidated Financial Statements:

     
Note   Title

 
4   Regulatory Matters
5   Nuclear Operations
13   Commitments and Contingencies

Detroit Edison

Detroit Edison is subject to applicable permit requirements, and to potentially 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, in December, 2003, proposed additional emission regulations relating to ozone, fine particulate and mercury air pollution. The new rules have led to additional controls on fossil-fueled power plants to reduce nitrogen oxides, sulfur dioxide, carbon dioxide and particulate emissions. To comply with these new controls, Detroit Edison has spent approximately $560 million through December 2003 and estimates that it will spend approximately $40 million in 2004 and incur up to an additional $1.2 billion of future capital expenditures over the next five to eight years to satisfy both the existing and proposed new control requirements. The EPA initiated enforcement actions against several major electric utilities citing violations of new source provisions of the Clean Air Act. Detroit Edison received and responded to information requests from the EPA on this subject. In October 2003, the EPA promulgated revised regulations to clarify new source review provisions going forward. Several states and environmental organizations have challenged these regulations and in December 2003 the Court stayed the implementation of the regulations until the U.S. Court of Appeals D.C. Circuit renders an opinion in the case. We cannot predict the future impact of this issue upon Detroit Edison.

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.

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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 gas utility located in Adrian, Michigan) owns, or previously owned, 18 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 seven of the former MGP sites and conducting more extensive investigations at six other former MGP sites. Enterprises received MDEQ closure of one site and a determination that it is not a responsible party for three other sites. Enterprises received closure from the EPA in 2002 for one site. 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.

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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.

Electric Customer Choice – Without regulatory and legislative changes, the negative impact of the electric Customer Choice program will continue to impact our financial 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.

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

Rate regulation – We operate in a regulated industry. Our electric and gas rates are set by the MPSC and the FERC and cannot be increased without 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 require us to incur additional expenses. There is no assurance that our currently pending electric and gas rate increases will be granted.

Section 29 tax credits – We have generated Section 29 tax credits from our synfuel, coke battery, biomass and gas production operations. Generating Section 29 tax credits is important to minimizing our income tax expense. Although, we have received favorable private letter rulings on all of our synfuel plants, the generation of tax credits is subject to audit and review by the Internal Revenue Service. If we do not prevail through the administrative and legal processes, there could be additional tax liabilities owed for previously recognized Section 29 tax credits that could impact our earnings and cash flows. Four of our synfuel facilities are under audit by the IRS for 2001. 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 investment in credit producing activities and new tax legislation could hinder our plan to sell interests in tax credit properties that could have an impact on our earnings and cash flows. We have also provided certain guarantees and indemnities in conjunction with the sales of interests in our synfuel facilities.

Credit ratings – Increased scrutiny of the energy industry and regulatory changes, as well as changes in our economic performance could result in credit agencies reexamining our credit rating. Several of the credit agencies have placed a “negative outlook” on our ratings due primarily to the uncertainty regarding our electric and gas rate cases. A downgrade in our rating could restrict or discontinue our ability to access capital markets at attractive rates and increase our borrowing costs.

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. Economic conditions in our service territory also impact our collections of accounts receivable.

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

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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.

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 would have an impact on our business. We have begun negotiations with unions for contracts expiring in 2004 and cannot predict the outcome. An unfavorable outcome, such as a strike, could adversely impact the 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.

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.

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

Terrorism – Damage to downstream infrastructure or our own assets by terrorist groups would impact our operations.

Energy trading markets – 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.

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EMPLOYEES

The table below shows our employees as of December 31, 2003:

                         
    Represented   Non-represented   Total
   
 
 
Detroit Edison
    4,062       3,946       8,008  
MichCon
    1,514       787       2,301  
Other
    98       692       790  
 
   
     
         
Total
    5,674       5,425       11,099  
 
   
     
     
 

There are several bargaining units for our represented employees. Of the 5,674 represented employees, 4,695 are under contracts that expire in June through October 2004. The contracts of the remaining represented employees expire in 2005 through 2007. We have begun negotiations on the labor contract that expires in June of 2004 and cannot predict the outcome.

EXECUTIVE OFFICERS OF DTE ENERGY

                 
                Present
                Position
Name   Age (1)   Present Position   Held Since

 
 
 
Anthony F. Earley, Jr.     54     Chairman of the Board, Chief Executive Officer, President, Chief Operating Officer   8-1-98
Gerard M. Anderson     45     Group President, Energy Resources   5-31-01
Robert J. Buckler     54     Group President, Energy Distribution   5-31-01
Stephen E. Ewing     59     Group President, Energy Gas   5-31-01
David E. Meador     46     Senior Vice President and Chief Financial Officer   5-31-01
Bruce D. Peterson     47     Senior Vice President and General Counsel   6-25-02
S. Martin Taylor     63     Senior Vice President   4-28-99
Susan M. Beale     55     Vice President and Corporate Secretary   12-11-95
Daniel G. Brudzynski     43     Vice President and Controller   2-8-01


(1)   As of December 31, 2003

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. Ewing and Peterson, all of the above officers have been employed by DTE Energy in one or more management capacities during the past five years.

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

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

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

Article VII of our Articles of Incorporation provides that each current or former director or officer of DTE Energy, or each current and former employee or agent of the company or a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise (including the heirs, executors, administrators or estate of such person), shall be indemnified by the company to the full extent permitted by the Michigan Business Corporation Act or any other applicable laws as presently or hereafter in effect. In addition, we have entered into indemnification agreements with all of our officers and directors, these agreements set forth procedures for claims for indemnification as well as contractually obligating us to provide indemnification to the maximum extent 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 six insurance policies providing aggregate coverage in the amount of $150 million.

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Item 3. Legal Proceedings

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

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

     
Note   Title

 
4   Regulatory Matters
5   Nuclear Operations
13   Commitments and Contingencies

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

We did not submit any matters to a vote of security holders in the fourth quarter of 2003.

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Part II

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters

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

                                 
                            Dividends
                            Paid
Calendar   Quarter   High   Low   Per Share

 
 
 
 
2003
                               
 
  First   $ 49.50     $ 38.51     $ 0.515  
 
  Second   $ 44.95     $ 38.52     $ 0.515  
 
  Third   $ 38.98     $ 34.00     $ 0.515  
 
  Fourth   $ 39.76     $ 35.12     $ 0.515  
2002
                               
 
  First   $ 45.75     $ 39.65     $ 0.515  
 
  Second   $ 47.70     $ 42.65     $ 0.515  
 
  Third   $ 44.56     $ 33.05     $ 0.515  
 
  Fourth   $ 46.90     $ 38.20     $ 0.515  

At December 31, 2003, there were 168,606,522 shares of our common stock outstanding. These shares were held by a total of 105,173 shareholders of record.

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

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

Pursuant to Article I, Section 8.(c) and Article II, Section 3.(c) of our By-laws, as amended through September 1, 1999, notice is given that the 2004 Annual Meeting of the company’s Common Shareholders will be held on Thursday April 29, 2004.

All of our equity compensation plans that provide for the annual awarding of stock-based compensation have been approved by shareholders. See Note 15 — Stock Based Compensation for additional detail. See below for information as of December 31, 2003.

                         
    Number of securities           Number of securities
    to be issued upon   Weighted-average   remaining available for
    exercise of   exercise price of   future issuance under equity
    outstanding options   outstanding options   compensation plans
   
 
 
Plans approved by shareholders
    6,653,122     $ 40.18       8,728,461  

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Item 6. 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)   2003   2002   2001(1)   2000   1999
   
 
 
 
 
Operating Revenues
  $ 7,041     $ 6,729     $ 5,787     $ 4,638     $ 4,499  
Net Income
                                       
 
Regulated operations
  $ 281     $ 418     $ 198     $ 427     $ 434  
 
Non-regulated operations (2)
    199       168       111       41       49  
 
   
     
     
     
     
 
 
Total from continuing operations
    480       586       309       468       483  
 
Discontinued operations (3)
    68       46       20              
 
Cumulative effect of accounting changes
    (27 )           3              
 
   
     
     
     
     
 
Net Income
  $ 521     $ 632     $ 332     $ 468     $ 483  
 
   
     
     
     
     
 
Diluted Earnings Per Share
                                       
 
Regulated operations
  $ 1.67     $ 2.53     $ 1.29     $ 2.99     $ 3.00  
 
Non-regulated operations (2)
    1.18       1.02       .72       .28       .33  
 
   
     
     
     
     
 
 
Total from continuing operations
    2.85       3.55       2.01       3.27       3.33  
 
Discontinued operations (3)
    .40       .28       .13              
 
Cumulative effect of accounting changes
    (.16 )           .02              
 
   
     
     
     
     
 
Diluted Earnings Per Share
  $ 3.09     $ 3.83     $ 2.16     $ 3.27     $ 3.33  
 
   
     
     
     
     
 
Financial Information
                                       
 
Dividends Declared Per Share of Common Stock
  $ 2.06     $ 2.06     $ 2.06     $ 2.06     $ 2.06  
 
Total Assets
  $ 20,753     $ 19,985     $ 19,587     $ 13,350     $ 13,021  
 
Long-Term Debt, including capital leases
  $ 7,669     $ 7,803     $ 7,928     $ 4,039     $ 4,091  
 
Shareholders’ Equity
  $ 5,287     $ 4,565     $ 4,589     $ 4,009     $ 3,909  


(1)   Includes the operations of MCN Energy from the May 31, 2001 acquisition date.
 
(2)   Includes Corporate & Other.
 
(3)   Represents the operations of ITC that were sold in February 2003 (Note 3).

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

OVERVIEW

DTE Energy is a diversified energy company with approximately $7 billion in revenues in 2003 and approximately $21 billion in assets at December 31, 2003. We are the parent company of Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales and distribution services throughout southeastern Michigan. Additionally, we have numerous non-regulated subsidiaries involved in energy-related businesses predominantly in the Midwest and eastern U.S.

The majority of our earnings are derived from utility operations and the production of synthetic fuel, which qualifies for Section 29 tax credits. Earnings in 2003 were $521 million, or $3.09 per diluted share, down from 2002 earnings of $632 million, or $3.83 per diluted share. Earnings from continuing operations in 2003 were $480 million, or $2.85 per diluted share, compared to 2002 earnings from continuing operations of $586 million, or $3.55 per diluted share. The 18% decrease in income reflects significantly lower utility earnings, partially offset by increased contributions from our non-regulated businesses. Our 2003 financial performance was primarily influenced by:

  Weather, including storms and power outages;
 
  Lost revenues from electric Customer Choice penetration;
 
  The regulatory environment in Michigan and the need to increase utility rates;
 
  Higher operating costs;
 
  The optimization of Section 29 tax credits; and
 
  Growth of non-regulated businesses

Weather – Earnings in our electric and gas utilities are seasonal and extremely sensitive to weather. Electric utility earnings are dependent on hot summer weather while the gas utility’s results are driven by cold winter weather. We experienced both milder summer and winter weather during 2003, which negatively impacted sales demand. The lower demand reduced current year earnings by $64 million compared to 2002, which was an above-normal weather demand year.

Additionally, we occasionally experience various types of storms that damage our electric distribution infrastructure resulting in power outages. Our current year earnings were affected by several catastrophic wind and ice storms, as well as by the August blackout. Restoration and other costs associated with these power outages lowered 2003 earnings by an additional $31 million compared to 2002.

Electric Customer Choice Program - The electric Customer Choice program as originally structured in Michigan anticipated an eventual transition to a totally deregulated and competitive environment where customers would be charged market-based rates for their electricity. However, Detroit Edison’s rates continue to be regulated by the MPSC, while alternative suppliers can charge market-based rates. This continued regulation has hindered Detroit Edison’s ability to retain customers. Detroit Edison’s results have been unfavorably impacted by the lack of recovery of lost margins and other costs associated with the electric Customer Choice program. Under Michigan legislation, we are allowed to recover net stranded costs associated with the electric Customer Choice program. To date, the MPSC has not fully implemented various provisions of Michigan’s restructuring legislation. Specifically, the MPSC:

    has not finalized all the components for calculating net stranded costs;
 
    has created a process whereby net stranded costs would be recovered two years after the costs were actually incurred;
 
    has not authorized timely recovery of any implementation costs associated with the electric Customer Choice program; and
 
    has created artificial incentives to encourage participation in the electric Customer Choice program

In addition, the MPSC has maintained regulated rates for certain groups of customers that exceed the cost of service to those customers. This has resulted in high levels of participation in the electric Customer Choice program by those customers that have the highest price relative to their cost of service. As a result, we continue to lose sales each year and are seeing an accelerating pace of migration towards the end of 2003. Lost margins and electricity volumes associated with electric Customer Choice were

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approximately $120 million and 7,281 gigawatthour (gWh) in 2003, compared with $50 million and 3,510 gWh in 2002. In February 2004, the MPSC authorized an interim base rate increase that recognized a revenue deficiency for lost Choice revenues, and eliminated transition credits and implemented a transition charge for Choice customers. The interim order is expected to reduce the level of Choice sales volumes. Assuming no further changes to the current electric Customer Choice program, we expect to continue losing margins and volumes in 2004. Partially offsetting the impact of lost margins in 2003, we recorded regulatory assets of $68 million representing an estimate of stranded costs that we believe are recoverable under Michigan legislation. Based on the MPSC’s July 2003 order, we do not believe that any of the stranded costs in years prior to 2003 are recoverable. There are a number of variables and estimates that impact the level of recoverable stranded costs, including weather, sales mix and wholesale prices. As a result, our estimate of stranded costs could increase or decrease. The actual amount of stranded costs to be recovered will ultimately be determined by the MPSC.

Detroit Edison addressed numerous issues with the electric Customer Choice program, including stranded costs, in its June 2003 rate filing and is also pursuing a legislative solution. Under the legislative solution, we are proposing to limit Customer Choice program participation to customers whose electric demand is 1 MW or greater. The continued delay in addressing the structural problems of the electric Customer Choice program and the timely and full recovery of stranded costs, unfavorably impacts earnings and cash flow. See Note 4 for a further discussion of the electric Customer Choice program and the MPSC interim rate order.

Electric and Gas Rate Plans – In 2000, Michigan legislation froze electric rates for all residential, commercial and industrial customers through 2003. The legislation also prevented rate increases or capped rates for residential customers through 2005, and for small commercial and industrial customers through 2004. The rate freeze and caps apply to base rates as well as rates designed to recover fuel and purchased power costs. Historically, these costs have been a pass-through under the power supply cost recovery (PSCR) mechanism.

In June 2003, Detroit Edison filed an application with the MPSC for: 1) an increase in retail electric rates of $427 million annually, 2) the resumption of the PSCR mechanism, and 3) the recovery of net stranded and other costs as permitted under Michigan legislation. Detroit Edison received an interim order in this rate case authorizing an increase in rates of $248 million annually. As a result of rate caps and other factors, the interim rate increase is only designed to increase revenues by $71 million in 2004 (Note 4). A final order is expected in the third quarter of 2004. The rate increase is effective for each customer class upon the expiration of the applicable rate cap period. The rate request is designed to more accurately reflect, among other things, significantly higher cost of service levels that Detroit Edison has experienced over the past few years.

The recovery of net stranded costs, electric Customer Choice implementation costs and other costs incurred as a result of changes in taxes, laws and governmental actions are covered under Michigan legislation. However, the MPSC has not approved a final mechanism to recover such costs, and this has negatively affected our cash flow. As part of its rate filing, Detroit Edison has requested authorization to implement a 5-year surcharge to recover these costs. The MPSC deferred addressing this item until a final rate order is issued.

In September 2003, MichCon filed an application with the MPSC for an increase in service and distribution charges for its gas sales and transportation customers totaling $194 million annually. The rate increase would be MichCon’s first since 1992, and is designed to recover significantly higher operating costs. MichCon expects an interim order in this case in mid-2004, with a final order by January 2005.

Operating Costs – During 2003, we experienced double-digit increases in regulated operation and maintenance costs. The increases were driven by higher costs associated with pension and health care benefits, uncollectable accounts receivable and customer service initiatives. To address this issue of rising costs, we implemented several cost savings initiatives that partially offset these increases. Some of the initiatives were structural in nature, whereas others were temporary. Examples of these initiatives included a hiring freeze, a pause on discretionary spending and overtime restrictions. Additionally, we

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reduced employee compensation costs, property and other taxes as well as interest costs through debt refinancings.

Synthetic Fuel Operations - We operate nine synthetic fuel production plants at eight locations. Interests in two of the nine plants were sold in 2002, interests in three other plants were sold in November 2003, and additional interests were sold in January 2004 in two of the plants sold in 2003. We continue to wholly own the remaining four plants, but intend to sell interests in all such plants in 2004. Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applicable IRS rules. Section 29 of the Internal Revenue Code provides tax credits for the production and sale of solid synthetic fuel produced from coal. In addition to meeting various qualifying conditions, a taxpayer must have sufficient taxable income to earn the Section 29 credits.

Our 2003 earnings were unfavorably affected by our inability to sell interests in synfuel plants until late 2003. The IRS suspended the issuance of private letter rulings (PLRs) relating to synthetic fuel projects in May 2003, pending its review of issues concerning chemical change, which is the basis for earning Section 29 tax credits. As a result of the IRS suspension, we were unable to complete the pending sale of interests in our synfuel projects. In addition, we experienced lower taxable earnings due to milder weather and continued cost and margin pressures. The temporary delay in selling interests in the synfuel projects, coupled with the lower taxable earnings, resulted in our capacity to generate more credits than we could utilize. These factors caused us to reduce our synthetic fuel production by approximately one-half in June 2003 to optimize the tax credits generated from these facilities. We began implementing a series of initiatives, including the monetization of in-the-money gas swap derivative contracts, to improve cash flow and increase taxable income thereby allowing us to more fully utilize our Section 29 tax credits.

In October 2003, the IRS concluded its assessment of the chemical change process involved in synfuel production and resumed issuing PLRs. The IRS determined that the test procedures and results used by taxpayers were scientifically valid if the procedures were applied in a consistent and unbiased manner. The conclusion of the IRS assessment allowed us to complete the sale of interests in additional facilities and increase synfuel production levels for the balance of 2003.

Non-regulated Growth – During 2003, we continued to experience growth in our non-regulated businesses with income reaching $199 million compared to $168 million in 2002. The significant improvement reflects increased contributions from our Energy Services segment due to higher synfuel production, partially offset by the impact of certain coke battery-related Section 29 tax credits expiring in 2002. Additionally, non-regulated growth in 2003 is attributable to increased margins in our Energy Marketing & Trading segment. We also realized gains in 2003 from the sale of our 16% interest in the Portland Natural Gas Transmission System, an interstate pipeline company, and the settlement of a tolling contract at one of our merchant generating facilities.

Although DTE Energy’s overall earnings were down 18% in 2003, our cash from operations totaling $950 million was comparable to the prior year despite a $222 million cash contribution to our pension plan. Operating cash flow reflects our successful initiative in 2003 to conserve cash, including better working capital management. This initiative coupled with $233 million in lower capital expenditures and over $750 million from selling non-strategic and other assets, resulted in a lower debt to total capital ratio and a healthier balance sheet.

Outlook - We are facing many challenges in 2004 to maintain earnings and cash flow levels, while protecting a strong balance sheet. Our financial performance over the short term will be dependent on preserving healthy electric and gas utilities, monetizing our synthetic fuel projects and continuing to grow our non-regulated businesses in a prudent manner.

Remedying the structural issues of the electric Customer Choice program in Michigan is a key priority for the organization. These issues must be corrected to prevent the continued migration of customers to the Choice program based on false market signals. The potential implications to remaining customers over the longer term could be significantly higher electricity rates.

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The timing and ultimate amount of final rate relief granted in the current electric and gas rate cases will affect customer service levels and our financial performance. Cash flow and earnings from our utilities will remain under pressure until the regulatory uncertainties are resolved. However, we remain focused on good cash management and a healthy balance sheet.

We are aggressively pursuing the sales of interests in all of our remaining synthetic fuel projects in 2004. These sales, in addition to previously completed sales, are expected to provide a $200 million to $300 million boost to our cash flow in 2004. The availability of qualified buyers and the timing of these sales will impact this financial outcome. In addition, we are continuing to grow our non-regulated businesses in areas such as waste coal technologies, coal bed methane production and on-site energy project development. Due to the regulatory uncertainties over the short term, we remain disciplined and conservative in our pursuit of incremental growth investments.

RESULTS OF OPERATIONS

We had income of $521 million in 2003, or $3.09 per diluted share, compared to income of $632 million, or $3.83 per diluted share in 2002 and income of $332 million, or $2.16 per diluted share in 2001. The comparability of earnings was impacted by the sale of our transmission business, International Transmission Company (ITC), and the adoption of new accounting rules as subsequently discussed. Upon selling ITC in February 2003, we classified this business as a discontinued operation. Excluding discontinued operations and the cumulative effect of accounting changes, our earnings from continuing operations in 2003 were $480 million, or $2.85 per diluted share, compared to earnings of $586 million, or $3.55 per diluted share in 2002 and earnings of $309 million, or $2.01 per diluted share in 2001. The following sections provide a detailed discussion of our segments, operating performance and future outlook.

Segment Performance & Outlook - 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. This results in the following reportable segments.

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(in Millions, except per share data)   2003   2002   2001
       
 
 
Net Income (Loss)
                       
Energy Resources
                       
 
Regulated - Power Generation
  $ 235     $ 241     $ 139  
 
   
     
     
 
 
Non-regulated
                       
   
Energy Services
    199       182       115  
   
Energy Marketing & Trading
    45       25       44  
   
Other
    (2 )     7       6  
 
   
     
     
 
 
Total Non-regulated
    242       214       165  
 
   
     
     
 
 
    477       455       304  
 
   
     
     
 
Energy Distribution
                       
 
Regulated - Power Distribution
    17       111       97  
 
Non-regulated
    (15 )     (16 )     (10 )
 
   
     
     
 
 
    2       95       87  
 
   
     
     
 
Energy Gas
                       
 
Regulated - Gas Distribution
    29       66       (38 )
 
Non-regulated
    29       26       11  
 
   
     
     
 
 
    58       92       (27 )
 
   
     
     
 
Corporate & Other
    (57 )     (56 )     (55 )
 
   
     
     
 
Income from Continuing Operations
                       
 
Regulated
    281       418       198  
 
Non-regulated (1)
    199       168       111  
 
   
     
     
 
 
    480       586       309  
Discontinued Operations
    68       46       20  
Cumulative Effect of Accounting Changes
    (27 )           3  
 
   
     
     
 
Net Income
  $ 521     $ 632     $ 332  
 
   
     
     
 
Diluted Earnings Per Share
                       
Regulated
  $ 1.67     $ 2.53     $ 1.29  
Non-regulated (1)
    1.18       1.02       .72  
 
   
     
     
 
Income from Continuing Operations
    2.85       3.55       2.01  
Discontinued Operations
    .40       .28       .13  
Cumulative Effect of Accounting Changes
    (.16 )           .02  
 
   
     
     
 
Net Income
  $ 3.09     $ 3.83     $ 2.16  
 
   
     
     
 


(1)   Includes Corporate & Other.

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ENERGY RESOURCES

Power Generation

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

                         
(in Millions)   2003   2002   2001
   
 
 
Operating Revenues
  $ 2,448     $ 2,711     $ 2,788  
Fuel and Purchased Power
    (920 )     (1,048 )     (1,231 )
 
   
     
     
 
Gross Margin
    1,528       1,663       1,557  
Operation and Maintenance
    (628 )     (626 )     (571 )
Depreciation and Amortization
    (224 )     (331 )     (385 )
Taxes Other Than Income
    (157 )     (156 )     (148 )
Merger and Restructuring Charges (Note 3)
                (72 )
 
   
     
     
 
Operating Income
    519       550       381  
Other Income and (Deductions)
    (149 )     (189 )     (184 )
Income Tax Provision
    (135 )     (120 )     (58 )
 
   
     
     
 
Net Income
  $ 235     $ 241     $ 139  
 
   
     
     
 
Operating Income as a Percent of Operating Revenues
    21 %     20 %     14 %

Factors impacting income: Power Generation earnings decreased $6 million in 2003 and increased $102 million in 2002, compared to the prior year. As subsequently discussed, these results primarily reflect changes in gross margins, increased operation and maintenance expenses and the recording of higher regulatory deferrals, which lowered depreciation and amortization expenses.

Merger and restructuring charges associated with the 2001 MCN Energy acquisition also impacted the comparability of results. These charges represent costs associated with systems integration, relocation, legal, accounting and consulting services, as well as 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.

Gross margins in 2003 declined $135 million due primarily to decreased cooling demand resulting from mild summer weather, lost margins from customers choosing to purchase power from alternative suppliers under the electric Customer Choice program and lost margins from the August 2003 blackout. Weather in 2003 was 38% milder than 2002 resulting in lost margins of $114 million. Detroit Edison lost 16% of retail sales in 2003 and 6% of such sales in 2002 as a result of customers choosing to purchase power from alternative suppliers under the electric Customer Choice program. We estimate that we lost $120 million of margins in 2003 under the electric Customer Choice program, an increase of $70 million over 2002. Lost Choice margins that we believe are recoverable under Michigan legislation are recorded as regulatory assets and therefore reduced depreciation and amortization expense as subsequently discussed. Gross margins benefited from a $.64 per MWh (4%) decline in fuel and purchased power costs reflecting the use of a more favorable power supply mix. The favorable mix is due to lower purchases, which is driven by lost sales under the electric Customer Choice program.

Gross margins in 2002 improved $106 million due primarily to significantly lower fuel and purchased power costs, partially offset by reduced operating revenues. The reduction in fuel and purchased power costs was driven by a $39.08 per MWh (50%) reduction in average purchased power prices from 2001 levels. The decline in operating revenues is attributable to commercial, industrial and wholesale customers. Commercial and industrial revenues were lower due to a full year’s impact of a 5% legislatively mandated rate reduction for customers that began in April 2001. Additionally, revenues from these retail customers were affected by customers switching to alternative suppliers under the electric Customer Choice program. Revenues from wholesale customers were reduced, reflecting lower power prices. Partially offsetting these revenue reductions was the impact of weather, resulting in a 10% increase in cooling demand during 2002.

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(in Thousands of MWh)   2003           2002           2001        
   
         
         
       
Power Generated and Purchased
                                               
Power Plant Generation
                                               
 
Fossil
                                               
   
Coal
    37,408       71 %     37,381       64 %     38,424       69 %
   
Natural Gas & Other
    644       1       1,636       3       1,287       2  
 
Nuclear (Fermi 2)
    8,114       16       9,301       16       8,555       16  
 
   
     
     
     
     
     
 
 
    46,166       88       48,318       83       48,266       87  
Purchased Power
    6,354       12       9,807       17       7,482       13  
 
   
     
     
     
     
     
 
System Output
    52,520       100 %     58,125       100 %     55,748       100 %
 
   
     
     
     
     
     
 
Average Unit Cost ($/MWh)
                                               
Generation (1)
  $ 12.89             $ 12.53             $ 12.31          
 
   
             
             
         
Purchased Power (2)
  $ 41.73             $ 39.16             $ 78.24          
 
   
             
             
         
Overall Average Unit Cost
  $ 16.38             $ 17.02             $ 21.15          
 
   
             
             
         


(1)   Represents fuel costs associated with power plants.
 
(2)   Includes amounts associated with hedging activities.

Operation and maintenance expense increased $2 million in 2003 and $55 million in 2002. Operation and maintenance expenses in 2003 were affected by $5 million in costs associated with the August 2003 blackout (Note 4) and a $69 million increase in employee pension and health care benefit costs, due to recent financial market performance, lower discount rates and increased health care trend rates. Partially offsetting these increases were benefits from the DTE Operating System, our company-wide initiative to pursue cost efficiencies as well as enhance operating performance. The DTE Operating System involves the application of tools and operating practices, which have resulted in inventory reductions and improvements in technology systems, among other enhancements. Operation and maintenance expenses in 2003 also benefited from $23 million in sales of emissions credits and lower employee incentive costs.

Operation and maintenance expenses in 2002 reflect $18 million in higher employee pension and health care benefit costs and $43 million in expenses associated with maintaining our generation fleet. The 2002 increase also includes a $5 million increase in allocations for corporate support services, as well as $11 million to fund 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 $107 million in 2003 and $54 million in 2002. The decrease in depreciation and amortization expense is attributable to the income effect of recording regulatory assets totaling $126 million in 2003 and $41 million in 2002 representing the deferral of net stranded and other costs we believe are recoverable under Public Act 141. The decline in 2002 also reflects the extension of the amortization period from seven years to 14 years for certain regulatory assets that were securitized in 2001. See Note 4 – Regulatory Matters. Partially offsetting these declines was increased depreciation associated with generation-related capital expenditures.

Other income and deductions declined $40 million in 2003 and increased $5 million in 2002. The reduction in 2003 is attributable to lower interest expense and increased interest income. Interest expense reflects lower borrowing levels and rates, and interest income includes the accrual of carrying charges on environmental-related regulatory assets.

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

As previously discussed, we expect to continue losing retail sales and margins in future years under the electric Customer Choice program until the inequities associated with this program are addressed. We will accrue as regulatory assets our unrecovered generation-related fixed costs due to electric Customer Choice that we believe are recoverable under Michigan legislation. We have addressed the issue of stranded costs in our June 2003 electric rate filing and are also pursuing a legislative solution. Additionally, we requested an increase in retail electric rates of $427 million annually to recover higher operating costs and the resumption of the PSCR mechanism. In February 2004, the MPSC authorized an interim base rate increase of $248 million annually. The actual timing and level of recovering stranded and operating costs will ultimately be determined by the MPSC or legislation. We cannot predict the outcome of these matters. See Note 4 – Regulatory Matters.

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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 injection, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. Merchant Generation owns and operates four gas-fired peaking electric generating plants and develops and acquires gas and coal-fired generation.

                             
(in Millions)   2003   2002   2001
       
 
 
Operating Revenues
                       
 
Coal-Based Fuels
  $ 850     $ 559     $ 365  
 
On-Site Energy Projects
    70       63       53  
 
Merchant Generation
    9       23       29  
 
   
     
     
 
 
    929       645       447  
Operation and Maintenance
    (966 )     (708 )     (400 )
Depreciation, Depletion and Amortization
    (84 )     (81 )     (85 )
Taxes other than Income
    (18 )     (15 )     (6 )
 
   
     
     
 
Operating Loss
    (139 )     (159 )     (44 )
Other Income and (Deductions)
    89       73       (14 )
Income Taxes
                       
   
Benefit
    19       30       20  
   
Section 29 Tax Credits
    230       238       153  
 
   
     
     
 
 
    249       268       173  
 
   
     
     
 
Net Income
  $ 199     $ 182     $ 115  
 
   
     
     
 

Factors impacting income: Energy Services earnings increased $17 million in 2003 and $67 million in 2002, compared to the prior year. As subsequently discussed, these results primarily reflect increases in synfuel production, varying levels of Section 29 tax credits, a one-time contract gain and a write-off of an uncollectable account.

Operating revenues increased $284 million in 2003 and $198 million in 2002 reflecting higher synfuel production due to a greater number of operating synfuel plants. All nine of our synfuel plants were operational throughout 2003, whereas only five were operational throughout 2002 and only two in 2001. As discussed in Note 13, the growth in synfuel revenues was tempered by our decision to reduce synfuel production by approximately one-half in June 2003. Also impacting the 2003 comparison was reduced generation revenue due to the settlement of a tolling contract at one of our generating facilities.

                                               
(Dollars in Millions)   2003           2002   2001
         
         
 
Coal-Based Fuels Statistics
                                       
 
Synfuel Plants:
                                       
   
Operational at End of Year
            9               9       5  
   
Tax Credits Generated (1)
  $         227.7     $         180.2     $ 64.1  
 
Coke Battery Plants:
                                       
   
Operational at End of Year
            3               3       3  
   
Tax Credits Generated (1)
  $         2.5     $         57.4     $ 88.6  


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

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Operation and maintenance expense increased $258 million in 2003 and $308 million in 2002, reflecting costs associated with the higher levels of synfuel production. Operating expenses associated with synfuel projects exceed operating revenues and therefore generate operating losses, which are more than offset by the resulting Section 29 tax credits. Operation and maintenance expense in 2003 also includes a $10 million net of tax write-off for an uncollectable receivable associated with a large customer bankruptcy. Partially offsetting these increases was a one-time $19 million net of tax gain from the settlement of the tolling contract.

Other income and deductions increased $16 million in 2003 and $87 million in 2002. The increases reflect our minority partners’ share of operating losses associated with synfuel operations. The sale of interests in our synfuel facilities during 2002 and 2003 resulted in our minority partners being allocated a larger percentage of such losses.

Income tax benefits decreased $19 million in 2003 and increased $95 million in 2002. Income tax variations reflect changes in taxable earnings and the level of Section 29 tax credits from our synfuel and coke battery facilities. Tax credits from our synfuel operations increased in each of the last two years due to higher synfuel production. Tax credits from our coke battery production reflect the expiration of such credits at two of our three plants in 2002. Additionally, tax credits were impacted by our interest in one of the coke battery projects being reduced from 95% to 5% in 2002, consistent with the original purchase and sale agreement.

Outlook - A significant portion of Energy Services’ earnings consist of Section 29 tax credits. Synfuel-related tax credits expire in 2007. Tax credits for two of our three coke batteries expired at the end of 2002, and the third expires in 2007. We are aggressively pursuing opportunities to sell interests in all of our synfuel plants in 2004. The level of tax credits generated in future periods will be affected by the timing and number of synfuel projects sold. When we sell an interest in a synfuel facility, we recognize the gain from such sale under the installment method of accounting. Gain recognition is dependent on the synfuel production qualifying for Section 29 tax credits. In substance, we are receiving installment gains and reduced operating losses in exchange for tax credits. Sales of interests in synfuel projects allow us to accelerate cash flow while maintaining a stable income base.

There is a bill currently before the United States Congress that includes provisions extending or reinstating tax credits for various types of energy facilities and processes, including coke batteries, Antrim shale gas, coal bed methane, refined coal and landfill gas. We are unable to predict the outcome of the legislative process.

Energy Services will continue leveraging its extensive energy-related operating experience and project management capability to develop and grow the on-site energy business. We continue to explore growth opportunities that will not require significant initial capital investment. We are currently negotiating an on-site energy business arrangement with a major manufacturer in the Midwest.

Power prices over the past few years have been low due, in part, to the current excess capacity in the generation industry. Additionally, the generation tolling agreement that was settled in 2003 was at above market rates. As a result of these factors, we expect lower revenues and earnings from our merchant generation business in 2004.

Energy Marketing & Trading

Energy Marketing & Trading consists of the electric and gas marketing and trading operations of DTE Energy Trading and CoEnergy. DTE Energy Trading focuses on physical power marketing and

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

Factors impacting income: Energy Marketing & Trading’s earnings increased $20 million in 2003, of which $18 million was attributable to DTE Energy Trading and $2 million to CoEnergy. Earnings for 2002 decreased $19 million, consisting of a $6 million improvement at DTE Energy Trading, which was more than offset by a $25 million reduction at CoEnergy.

DTE Energy Trading’s earnings improvement in 2003 and 2002 was due mainly to margins associated with short-term physical trading and origination activities. The improvement was partially offset by reduced proprietary trading profits. Proprietary trading represents derivative activity transacted with the intent of capturing profits on forward price movements.

                             
(Dollars in Millions)   2003   2002   2001
       
 
 
DTE Energy Trading
                       
 
Margins – gains (losses)
                       
   
Realized (1)
  $ 82     $ 38     $ 33  
   
Unrealized (2)
    (9 )     13       (6 )
 
   
     
     
 
 
    73       51       27  
 
Operating and other costs
    (28 )     (29 )     (14 )
 
Income taxes
    (13 )     (8 )     (5 )
 
   
     
     
 
 
Net income
  $ 32     $ 14     $ 8  
 
   
     
     
 
CoEnergy
                       
 
Margins – gains (losses)
                       
   
Realized (1)
  $ 168     $ 32     $ (6 )
   
Unrealized (2)
    (135 )     (62 )     108  
   
Unrealized-gas in inventory (3)
          74       (28 )
 
   
     
     
 
 
    33       44       74  
 
Operating and other costs
    (13 )     (27 )     (19 )
 
Income taxes
    (7 )     (6 )     (19 )
 
   
     
     
 
 
Net income
  $ 13     $ 11     $ 36  
 
   
     
     
 
Total Energy Marketing & Trading Net Income
  $ 45     $ 25     $ 44  
 
   
     
     
 

1)   Realized margins include the settlement of all derivative and non-derivative contracts, as well as the amortization of deferred assets and liabilities.
 
2)   Unrealized margins include mark-to-market gains and losses on derivative contracts, net of gains and losses reclassified to realized. See “Fair Value of Contracts” section that follows.
 
3)   Unrealized – gas in inventory margins represent gains and losses associated with fair value accounting in 2002 and 2001. CoEnergy changed its method of accounting for inventory in January 2003 (Note 2).

CoEnergy’s earnings in 2003 and 2002 were driven by varying levels of operating costs and margins. Operating costs reflect the scale-back of certain retail gas marketing operations in 2002 as well as lower allocations for corporate support services in 2003.

Variations in margins reflect: 1) the settling or monetizing of certain in-the-money derivative contracts in 2003, 2) a change in the method of accounting for our gas in inventory in January 2003, and 3) volatility related to the accounting for our production-related gas supply contracts in 2001.

We monetized certain in-the-money derivative contracts in 2003 while simultaneously entering into replacement at-the-market contracts with various counterparties. The monetizations were completed in conjunction with implementing a series of initiatives to improve cash flow as well as our ability to fully

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utilize Section 29 tax credits (Note 13). The monetizations had the impact of reducing unrealized gains and increasing realized gains by approximately $136 million, with no significant impact on earnings.

As previously discussed, our derivative financial instruments are accounted for under the mark to market method, including those derivatives that hedge our price risk exposure associated with gas in inventory. Through December 2002, our physical gas in inventory was marked to the current spot price under fair value accounting rules. Accordingly, mark to market accounting for derivatives, coupled with fair value accounting for gas in inventory, minimized earnings mismatches. To comply with new accounting requirements resulting from the rescission of Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” we changed to the average cost method for our gas inventories, effective January 2003 (Note 2). As a result, CoEnergy experienced earnings volatility as it recorded unrealized gains in 2002 and unrealized losses in 2001 from fair valuing its inventory, whereas no such gains or losses were recorded in 2003.

The comparability of CoEnergy’s results was also affected by using different market prices for fair valuing its derivatives and fair valuing its gas in inventory, before the accounting change. Derivatives are marked to market against the forward curve, whereas gas in inventory was marked to the current spot price. The difference in accounting for derivatives 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 the forward market. Gas in storage in December 2002 was priced at a spot market rate of $5.10 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.

CoEnergy receives gas produced from DTE Energy’s Gas Production operations, which is used to meet its commitments under long-term contracts with cogeneration customers. The gas produced does not qualify for mark-to-market accounting. CoEnergy 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, CoEnergy entered into hedge transactions that substantially mitigate the earnings volatility related to the gas contracts with power generation customers.

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

Significant portions of the Energy Marketing & Trading portfolio are economically hedged, and include financial instruments, gas inventory, as well as owned and contracted natural gas pipelines and storage assets. These financial instruments are deemed derivatives whereas the gas inventory, pipelines and storage assets are not considered derivatives for accounting purposes. As a result, Energy Marketing & Trading will experience earnings volatility as derivatives are marked to market without revaluing the underlying non-derivative contracts and assets.

A significant portion of the earnings volatility in this segment is associated with the natural gas storage cycle, which runs from June to March. Injections of gas into inventory takes place in the summer and gas is withdrawn in the winter. DTE Energy’s policy is to hedge the price risk of all purchases for storage with sales in the “over the counter” and futures markets, eliminating the price risk for the storage business. As previously discussed, current accounting rules do allow for the marking to market of forward sales, but do not allow for the marking to market of the related gas inventory. This results in gains and losses that are recognized in different interim periods, but even out by the end of the storage cycle.

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In February 2004, we terminated a long-term gas exchange agreement and modified our future purchase commitments under a related transportation agreement with an interstate pipeline company, effective March 31, 2004. The agreements were at rates that were not reflective of current market conditions and had been fair valued under generally accepted accounting principles. In 2002, the fair value of the transportation agreement was frozen when it no longer met the definition of a derivative as a result of FERC Order 637. The fair value amounts were being amortized to income over the life of the related agreements, representing a net liability of approximately $75 million as of December 31, 2003. We are currently negotiating new agreements with the interstate pipeline company. We will record an appropriate adjustment to the liability after all related agreements have been finalized.

Non-regulated - Other

Our other non-regulated businesses are comprised of our Coal Services and Biomass units. Coal Services provides fuel, transportation and equipment management services. We specialize in minimizing energy production costs and maximizing reliability of supply for energy-intensive customers. Additionally, we participate in coal trading and coal-to-power tolling transactions, as well as sales of excess emissions credits. Coal Services has formed a subsidiary, DTE PepTec Inc., that uses proprietary technology to produce high quality coal products from fine coal slurries that are typically discarded from coal mining operations. 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 declined $9 million in 2003 and increased $1 million in 2002. The 2003 decline reflects reduced marketing and tolling income as well as an increase in operating costs associated with ramping up the DTE PepTec business. Our first waste coal facility in Ohio became operational in late-2003.

                           
(Dollars in Millions)   2003   2002   2001
   
 
 
Coal Services
                       
 
Tons of coal shipped (in millions)
    32.0       28.5       23.5  
Biomass
                       
 
Gas Produced (in Bcf)
    26.8       27.5       24.2  
 
Tax Credits Generated (1)
  $ 10.5     $ 12.9     $ 11.9  

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

Outlook – We expect to continue to grow our Coal Services and Biomass units. We believe a substantial market exists for the use of DTE PepTec Inc. technology and plan to aggressively pursue expansion opportunities. We expect to open 3 to 5 operating sites in 2004. Biomass currently has 31 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 of Detroit Edison. Power Distribution distributes electricity generated and purchased by Energy Resources and alternative electric suppliers to Detroit Edison’s 2.1 million customers.

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(in Millions)   2003   2002   2001
   
 
 
Operating Revenues
  $ 1,247     $ 1,343     $ 1,256  
Fuel and Purchased Power
    (19 )     (26 )     (10 )
Operation and Maintenance
    (724 )     (649 )     (511 )
Depreciation, Depletion and Amortization
    (249 )     (246 )     (246 )
Taxes Other Than Income
    (100 )     (117 )     (120 )
Merger and Restructuring Charges
                (114 )
 
   
     
     
 
Operating Income
    155       305       255  
Other Income and (Deductions)
    (128 )     (136 )     (132 )
Income Tax Provision
    (10 )     (58 )     (26 )
 
   
     
     
 
Net Income
  $ 17     $ 111     $ 97  
 
   
     
     
 
Operating Income as a Percent of Operating Revenues
    12 %     23 %     20 %

Factors impacting income: Power Distribution earnings decreased $94 million during 2003 and increased $14 million in 2002, compared to the prior year. As subsequently discussed, these results primarily reflect changes in operating revenues and increased operation and maintenance expenses. Merger and restructuring charges associated with the 2001 MCN Energy acquisition also impacted the comparability of results.

Operating revenues declined $96 million in 2003 primarily due to mild summer weather and the impact of slower economic conditions affecting commercial and industrial sales. Operating revenues increased $87 million in 2002 reflecting higher residential sales attributable to greater cooling demand.

Below are volumes associated with the regulated power distribution business:

                         
(in Thousands of MWh)   2003   2002   2001
   
 
 
Electric Deliveries
                       
Residential
    15,074       15,958       14,503  
Commercial
    15,942       18,395       18,777  
Industrial
    12,254       13,590       14,430  
Wholesale
    2,241       2,249       2,159  
 
   
     
     
 
 
    45,511       50,192       49,869  
Electric Choice
    7,281       3,510       1,268  
 
   
     
     
 
Total Electric Deliveries
    52,792       53,702       51,137  
 
   
     
     
 

Operation and maintenance expense increased $75 million in 2003 and $138 million in 2002 reflecting higher costs associated with weather-related power outages, employee benefits, uncollectable accounts receivables, allocations for corporate support services, and customer service initiatives to improve customer satisfaction. Restoration costs associated with three catastrophic storms in 2003 and the August 2003 blackout totaled $76 million. We experienced an April ice storm, resulting in more than 400,000 customers losing power, a July windstorm, affecting over 190,000 customers, a November windstorm, affecting 160,000 customers, and the August blackout, affecting all 2.1 million of our customers. This compares with $49 million in costs in 2002 related to two catastrophic storms, as well as heat-related maintenance expenses due to prolonged periods of above normal summer temperatures and the related stress placed on our distribution system.

Employee pension and health care benefit costs increased $26 million in 2003 and $12 million in 2002 due to recent financial market performance, lower discount rates and increased health care trend rates. Uncollectable accounts expense increased $17 million in 2003 and decreased $1 million in 2002 reflecting higher past due amounts attributable to current economic conditions. Additionally, results for

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2003 also reflect costs associated with customer service initiatives and a net of tax loss of $14 million on the sale of our non-strategic steam heating business (Note 3). Partially offsetting these increases were benefits from the DTE Operating System, as previously discussed, and lower employee incentive costs.

Taxes other than income decreased $17 million in 2003 and $3 million in 2002. The decline in 2003 is due to lower Michigan Single Business Taxes, reflecting reduced taxable earnings, and lower property taxes.

Outlook – Operating results are expected to vary as a result of external factors such as weather, changes in economic conditions and the severity and frequency of storms. Economic conditions and prior billing issues have resulted in an increase in past due receivables. We believe our allowance for doubtful accounts is based on reasonable estimates. However, failure to make continued progress in collecting our past due receivables would unfavorably affect operating results. As a result, we have organized a focused effort to address the credit and collection issues.

We experienced numerous catastrophic storms over the past few years. The effect of the storms on annual earnings ranged up to $70 million and was partially offset by storm insurance. We were unable to obtain storm insurance at economical rates in 2004 and as a result, we do not anticipate having insurance coverage at levels that would significantly offset unplanned expenses from ice storms, tornadoes, or high winds that damage our distribution infrastructure.

As previously mentioned, Detroit Edison filed a rate case in June 2003 to address future operating costs and other issues. Detroit Edison received an interim order in this rate case in February 2004. See Note 4 – Regulatory Matters.

Non-Regulated

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

Factors impacting income: Non-regulated losses decreased $1 million in 2003 and increased $6 million in 2002. The slight improvement in 2003 is due primarily to increased sales and cost reductions.

Outlook – Although installed capacity for DTE Energy Technologies is increasing, the growth in this business is below our expectations. Accordingly, we have taken actions to reduce our expenses and streamline our operations, including exiting from some non-strategic business lines and activities. DTE Energy Technologies expects to continue participating in the emerging distributed generation market.

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ENERGY GAS

Gas Distribution

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

                         
(in Millions)   2003   2002   2001*
   
 
 
Operating Revenues
  $ 1,498     $ 1,369     $ 615  
Fuel and Purchased Power
    (909 )     (774 )     (304 )
 
   
     
     
 
Gross Margins
    589       595       311  
Operation and Maintenance
    (371 )     (297 )     (194 )
Depreciation, Depletion and Amortization
    (101 )     (104 )     (61 )
Taxes Other Than Income
    (52 )     (51 )     (24 )
Merger and Restructuring Charges
                (81 )
 
   
     
     
 
Operating Income (Loss)
    65       143       (49 )
Other Income and (Deductions)
    (36 )     (41 )     (38 )
Income Tax Benefit (Provision)
          (36 )     49  
 
   
     
     
 
Net Income (Loss)
  $ 29     $ 66     $ (38 )
 
   
     
     
 
Operating Income as a Percent of Operating Revenues
    4 %     10 %     n/m %


* Reflects the operations of MichCon from the May 31, 2001 acquisition date.
n/m - not meaningful

Factors impacting income: Gas Distribution’s earnings declined $37 million in 2003 and increased $104 million in 2002, compared to the prior year. As subsequently discussed, results in 2003 primarily reflect a decline in gross margins and increased operation and maintenance expenses. The significant improvement in 2002 reflects a full year of operations of 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. Merger and restructuring charges associated with the merger also impacted the comparability. The pro-forma impact of the MCN Energy acquisition on DTE Energy is discussed in Note 3 – Acquisitions and Dispositions.

Gross margins declined $6 million in 2003 reflecting a $26.5 million reserve for the potential disallowance in gas costs pursuant to a March 2003 MPSC order in MichCon’s 2002 GCR plan case (Note 4). The impact of the reserve was significantly offset by increased sales due to colder winter weather in early 2003.

Operation and maintenance expense increased $74 million in 2003 reflecting higher costs associated with employee benefits, uncollectable accounts receivables, allocations for corporate support services, and customer service initiatives. Employee pension and health care benefit costs increased $47 million in 2003 and uncollectable accounts expense increased $17 million in 2003 reflecting economic conditions and higher gas prices. Partially offsetting these increases were benefits from the DTE Operating System, as previously discussed, and lower employee incentive costs.

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

Outlook – Operating results are expected to vary as a result of external factors such as regulatory proceedings, weather and changes in economic conditions. Higher gas prices, current economic conditions and prior billing issues have resulted in an increase in past due receivables. We believe our allowance for doubtful accounts is based on reasonable estimates. However, failure to make continued progress in collecting our past due receivables would unfavorably affect operating results. As previously discussed, we are focused on addressing the credit and collection issues.

The MPSC issued several orders that continue the gas Customer Choice program on a permanent basis. 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 2003, approximately 129,000 customers were participating in the gas Customer Choice program, compared with approximately 190,000 customers as of December 2002.

As a result of the continued increase in operating costs, MichCon filed a rate case in September 2003 to increase rates by $194 million annually to address future operating costs and other issues. See Note 4 – Regulatory Matters.

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Non-regulated

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

Factors impacting income: Earnings increased $3 million in 2003 and $15 million in 2002. The 2003 earnings improvement primarily reflects the gain from the sale of our 16% pipeline interest in the Portland Natural Gas Transmission System. The 2002 results reflect a full year of operations of the our non-regulated gas 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. In October 2003, we acquired an additional 15% interest in the Vector Pipeline, bringing our total ownership interest to 40%. The purchase of the additional interest in the Vector Pipeline complements our existing gas distribution and storage facilities in Michigan. Additionally, we expect to continue to invest in opportunities in the coal bed methane business to leverage our production, coal and low cost operating capabilities.

CORPORATE & OTHER

Corporate & Other includes the administrative and general expenses of various corporate support functions such as accounting, legal and information technology. As these functions essentially support the entire company, they are allocated to the various segments based on services utilized and therefore can vary from year to year. Additionally, Corporate & Other holds certain non-regulated debt and investments, including assets held for sale and in emerging energy technologies.

Factors impacting income: Corporate & Other’s losses were basically flat in 2003 and 2002. The 2003 results were affected by a $15 million cash contribution to the DTE Energy Foundation that was funded with proceeds received from the sale of ITC (Note 3). The impact of the contribution was offset by lower interest costs. Results in 2002 reflect higher interest expense resulting from increased debt and a full year’s 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 the amortization of goodwill associated with the MCN Energy acquisition.

DISCONTINUED OPERATIONS - ITC

In December 2002, we entered into a definitive agreement with an affiliate of Kohlberg Kravis Roberts & Co. and Trimaran Capital Partners, LLC to sell ITC for $610 million in cash. The sale closed on February 28, 2003 following approval of the transaction by the FERC and resolution of all other contingencies and generated a net of tax gain of $63 million.

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

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financial results of the transmission business prior to June 1, 2001 are included as part of the Power Distribution segment.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES

As required by generally accepted accounting principles, on January 1, 2003, we adopted new accounting rules for asset retirement obligations and energy trading activities. The cumulative effect of adopting these new accounting rules reduced 2003 earnings by $27 million. Additionally, on January 1, 2001 we adopted a new accounting rule for derivative instruments and the cumulative effect of adopting this new rule increased 2001 earnings by $3 million. See Note 2 for further discussion.

CAPITAL RESOURCES AND LIQUIDITY

                             
(in Millions)   2003   2002   2001
   
 
 
Cash and Cash Equivalents
                       
Cash Flow From (Used For)
                       
 
Operating activities:
                       
   
Net income
  $ 521     $ 632     $ 332  
   
Depreciation, depletion and amortization
    691       759       795  
   
Merger and restructuring charges
                215  
   
Deferred income taxes
    (220 )     (208 )     (7 )
   
Gain on sale of assets, net
    (129 )            
   
Working capital and other
    87       (187 )     (524 )
 
   
     
     
 
 
    950       996       811  
 
   
     
     
 
 
Investing activities
                       
   
Plant and equipment expenditures – regulated
    (679 )     (794 )     (776 )
   
Plant and equipment expenditures – non-regulated
    (72 )     (190 )     (320 )
   
Proceeds for sale of ITC, synfuels and other assets
    758       41       216  
   
Acquisition of MCN Energy
                (1,212 )
   
Restricted cash and other investments
    3       (172 )     (194 )
 
   
     
     
 
 
    10       (1,115 )     (2,286 )
 
   
     
     
 
 
Financing activities
                       
   
Issuance of long-term debt and common stock (1)
    571       1,223       4,254  
   
Redemption of long-term debt
    (1,208 )     (613 )     (1,423 )
   
Short-term borrowings, net
    (44 )     (267 )     (282 )
   
Repurchase of common stock
    (3 )     (9 )     (438 )
   
Other, primarily dividends on common stock
    (355 )     (350 )     (432 )
 
   
     
     
 
 
    (1,039 )     (16 )     1,679  
 
   
     
     
 
Net Increase (Decrease) in Cash and Cash Equivalents
  $ (79 )   $ (135 )   $ 204  
 
   
     
     
 


(1)  2001 includes $1.75 billion of securitization bonds and $1.35 billion of debt issued to acquire MCN Energy.

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Operating Activities

We use cash derived from operating activities to maintain and expand our electric and gas utilities and to grow our non-regulated businesses. In addition, we use cash from operations to retire long-term debt and pay dividends. A majority of the company’s operating cash flow is provided by the two regulated utilities, which are significantly influenced by factors such as weather, customer choice sales loss, regulatory outcomes, economic conditions and operating costs. This part of our business has recently been under considerable financial pressure given that we have not had a rate increase in over 10 years, coupled with higher operating costs and increased regulatory deferrals. While these regulatory deferrals at Detroit Edison have served to mitigate some of the earnings pressures as a result of these influencing factors, the corresponding cash flows have been deferred. Our non-regulated businesses also provide sources of cash flow to the enterprise and reflect a range of operating profiles. These vary from our synthetic fuels business, which will provide substantial cash flow over the next 5 years, to new start-ups, such as our coal bed methane or waste coal recovery businesses, which are growing and will require modest investments beyond their cash generation capabilities.

During 2003, our consolidated net cash from operating activities was $950 million, reflecting a decrease of $46 million from 2002 levels. The decrease in 2003 operating cash flow was attributable to declines in regulated net income, after adjusting for noncash items (depreciation, depletion, amortization, deferred taxes and gains), reflecting the impacts of weather, lost electric Customer Choice margins and higher operating costs. Partially offsetting these declines were lower working capital and other requirements reflecting a company-wide initiative focused on improving cash flow. The initiative included better inventory management, improved accounts receivable collections, the selling of interests in our synfuel facilities, the monetization of in-the-money derivatives and replacing margin deposits with letters of credit. The improvement in working capital was achieved despite a $222 million contribution to our pension plan.

Operating cash flow in 2002 of $996 million was $185 million higher than 2001 levels, largely attributable to the full year’s impact of the MCN Energy acquisition, which was completed in May 2001. Lower working capital and other requirements were partially offset by a decline in net income, after adjusting for noncash items. Working capital reflects the seasonal requirements of the gas business where cash is used in the second half of the year to finance increases in gas inventories and customer accounts receivable. Additionally, past due accounts receivable balances increased due to higher gas prices, economic conditions and conversion issues with the new combined utility billing system.

Outlook — We expect cash flow from operations to increase over the long-term, but to remain relatively the same in 2004 as 2003. Cash flow improvements from utility rate increases and synfuel sales will be offset by higher cash requirements primarily within our energy marketing and trading business.

Operating cash flow from our utilities is expected to increase in 2004, but will be affected by the level of sales migration under the electric Customer Choice program and the ability of the MPSC within the regulatory processes to put in place a Choice program that has sound economic fundamentals. In addition, the Choice program’s impact will also be determined by the success of the company in addressing certain structural flaws within the legislative process. While the Choice program’s shortfalls may be structurally addressed within these two processes, the use of regulatory deferrals by the MPSC might affect the cash benefits of addressing the existing choice program being realized in 2004.

Another factor affecting regulated cash flows is the degree and timing of rate relief within the electric and gas rate cases. Based on the interim order issued by the MPSC on February 20, 2004, approximately $71 million of additional revenues should be realized within the 2004 calendar year. Due to the structure of the interim rate order, we will not realize the full benefits of interim and final rate relief until 2006 when customer rate caps expire.

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

Cash flow from our synfuel business, including proceeds from the sale of interests in related facilities, should shift from a net cash loss of $195 million in 2003 to positive cash flow of $135 million in 2004 and $355 million in 2005. The expected improvements are driven by the sale of interests in synfuel facilities, increased production and a higher cash value per credit. We will also benefit from lower taxes paid as we use our tax credit carry forward position.

Our other operating non-regulated businesses will provide minimal cash from operations in 2004 and grow modestly in future years. Remaining start-up businesses such as coal bed methane, waste coal recovery and distributed generation will have cash losses over the next couple of years while they are being further developed. Certain of the cash initiatives previously discussed, resulted in accelerating the receipt of cash in 2003 which will have the impact of lowering cash flow in 2004.

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Investing Activities

Cash inflows associated with investing activities are partially generated from the sale of assets and utilized to invest in our utilities and non-regulated businesses. In any given year, we will look to harvest cash from under performing or non-strategic assets. Capital spending within the utility business is primarily to maintain our generation and distribution infrastructure and comply with environmental regulations. We have incurred higher utility capital expenditures over the past several years to comply with new air quality standards. Capital spending within our non-regulated businesses should be viewed in two categories. For businesses currently operating, expenditures are for ongoing maintenance and some expansion. The balance of non-regulated spending is for growth, which we manage very carefully. We look to make investments that meet strict criteria in terms of strategy, management skills, risks and returns. All new investments are analyzed for their rates of return and cash payback on a risk adjusted basis. We have been disciplined in how we deploy capital and will not make investments unless they meet our criteria. For new business lines, we invest tentatively based on research and analysis. Based on a limited investment, we evaluate results and either expand or exit the business based on those results. In any given year, the amount of growth capital will be determined by the underlying cash flows of the company with a clear understanding of any potential impact on our credit ratings.

During 2003, we had net cash from investing activities of $10 million compared to cash used of $1.1 billion in 2002. The significant improvement was due to proceeds totaling $758 million from the sale of ITC, interests in three synfuel projects and non-strategic assets that were acquired as part of the MCN Energy acquisition. Additionally, regulated and non-regulated plant expenditures decreased significantly in 2003. Lower regulated expenditures of $115 million were associated with air quality regulations that require reductions in nitrogen oxide levels. Non-regulated expenditures declined by $118 million and the comparison reflects costs incurred in 2002 associated with four synfuel facilities that became fully operational.

During 2002, the investing activity cash flow comparison improved by $1.2 billion and was impacted by the cash portion of the MCN Energy acquisition in 2001. The 2002 improvement was also due to lower non-regulated capital expenditures, partially offset by reduced proceeds from the sale of assets.

Outlook — Our strategic direction anticipates base level capital investments and expenditures for existing businesses in 2004 ranging from $750 million to $1.0 billion. Our utilities plan to spend higher amounts of capital, but actual spending levels will be matched to available cash flows. Until our two rate cases are resolved, we will hold utility capital spending at 2003 levels.

Capital spending for general corporate purposes will increase in 2004 primarily as a result of our DTE2 initiative, as subsequently discussed. This project will require capital investments in 2004 and 2005 for new computer systems. Non-regulated capital spending will approximate $80 million to $100 million annually for the next several years. Capital spending for growth of existing or new businesses will be constrained in 2004 due to the pending rate cases, electric Customer Choice issues and rating agency concerns about these businesses. Accordingly, we are seeking to grow the business by making small investments in areas like coal bed methane and waste coal recovery. Utilizing this approach allows us to determine quarterly our spending levels, which will be based on capital and credit constraints.

Longer term, once the electric Choice issues are resolved and utility rate increases are fully phased in, we anticipate capital availability to return to historical levels. After the utilities return to financial health, we will continue to pursue opportunities to grow our businesses in a disciplined fashion. If we can find opportunities that meet our strategy and financial and risk criteria we will look to make investments. If we have the available cash flow and can’t find value creating investments, we intend to return that capital to shareholders and pay down debt.

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

Financing Activities

We continually evaluate our leverage targets to ensure that they are consistent with our objective to have a strong investment grade debt rating. Since our merger with MCN Energy in 2001, we have been successful in reducing our leverage. Given the present environment in our industry, the increase in regulatory assets, and the nature of the electric Customer Choice program and other uncertainties, we may need to further lower our leverage in the future.

Our strategy is to have a targeted debt portfolio blend as to fixed and variable interest rates and maturity. We have completed a number of refinancings over the past several years with the effect of extending the average maturity of our long-term debt. The extension of the average maturity was accomplished at interest rates which have lowered our debt costs. Variable rate debt is principally in the form of outstanding commercial paper. Additionally, we have interest rate derivatives that effectively converts fixed rate debt to variable rate debt. Variable rate debt represents approximately 10% of our total debt outstanding as of December 31, 2003.

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Our net cash related to financing activities decreased $1.0 billion in 2003 and decreased $1.7 billion in 2002. The 2003 change was due to higher redemptions of long-term debt and lower proceeds from issuances of new debt and common stock. 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. 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 between 2002 and 2001. In 2001, proceeds from the issuance of securitization bonds and other Detroit Edison and MichCon debt were used to repay higher priced debt and repurchase our common stock. Details of 2003 financing activities follows (Note 9):

    MichCon issued $200 million of 5.7% senior notes due in March 2033. The proceeds were used for debt redemption and general corporate purposes.
 
    DTE Energy issued $400 million of 6-3/8% senior notes due in April 2033. In conjunction with this issuance, DTE Energy exchanged $100 million principal amount of existing debt due April 2008. The proceeds were used for debt redemptions and general corporate purposes.
 
    DTE Energy redeemed $100 million principal amount of 6.17% Remarketed Notes due in 2038.
 
    Detroit Edison issued $49 million of 5.5% tax exempt bonds due in 2030. The proceeds were used to redeem $49 million of 6.55% tax-exempt bonds due 2024.

Outlook — Our goal is to maintain a healthy balance sheet. We intend on maintaining a high investment grade credit rating and maintaining leverage in the 50% to 55% range (excluding certain debt, principally securitization debt).

We expect to contribute $170 million of DTE Energy common stock to our pension plan in the first quarter of 2004. This contribution will modestly improve our leverage. Additionally, we expect to continue the practice of issuing new DTE Energy shares for our dividend reinvestment plan. We believe this is a cost-effective means of raising new equity.

Debt maturing in 2004 totals approximately $500 million and we called $100 million of Trust preferred- linked securities in late 2003. In addition, there are outstanding debt instruments that are likely to be economic to redeem and refund with new debt in 2004. The Company expects to continue to take advantage of low historical long-term interest rates and issue new securities with a longer life than the securities maturing or called.

As of December 31, 2003, DTE Energy, Detroit Edison and MichCon have effective shelf registrations with the SEC that allow for the issuance of up to an additional $1.3 billion of debt and $850 million of equity securities. We have authorization from the DTE Energy Board to repurchase approximately 9.5 million shares of our common stock. No shares have been repurchased under this authorization since early 2002. Future repurchases are not presently contemplated and will depend upon future market conditions and the Company’s financial condition.

In October 2003, DTE Energy, Detroit Edison and MichCon entered into separate revolving credit facilities with a syndicate of banks totaling $1.3 billion. These facilities support our use of letters of credit and the issuance of commercial paper. Borrowing available under these revolving credit facilities totaled $1.2 billion as of December 31, 2003. Our revolving credit facilities contain customary covenants, including the requirement to maintain a debt to total capitalization ratio of not more than .65 to 1, and an “earnings before interest, taxes, depreciation and amortization” (EBITDA) to interest ratio of no less than 2 to 1. As of December 31, 2003, our debt to total capitalization ratio as computed under the terms of the agreement was .50 to 1 and our EBITDA to interest ratio was 3.6 to 1. We anticipate having the need and the ability to renew these credit facilities prior to their expiration at fair and reasonable market rates as determined at the time of negotiation.

Additionally, Detroit Edison has a $200 million short-term financing agreement secured by customer accounts receivable of which $100 million was outstanding as of December 31, 2003. The agreement contains certain covenants related to the delinquency of accounts receivable. Detroit Edison is currently in compliance with these covenants.

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

Contractual Obligations

The following table details our contractual obligations for debt redemptions, leases, purchase obligations and other long-term obligations as of December 31, 2003.

                                           
              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
  $ 6,006     $ 382     $ 1,054     $ 564     $ 4,006  
 
Securitization bonds
    1,585       89       312       252       932  
 
Equity-linked securities
    185       7       178              
 
Trust preferred-linked securities
    289       103                   186  
 
Capital lease obligations
    109       12       36       22       39  
Operating leases
    757       72       182       92       411  
Electric, gas, fuel, transportation & storage purchase obligations
    10,228       4,269       3,292       1,219       1,448  
Other long-term obligations
    802       203       289       161       149  
 
   
     
     
     
     
 
Total Obligations
  $ 19,961     $ 5,137     $ 5,343     $ 2,310     $ 7,171  
 
   
     
     
     
     
 

Credit Ratings

The uncertainty in Michigan’s regulatory environment and the impact of the electric Customer Choice program has resulted in various independent credit rating agencies reviewing our credit rating. An unfavorable change in our rating could restrict our ability to access capital markets at attractive rates and increase our borrowing costs. We have issued guarantees for the benefit of various non-regulated subsidiaries. In the event that our credit rating is downgraded two levels and would therefore be below investment grade, certain of these guarantees would require us to post cash or letters of credit valued at approximately $290 million at December 31, 2003. Additionally, our trading business could be required to cease operations and our access to the short-term commercial paper market would be restricted or eliminated. While we currently do not anticipate such a downgrade, we cannot predict the outcome of current or future reviews. The following table shows our credit rating as determined by three nationally respected credit rating agencies. All ratings are considered investment grade and affect the value of the related securities.

                 
        Credit Rating Agency
       
            Moody's    
        Standard &   Investors    
        Poors   Service   Fitch Ratings
       
 
 
DTE Energy   Senior Unsecured Debt   BBB *   Baa2 *   BBB
Detroit Edison   Senior Secured Debt   A- *   A3 *   A-
MichCon   Senior Secured Debt   BBB+ *   A2 **   A

    * Currently on negative outlook
 
    ** Currently being reviewed for possible downgrade

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

         
(in millions)        
Regulated Entity        

       
Detroit Edison (1)
  $ (18 )
MichCon
    (40 )
 
   
 
Total
  $ (58 )
 
   
 


(1)   Excludes securitized regulatory assets

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

Risk Management and Trading Activities

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

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

  published exchange traded market data
 
  prices from external sources
 
  price based on valuation models

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

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Section 29 Tax Credits

We have generated Section 29 tax credits from our synfuel, coke battery, biomass and gas production operations. All of our synthetic fuel facilities have received favorable private letter rulings from the IRS with respect to their operations. All Section 29 tax credits taken after 1997 are subject to audit 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. Four of our synfuel facilities are under audit by the IRS for 2001 and are expected to be completed in 2004. Our portion of tax credits generated was $241 million in 2003 as compared to $250 million in 2002 and $165 million in 2001. 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 (Note 1). 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. Based on our 2003 goodwill impairment test, we determined that no impairment existed. As of December 31, 2003, our goodwill totaled $2.1 billion.

Pension and Postretirement Costs

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

We had pension costs for qualified pension plans of $47 million in 2003, pension income of $9 million in 2002 and pension costs of $159 million in 2001. Postretirement benefits costs for all plans was $118 million in 2003, $70 million in 2002 and $104 million in 2001. Pension and postretirement benefits cost 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, 2003. In developing our expected long-term rate of return assumption, we evaluated input from our consultants, including their review of asset class risk and return expectations as well as inflation assumptions. Projected returns 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 utilizing active investment management of 65% in equity markets, 28% in fixed income markets, and 7% invested in other assets. Because of market volatility, we periodically review our asset allocation and rebalance our portfolio when considered appropriate. Given market conditions we believe that 9.0% is a reasonable long-term rate of return on our plan assets. We will continue to evaluate our actuarial assumptions, including our expected rate of return, at least annually.

We base our determination of the expected return on qualified plan assets on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes changes in fair value in a systematic manner over a three-year period. Because of this method, the future value of assets will be impacted as previously deferred gains or losses are recorded. We have unrecognized net losses due to the recent unfavorable performance of the financial markets. As of December 31, 2003, we had $7 million of cumulative losses that remain to be recognized in the calculation of the market-related value of assets.

The discount rate that we utilize for determining future pension and postretirement benefit obligations is based on a review of bonds that receive one of the two highest ratings given by a recognized rating

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agency. The discount rate determined on this basis has decreased from 6.75% at December 31, 2002 to 6.25% at December 31, 2003. Due to recent financial market performance, lower discount rates and increased health care trend rates, we estimate that our 2004 pension costs will approximate $100 million compared to $54 million in 2003 and our 2004 postretirement benefit costs will approximate $135 million compared to $118 million in 2003. We have made modifications to the pension and postretirement benefit plans to mitigate the earnings impact of higher costs. Future actual pension and postretirement benefit costs will depend on future investment performance, changes in future discount rates and various other factors related to plan design.

Lowering the expected long-term rate of return on our plan assets by 1.0% would have increased our 2003 qualified pension costs by approximately $22 million. Lowering the discount rate and the salary increase assumptions by 1.0% would have increased our pension costs for 2003 by approximately $11 million. Lowering the health care cost trend assumptions by 1.0% would have decreased our postretirement benefit service and interest costs for 2003 by approximately $16 million.

The market value of our pension and postretirement benefit plan assets has been affected by declines in the financial markets in recent years. The value of our plan assets decreased from $2.8 billion at December 31, 2001, to $2.4 billion at December 31, 2002. The value at December 31, 2003 increased to $2.9 billion. The investment performance returns and declining discount rates 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. As of December 31, 2003, we recognized a decrease in minimum pension liability of $75 million, a decrease in intangible assets of $13 million and a decrease in other comprehensive loss (a component of shareholders’ equity) of $647 million ($421 million after tax). The additional minimum pension liability and related accounting entries will be reversed on the balance sheet in future periods if the fair value of plan assets exceeds the accumulated pension benefit obligations. The recording of the minimum pension liability does not affect net income or cash flow.

Pension and postretirement costs and pension cash funding requirements 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 2003. We anticipate making an approximate $170 million contribution to our pension plan in the form of DTE Energy common stock in the first quarter of 2004. We also contributed $33 million to the postretirement plans in 2002. We did not contribute to the postretirement plans in 2003, and made a $40 million contribution in January 2004.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act was signed into law. This Act provides for a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the benefit established by law. We have not quantified the impact of the Act, if any, on our plan.

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 utility billing system in late 2001, we encountered billing issues as is typical with large-scale system implementations. While we have resolved the primary billing issues, we may encounter difficulty in collecting past due receivables. Higher customer bills due to increased gas prices, the lack of adequate levels of assistance for low-income customers and economic conditions have also contributed to the increase in past due receivables. As a result of these factors, our allowance for doubtful accounts increased in 2002 and 2003. We believe the allowance for doubtful accounts is based on reasonable estimates. However, failure to make continued progress in collecting our past due receivables would unfavorably affect operating results and cash flow.

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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 ozone transport regulations and final new air quality standards relating to ozone and particulate air pollution will continue to impact us. Detroit Edison has spent approximately $560 million through December 2003 and estimates that it will spend approximately $40 million in 2004 and incur up to an additional $1.2 billion of future capital expenditures over the next five to eight years to satisfy both existing and proposed new control requirements. Recovery of costs to be incurred through December 2004 is included in our June 2003 electric rate case. In addition, we maintain the option to securitize these costs after the completion of our current regulatory proceedings.

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

DTE ENERGY OPERATING SYSTEM AND DTE2

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

In 2003, we began the implementation of DTE2, a company-wide initiative to improve existing processes and to implement new core information systems including, finance, human resources, supply chain and work management. We expect to incrementally spend approximately $150 million to $175 million over the next 3 to 4 years to implement these new processes and systems. We expect the benefits to outweigh this investment primarily from lower costs, faster business cycles, repeatable and optimized processes, enhanced internal controls, improvements in inventory management and reductions in system support costs.

NEW ACCOUNTING PRONOUNCEMENTS

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

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FAIR VALUE OF CONTRACTS

The following disclosures are voluntary and have been developed through efforts of the Committee of Chief Risk Officers, a working group of chief risk officers from companies active in both physical and financial energy trading and marketing. We believe the disclosures provide enhanced transparency of the activities and position of our Energy Trading & Marketing segment.

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 2003.

                                                   
                              Energy                
      Proprietary   Structured   Owned   Trading   Gas        
(in Millions)   Trading (1)   Contracts (2)   Assets (3)   Total   Production   Total
   
 
 
 
 
 
Energy Marketing & Trading Segment
                                               
 
MTM at December 31, 2002
  $ 15     $ 19     $ (50 )   $ (16 )   $ (79 )   $ (95 )
 
   
     
     
     
     
     
 
 
Reclassed to realized upon settlement
    (5 )     (15 )     14       (6 )     27       21  
 
Liquidation of in-the-money positions (4)
                (136 )     (136 )           (136 )
 
Changes in fair value
    11       12       (16 )     7             7  
 
Amortization of option premiums
    (9 )                 (9 )           (9 )
 
   
     
     
     
     
     
 
 
Amounts impacting unrealized income
    (3 )     (3 )     (138 )     (144 )     27       (117 )
 
Cumulative effect adjustment (5)
    (2 )     (1 )     17       14       -*       14  
 
Effective portion of change in fair value
          2             2       (28 )     (26 )
 
 
   
     
     
     
     
     
 
 
MTM at December 31, 2003
  $ 10     $ 17     $ (171 )   $ (144 )   $ (80 )   $ (224 )
 
   
     
     
     
     
     
 

(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)   In conjunction with our overall tax planning and cash initiatives, we monetized certain in-the-money contracts in 2003 while simultaneously entering into at-the-market contracts with various counterparties. This had the impact of optimizing taxable income and cash flow while having minimal impact on reported earnings.
 
(5)   Excludes the cumulative effect adjustment associated with the change in accounting for gas inventory (Note 2).

                                                         
                                    Energy           Total
    Proprietary   Structured   Owned           Trading   Gas   Assets
(in Millions)   Trading   Contracts   Assets   Eliminations   Total   Production   (Liabilities)
   
 
 
 
 
 
 
Current assets
  $ 91     $ 44     $ 98     $ (45 )   $ 188     $     $ 188  
Noncurrent assets
    13       27       57       (7 )     90             90  
 
   
     
     
     
     
     
     
 
Total MTM assets
    104       71       155       (52 )     278             278  
 
   
     
     
     
     
     
     
 
Current liabilities
    (79 )     (32 )     (219 )     44       (286 )     (42 )     (328 )
Noncurrent liabilities
    (15 )     (22 )     (107 )     8       (136 )     (38 )     (174 )
 
   
     
     
     
     
     
     
 
Total MTM liabilities
    (94 )     (54 )     (326 )     52       (422 )     (80 )     (502 )
 
   
     
     
     
     
     
     
 
Total MTM net assets (liabilities)
  $ 10     $ 17     $ (171 )   $     $ (144 )   $ (80 )   $ (224 )
 
   
     
     
     
     
     
     
 

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

We fully reserve all unrealized gains and losses related to periods beyond the liquid time frame. Our intent is to recognize MTM activity only when pricing data is obtained from active quotes and published indexes. The table below shows the maturity of the MTM positions of our energy contracts.

                                         
                                    Total
(in Millions)                           2007 and   Fair
Source of Fair Value   2004   2005   2006   Beyond   Value

 
 
 
 
 
Proprietary Trading
  $ 13     $ (3 )   $     $     $ 10  
Structured Contracts
    11       5             1       17  
Owned Assets
    (121 )     (39 )     (11 )           (171 )
 
   
     
     
     
     
 
Energy Marketing & Trading
    (97 )     (37 )     (11 )     1       (144 )
Gas Production
    (42 )     (30 )     (8 )           (80 )
 
   
     
     
     
     
 
Total
  $ (139 )   $ (67 )   $ (19 )   $ 1     $ (224 )
 
   
     
     
     
     
 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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

Foreign Currency Risk

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

Summary of Sensitivity Analysis

We performed a sensitivity analysis calculating the impact of changes in fair values utilizing applicable forward commodity rates or changes in interest rates if they occurred at December 31, 2003:

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

 
 
 
Gas Contracts
  $ (8 )   $ 9     Commodity contracts
Power Contracts
  $ (8 )   $ 8     Commodity contracts
Interest Rate Risk
  $ (303 )   $ 323     Long term debt
Foreign Currency Risk
  $ .2     $ (.2 )   Forward contracts

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Credit Risk

Bankruptcies

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

Energy Trading & CoEnergy Portfolio

We utilize both external and internally generated credit assessments when determining the credit quality of our trading counterparties. The following table displays the credit quality of our trading counterparties.

                             
        Credit Exposure                
        before Cash   Cash   Net Credit
(in Millions)   Collateral   Collateral   Exposure
   
 
 
Investment grade (1)
                       
   
A- and Greater
  $ 215     $ (22 )   $ 193  
   
BBB+ and BBB
    157               157  
   
BBB-
    3               3  
 
   
     
     
 
Total Investment Grade
    375       (22 )     353  
Non-investment grade (2)
    4       (2 )     2  
Internally Rated - investment grade (3)
    59       (3 )     56  
Internally Rated - non-investment grade (4)
    4               4  
 
   
     
     
 
 
Total
  $ 442     $ (27 )   $ 415  
 
   
     
     
 

(1)   This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s Investor Service (Moody’s) and BBB- assigned by Standard & Poor’s Rating Group (Standard & Poor’s). The five largest counterparty exposures combined for this category represented 39% of the total gross credit exposure.
 
(2)   This category includes counterparties with credit ratings that are below investment grade. The five largest counterparty exposures combined for this category represented less than 1% of the total gross credit exposure.
 
(3)   This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, but are considered investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented 7% of the total gross credit exposure.
 
(4)   This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, and are considered non-investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented less than 1% of the gross credit exposure.

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Item 8. Financial Statements and Supplementary Data

The following consolidated financial statements and schedules are included herein.

             
        Page
       
Independent Auditors’ Report     57  
Consolidated Statement of Operations     58  
Consolidated Statement of Financial Position     59  
Consolidated Statement of Cash Flows     61  
Consolidated Statement of Changes in Shareholders’ Equity and Comprehensive Income     62  
Notes to Consolidated Financial Statements        
Note 1   Significant Accounting Policies     63  
Note 2   New Accounting Pronouncements     70  
Note 3   Acquisitions and Dispositions     73  
Note 4   Regulatory Matters     75  
Note 5   Nuclear Operations     83  
Note 6   Jointly Owned Utility Plant     85  
Note 7   Income Taxes     86  
Note 8   Common Stock and Earnings Per Share     87  
Note 9   Long-Term Debt and Preferred Securities     89  
Note 10   Short-Term Credit Arrangements and Borrowings     91  
Note 11   Capital and Operating Leases     92  
Note 12   Financial and Other Derivative Instruments     93  
Note 13   Commitments and Contingencies     95  
Note 14   Retirement Benefits and Trusteed Assets     99  
Note 15   Stock-based Compensation     106  
Note 16   Segment and Related Information     109  
Note 17   Supplementary Quarterly Financial Information     113  
    Schedule II – Valuation and Qualifying Accounts     119  

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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, 2003 and 2002, 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, 2003. Our audits also included the financial statement schedule listed in the index at Item 15. These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and the 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, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements of the Company taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, in connection with the required adoption of certain new accounting principles, in 2003 the Company changed its method of accounting for asset retirement obligations, energy trading contracts and gas inventories; in 2002 the Company changed its method of accounting for goodwill and energy trading contracts; and in 2001 the Company changed its method of accounting for derivative instruments and hedging activities.

/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan
March 1, 2004

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DTE Energy Company
Consolidated Statement of Operations

                               
          Year Ended December 31
         
(in Millions, Except per Share Amounts)   2003   2002   2001
   
 
 
Operating Revenues
  $ 7,041     $ 6,729     $ 5,787  
 
   
     
     
 
Operating Expenses
                       
 
Fuel, purchased power and gas
    2,241       2,099       1,919  
 
Operation and maintenance
    3,032       2,547       1,848  
 
Depreciation, depletion and amortization
    687       737       782  
 
Taxes other than income
    334       352       305  
 
Merger and restructuring charges (Note 3)
                268  
 
   
     
     
 
 
    6,294       5,735       5,122  
 
   
     
     
 
Operating Income
    747       994       665  
 
   
     
     
 
Other (Income) and Deductions
                       
 
Interest expense
    546       569       482  
 
Interest income
    (37 )     (29 )     (22 )
 
Minority interest
    (91 )     (37 )      
 
Other income
    (138 )     (62 )     (60 )
 
Other expenses
    110       51       75  
 
   
     
     
 
 
    390       492       475  
 
   
     
     
 
Income Before Income Taxes
    357       502       190  
Income Tax Benefit (Note 7)
    (123 )     (84 )     (119 )
 
   
     
     
 
Income from Continuing Operations
    480       586       309  
Income from Discontinued Operations of ITC, net of tax (Note 3)
    68       46       20  
Cumulative Effect of Accounting Changes, net of tax (Note 2)
    (27 )           3  
 
   
     
     
 
Net Income
  $ 521     $ 632     $ 332  
 
   
     
     
 
Basic Earnings per Common Share (Note 8)
                       
   
Income from continuing operations
  $ 2.87     $ 3.57     $ 2.02  
   
Discontinued operations
    .41       .28       .13  
   
Cumulative effect of accounting changes
    (.17 )           .02  
 
   
     
     
 
     
Total
  $ 3.11     $ 3.85     $ 2.17  
 
   
     
     
 
Diluted Earnings per Common Share (Note 8)
                       
   
Income from continuing operations
  $ 2.85     $ 3.55     $ 2.01  
   
Discontinued operations
    .40       .28       .13  
   
Cumulative effect of accounting changes
    (.16 )           .02  
 
   
     
     
 
     
Total
  $ 3.09     $ 3.83     $ 2.16  
 
   
     
     
 
Average Common Shares
                       
   
Basic
    168       164       153  
   
Diluted
    168       165       154  
Dividends Declared per Common Share
  $ 2.06     $ 2.06     $ 2.06  

See Notes to Consolidated Financial Statements

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DTE Energy Company
Consolidated Statement of Financial Position

                     
        December 31
       
(in Millions)   2003   2002
   
 
ASSETS
               
Current Assets
               
 
Cash and cash equivalents
  $ 54     $ 133  
 
Restricted cash
    131       237  
 
Accounts receivable
               
   
Customer (less allowance for doubtful accounts of $99 and $82, respectively)
    877       902  
   
Accrued unbilled revenues
    316       296  
   
Other
    338       237  
 
Inventories
               
   
Fuel and gas
    467       413  
   
Materials and supplies
    162       163  
 
Assets from risk management and trading activities
    186       224  
 
Other
    181       159  
 
 
   
     
 
 
    2,712       2,764  
 
   
     
 
Investments
               
 
Nuclear decommissioning trust funds
    518       417  
 
Other
    601       496  
 
 
   
     
 
 
    1,119       913  
 
   
     
 
Property
               
 
Property, plant and equipment
    17,679       17,862  
 
Less accumulated depreciation and depletion (Note 2)
    (7,355 )     (7,320 )
 
 
   
     
 
 
    10,324       10,542  
 
   
     
 
Other Assets
               
 
Goodwill (Note 3)
    2,067       2,112  
 
Regulatory assets (Note 4)
    2,063       1,197  
 
Securitized regulatory assets (Note 4)
    1,527       1,613  
 
Notes receivable
    469       336  
 
Assets from risk management and trading activities
    88       152  
 
Prepaid pension assets
    181       172  
 
Other
    203       184  
 
 
   
     
 
 
    6,598       5,766  
 
 
   
     
 
Total Assets
  $ 20,753     $ 19,985  
 
   
     
 

See Notes to Consolidated Financial Statements

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DTE Energy Company
Consolidated Statement of Financial Position

                   
      December 31
     
(in Millions, Except Shares)   2003   2002
   
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
               
Current Liabilities
               
 
Accounts payable
  $ 625     $ 647  
 
Accrued interest
    110       115  
 
Dividends payable
    87       90  
 
Accrued payroll
    51       49  
 
Income taxes
    185       44  
 
Short-term borrowings
    370       414  
 
Current portion long-term debt, including capital leases
    477       1,018  
 
Liabilities from risk management and trading activities
    326       262  
 
Other
    648       552  
 
 
   
     
 
 
    2,879       3,191  
 
   
     
 
Other Liabilities
               
 
Deferred income taxes
    988       916  
 
Regulatory liabilities (Notes 2 and 4)
    817       179  
 
Asset retirement obligations (Note 2)
    866        
 
Asset removal costs (Note 2)
          729  
 
Unamortized investment tax credit
    156       168  
 
Liabilities from risk management and trading activities
    173       208  
 
Liabilities from transportation and storage contracts
    495       545  
 
Accrued pension liability
    345       582  
 
Deferred gains from asset sales
    311       161  
 
Minority interest
    156       128  
 
Nuclear decommissioning (Notes 2 and 5)
    67       416  
 
Other
    544       394  
 
 
   
     
 
 
    4,918       4,426  
 
   
     
 
Long-Term Debt (net of current portion) (Note 9)
               
 
Mortgage bonds, notes and other
    5,624       5,656  
 
Securitization bonds
    1,496       1,585  
 
Equity-linked securities
    185       191  
 
Trust Preferred-linked securities
    289       289  
 
Capital lease obligations
    75       82  
 
   
     
 
 
    7,669       7,803  
 
   
     
 
Commitments and Contingencies (Notes 4, 5 and 13)
               
Shareholders’ Equity
               
 
Common stock, without par value, 400,000,000 shares authorized, 168,606,522 and 167,462,430 shares issued and outstanding, respectively
    3,109       3,052  
 
Retained earnings
    2,308       2,132  
 
Accumulated other comprehensive loss
    (130 )     (619 )
 
 
   
     
 
 
    5,287       4,565  
 
   
     
 
Total Liabilities and Shareholders’ Equity
  $ 20,753     $ 19,985  
 
   
     
 

See Notes to Consolidated Financial Statements

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DTE Energy Company
Consolidated Statement of Cash Flows

                               
          Year Ended December 31
         
(in Millions)   2003   2002   2001
   
 
 
Operating Activities
                       
 
Net income
  $ 521     $ 632     $ 332  
 
Adjustments to reconcile net income to net cash from operating activities:
                       
     
Depreciation, depletion and amortization
    691       759       795  
     
Merger and restructuring charges
                215  
     
Deferred income taxes
    (220 )     (208 )     (7 )
     
Gain on sale of assets, net
    (129 )            
     
Partners’ share of synfuel project losses
    (78 )     (40 )      
     
Contributions from synfuel partners
    65       22        
     
Cumulative effect of accounting changes
    27             3  
     
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)
    73       (169 )     (527 )
 
 
   
     
     
 
     
Net cash from operating activities
    950       996       811  
 
   
     
     
 
Investing Activities
                       
   
Plant and equipment expenditures – regulated
    (679 )     (794 )     (776 )
   
Plant and equipment expenditures – non-regulated
    (72 )     (190 )     (320 )
   
Acquisition of MCN Energy, net of cash acquired
                (1,212 )
   
Proceeds from sale of interests in synfuel projects
    89       32        
   
Proceeds from sale of ITC and other assets
    669       9       216  
   
Restricted cash for debt redemptions
    106       (79 )     (70 )
   
Other investments
    (103 )     (93 )     (124 )
 
   
     
     
 
   
Net cash from (used for) investing activities
    10       (1,115 )     (2,286 )
 
   
     
     
 
Financing Activities
                       
   
Issuance of long-term debt
    527       958       4,254  
   
Redemption of long-term debt
    (1,208 )     (613 )     (1,423 )
   
Issuance of trust preferred-linked securities
          180        
   
Redemption of trust preferred-linked securities
          (180 )      
   
Short-term borrowings, net
    (44 )     (267 )     (282 )
   
Capital lease obligations
    (9 )     (12 )     (107 )
   
Issuance of common stock
    44       265        
   
Repurchase of common stock
    (3 )     (9 )     (438 )
   
Dividends on common stock
    (346 )     (338 )     (325 )
 
 
   
     
     
 
   
Net cash from (used for) financing activities
    (1,039 )     (16 )     1,679  
 
   
     
     
 
Net Increase (Decrease) in Cash and Cash Equivalents
    (79 )     (135 )     204  
Cash and Cash Equivalents at Beginning of Period
    133       268       64  
 
   
     
     
 
Cash and Cash Equivalents at End of Period
  $ 54     $ 133     $ 268  
 
 
   
     
     
 

See Notes to Consolidated Financial Statements

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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, 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 )
 
Net change in unrealized losses on derivatives, net of tax
                      (69 )     (69 )
 
Net change in unrealized gain on investments, net of tax
                      1       1  
 
Other
                11             11  
 
   
     
     
     
     
 
Balance, December 31, 2001
    161,134       2,811       1,846       (68 )     4,589  
 
   
     
     
     
     
 
 
Net income
                632             632  
 
Issuance of new shares
    6,426       270                   270  
 
Dividends declared on common stock
                (341 )           (341 )
 
Repurchase and retirement of common stock
    (98 )     (1 )     (2 )           (3 )
 
Pension obligations (Note 14)
                            (518 )     (518 )
 
Net change in unrealized losses on derivatives, net of tax
                      (33 )     (33 )
 
Other
          (28 )     (3 )           (31 )
 
   
     
     
     
     
 
Balance, December 31, 2002
    167,462       3,052       2,132       (619 )     4,565  
 
   
     
     
     
     
 
 
Net income
                521             521  
 
Issuance of new shares
    1,225       57                   57  
 
Dividends declared on common stock
                (348 )           (348 )
 
Repurchase and retirement of common stock
    (80 )     (1 )                 (1 )
 
Pension obligations (Note 14)
                      420       420  
 
Net change in unrealized losses on derivatives, net of tax
                      17       17  
 
Net change in unrealized gain on investments, net of tax
                      52       52  
 
Other
          1       3             4  
 
   
     
     
     
     
 
Balance, December 31, 2003
    168,607     $ 3,109     $ 2,308     $ (130 )   $ 5,287  
 
   
     
     
     
     
 

The following table displays comprehensive income (loss):

                             
(in Millions)   2003   2002   2001
   
 
 
Net income
  $ 521     $ 632     $ 332  
 
   
     
     
 
Other comprehensive income (loss), net of tax:
                       
 
Net unrealized losses on derivatives:
                       
   
Gains or (losses) arising during the period, net of taxes of $(8), $32 and $29
    16       (60 )     (53 )
   
Amounts reclassified to earnings, net of taxes of $-, $(15) and $(14)
    1       27       26  
   
Cumulative effect of a change in accounting, net of taxes of $-, $- and $24
                (42 )
 
   
     
     
 
 
    17       (33 )     (69 )
   
Net change in unrealized gain on investments, net of taxes of $(28), $- and $(1)
    52             1  
   
Pension obligations, net of taxes of $(226), $280 and $-
    420       (518 )      
 
   
     
     
 
Comprehensive income
  $ 1,010     $ 81     $ 264  
 
   
     
     
 

See Notes to Consolidated Financial Statements

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DTE Energy Company
Notes to Consolidated Financial Statements

NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure

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

    Detroit Edison Company (Detroit Edison), an electric utility engaged in the generation, purchase, distribution and sale of electric energy to 2.1 million customers in southeast Michigan;
 
    Michigan Consolidated Gas Company (MichCon), a natural gas utility engaged in the purchase, storage, transmission and distribution and sale of natural gas to 1.2 million customers throughout areas of Michigan; and
 
    Other non-regulated subsidiaries engaged in energy marketing and trading, energy services and various other electricity, coal and gas related businesses.

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

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

Principles of Consolidation

We consolidate all majority owned subsidiaries and investments in entities in which we have controlling influence. Non-majority owned investments are accounted for using the equity method when the company is able to influence the operating policies of the investee. Non-majority owned investments include investments in limited liability companies, partnerships or joint ventures. When we do not influence the operating policies of an investee, the cost method is used. We eliminate all intercompany balances and transactions.

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

Basis of Presentation

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

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

Revenues

Revenues from the sale and delivery of electricity, and the sale, delivery and storage of natural gas are recognized as services are provided. Detroit Edison and MichCon record revenues for electric and gas provided but unbilled at the end of each month. Under agreement with the MPSC, Detroit Edison was not allowed to raise rates through 2003. Through December 2001, MichCon’s rates included a component for cost

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of gas sold that was fixed at $2.95 per thousand cubic feet (Mcf). In 2002, MichCon reinstated the gas cost recovery (GCR) mechanism that recovers the prudent and reasonable cost of gas sold subject to annual proceedings before the MPSC.

Non-regulated revenues are recognized as services are provided and products are delivered.

Since 2002, the FASB has issued significant accounting guidance that governs energy trading revenue recognition and classification. See Note 2 - New Accounting Pronouncements for additional detail.

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. As shown in the following table, amounts recorded to other comprehensive income include unrealized derivative gains and losses under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” unrealized gains and losses on available for sale securities under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and minimum pension liabilities as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions,” at December 31, 2003. The minimum pension liability was reclassified to a regulatory asset during 2003 (Note 4).

                                 
    Net   Net   Minimum   Accumulated
    Unrealized   Unrealized   Pension   Other
    Losses on   Gains on   Liability   Comprehensive
(in Millions)   Derivatives   Investments   Adjustment   Income
   
 
 
 
Beginning balance
  $ (102 )   $ 1     $ (518 )   $ (619 )
Current-period change
    17       52       420       489  
 
   
     
     
     
 
Ending balance
  $ (85 )   $ 53     $ (98 )   $ (130 )
 
   
     
     
     
 

Inventories

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

Gas inventory at MichCon is determined using the last-in, first-out (LIFO) method. At December 31, 2003, the replacement cost of gas remaining in storage exceeded the $117 million LIFO cost by $251 million. At December 31, 2002, the replacement cost exceeded the $55 million LIFO cost by $187 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 the accounting requirements resulting from the rescission of Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Energy Trading Activities and Risk Management Activities,” the Energy Marketing & Trading segment changed to the average cost method for its gas inventories, effective January 2003.

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Property, Retirement and Maintenance, and Depreciation and Depletion

Summary of property by classification as of December 31:

                       
(in Millions)   2003   2002
   
 
Property, Plant and Equipment
               
 
Electric Utility
               
     
Generation
  $ 6,938     $ 6,515  
     
Distribution
    5,733       5,606  
     
Transmission (1)
          813  
     
 
   
     
 
 
Total Electric Utility
    12,671       12,934  
 
   
     
 
 
Gas Utility
               
     
Distribution
    1,961       1,903  
     
Storage
    224       212  
     
Other
    855       906  
     
 
   
     
 
 
Total Gas Utility
    3,040       3,021  
 
   
     
 
 
Energy Services
               
     
Coal Based Fuels
    652       636  
     
On-Site Energy
    180       172  
     
Merchant Generation
    229       228  
     
Other
    13       9  
     
 
   
     
 
 
Total Energy Services
    1,074       1,045  
     
 
   
     
 
 
Other non-regulated and other
    894       862  
 
   
     
 
Total Property, Plant and Equipment
    17,679       17,862  
 
   
     
 
Less Accumulated Depreciation and Depletion
               
 
Electric Utility
               
     
Generation
    (3,231 )     (3,046 )
     
Distribution
    (2,108 )     (2,051 )
     
Transmission (1)
          (327 )
     
 
   
     
 
 
Total Electric Utility
    (5,339 )     (5,424 )
 
   
     
 
 
Gas Utility
               
     
Distribution
    (798 )     (756 )
     
Storage
    (102 )     (99 )
     
Other
    (432 )     (457 )
     
 
   
     
 
 
Total Gas Utility
    (1,332 )     (1,312 )
 
   
     
 
 
Energy Services
               
     
Coal Based Fuels
    (219 )     (163 )
     
On-Site Energy
    (42 )     (30 )
     
Merchant Generation
    (20 )     (11 )
     
Other
    (2 )     (1 )
     
 
   
     
 
   
Total Energy Services
    (283 )     (205 )
 
   
     
 
 
Other non-regulated and other
    (401 )     (379 )
 
   
     
 
Total Accumulated Depreciation and Depletion
    (7,355 )     (7,320 )
     
 
   
     
 
Net Property, Plant and Equipment
  $ 10,324     $ 10,542  
     
 
   
     
 


(1)   Represents the operations of ITC that were sold in February 2003.

Property is stated at cost and includes construction-related labor, materials and overheads. The cost of properties retired, less salvage, at Detroit Edison and MichCon are charged to accumulated depreciation.

Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2. Approximately $37 million of expenses related to the anticipated Fermi 2 refueling outage scheduled for 2004 are being accrued on a pro-rata basis over an 18-month period that began in May 2003. We have utilized the

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accrue-in-advance policy for nuclear refueling outage costs since the Fermi 2 plant was placed in service in 1988. This method also matches the regulatory recovery of these costs in rates set by the MPSC.

We base depreciation provisions for utility property at Detroit Edison and MichCon on straight-line and units of production rates approved by the MPSC. The composite depreciation rate for Detroit Edison was 3.4 % in 2003, 2002 and 2001. The composite depreciation rate for MichCon was 3.5%, 3.6% and 3.9% in 2003, 2002 and 2001, respectively.

The average estimated useful life for each class of property, plant and equipment as of December 31, 2003 follows:

                         
Estimated Useful Lives in Years

Utility   Generation   Distribution   Transmission (1)

 
 
 
Electric
    39       37        
Gas
    N/A       26       28  


(1)   The electric transmission assets were sold in February 2003.

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

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

Gas Production

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

Long-Lived Assets

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 costs associated with computer software we develop or obtain for use in our business. We amortize computer software costs on a straight-line basis over expected periods of benefit once the installed software is ready for its intended use.

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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 our electric and gas utilities, the unamortized discount, premium and expense related to debt redeemed with a refinancing are amortized over the life of the replacement issue. Discount, premium and expense on early redemptions of debt associated with non-regulated operations are charged to earnings.

Insured and Uninsured Risks

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

Under our risk management policy, we self-insure portions of certain risks up to specified limits, depending on the type of exposure. We periodically review our insurance coverages and during 2003, we reviewed our process for estimating and recognizing reserves for self-insured risks. As a result of this review, we revised the process for estimating liabilities under our self-insured layers to include an actuarially determined estimate of “incurred but not reported” (IBNR) claims. This revision resulted in the recording of an additional liability and reduced earnings in 2003 by approximately $15 million, primarily related to general liability and workers’ compensation exposures. We intend to have an actuarially determined estimate of our IBNR liability prepared annually and will adjust the related reserve as appropriate.

Stock-Based Compensation

We have a stock-based employee compensation plan, which is described in Note 15. The plan permits the awarding of various stock awards, including options, restricted stock and performance shares. We account for stock awards under the plan under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” No compensation cost related to stock options is reflected in 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.

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(in Millions, except per share amounts)   2003   2002   2001
   
 
 
Net Income As Reported
  $ 521     $ 632     $ 332  
Less: Total Stock-based Expense (1)
    (7 )     (7 )     (9 )
 
   
     
     
 
Pro Forma Net Income
  $ 514     $ 625     $ 323  
 
   
     
     
 
Earnings Per Share
                       
 
Basic – as reported
  $ 3.11     $ 3.85     $ 2.17  
 
   
     
     
 
 
Basic – pro forma
  $ 3.06     $ 3.81     $ 2.11  
 
   
     
     
 
 
Diluted – as reported
  $ 3.09     $ 3.83     $ 2.16  
 
   
     
     
 
 
Diluted – pro forma
  $ 3.05     $ 3.79     $ 2.10  
 
   
     
     
 


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

Investments in Debt and Equity Securities

We generally classify investments in debt and equity securities as either trading or available-for-sale and have recorded such investments at market value with unrealized gains or losses included in the Consolidated Statement of Operations or in other comprehensive income or loss, respectively. Changes in the fair value of certain other investments are recorded as adjustments to regulatory assets or liabilities.

Gains from Sale of Interest in Synthetic Fuel Facilities

When we sell an interest in a synfuel facility, we recognize the gain from such sale under the installment method of accounting. Gain recognition is dependent on the synfuel production qualifying for Section 29 tax credits. Accordingly, we have deferred gains totaling $311 million and $161 million as of December 31, 2003 and 2002, respectively.

Investment in Plug Power

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

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)   2003   2002   2001
   
 
 
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
                       
 
Accounts receivable, net
  $ (113 )   $ (157 )   $ 17  
 
Accrued unbilled receivables
    (20 )     (54 )     (19 )
 
Accrued gas cost recovery revenue
    29       (5 )     (14 )
 
Inventories
    (61 )     (71 )     (76 )
 
Accounts payable
    (21 )     66       (178 )
 
Income taxes payable
    135       (8 )     (105 )
 
General taxes
    (12 )     (36 )     22  
 
Risk management and trading activities
    127       69       (80 )
 
Pension contributions
    (222 )     (35 )     (35 )
 
Postretirement obligation
    93       58       27  
 
Other
    138       4       (86 )
 
 
   
     
     
 
 
  $ 73     $ (169 )   $ (527 )
 
   
     
     
 

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

                           
(in Millions)   2003   2002   2001
   
 
 
Supplementary Cash Flow Information
                       
 
Interest paid (excluding interest capitalized)
  $ 552     $ 551     $ 409  
 
Income taxes paid
    31       167       45  
Noncash Investing and Financing Activities
                       
 
Exchange of debt
  $ 100     $     $  
 
Notes received from sale of synfuel projects
    238       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.

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Note   Title

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

NOTE 2 – NEW ACCOUNTING PRONOUNCEMENTS

Derivative Instruments and Hedging Activities

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 required 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. The cumulative effect of adopting SFAS No. 133 on January 1, 2001 was an increase in net income of $3 million and an increase in other comprehensive loss of $42 million.

Effective July 1, 2003, we adopted SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” The statement amends and clarifies financial accounting and reporting for derivative instruments, including derivative instruments embedded in other contracts and for hedging activities. Our financial statements were not impacted by the adoption of SFAS No. 149.

In August 2003, the EITF released Issue No. 03-11, which provides guidance on whether to report realized gains or losses on a gross or net basis on physically settled derivative contracts not held for trading purposes. The new guidance was implemented in the fourth quarter of 2003 and had an immaterial effect on our financial statements.

See Note 12 – Financial and Other Derivative Instruments for additional information.

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Energy Trading Contracts

Under EITF Issue No. 98-10, 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. 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 and recognized 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

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definition of a derivative are accounted for under settlement accounting, effective October 25, 2002 for new contracts and effective January 1, 2003 for existing contracts. Derivative contracts are only marked to market to the extent that markets are considered highly liquid where objective, transparent prices can be obtained. Unrealized gains and losses are fully reserved for transactions that do not meet this criteria.

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

Effective January 1, 2003, we applied EITF Issue 02-03 which rescinded EITF Issue 98-10. As a result of discontinuing the application of EITF Issue No. 98-10 to energy contracts and ARB No. 43 to gas inventory, we recorded a cumulative effect of accounting change that reduced net income for the first quarter of 2003 by $16 million (net of taxes of $9 million.)

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 required 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 principal. We completed the annual goodwill impairment test and have determined that no impairment exists.

In accordance with SFAS No. 142, we discontinued the amortization of goodwill effective January 1, 2002. A reconciliation of previously reported 2001 net income and earnings per share to the amounts adjusted for the exclusion of goodwill amortization follows:

                         
    Year Ended December 31, 2001
            Basic   Diluted
    Net   Earnings   Earnings
(In Millions, except per share amounts)
  Income
  Per Share
  Per Share
As reported
  $ 332     $ 2.17     $ 2.16  
Add: Goodwill amortization
    31       .20       .20  
 
   
 
     
 
     
 
 
As adjusted
  $ 363     $ 2.37     $ 2.36  
 
   
 
     
 
     
 
 

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 $40 million in 2003, $46 million in 2002 and $48 million in 2001. There were no material acquisitions of intangible assets during 2003 and 2002. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2003 were $537 million and $303 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2002 were $526 million and $317 million, respectively. Amortization expense of intangible assets is estimated to be $40 million annually for 2004 through 2008.

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 are deferring such differences under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.

As a result of adopting SFAS No. 143 on January 1, 2003, we recorded a plant asset of $306 million with offsetting accumulated depreciation of $106 million, a retirement obligation liability of $815 million and reversed previously recognized obligations of $377 million, principally nuclear decommissioning liabilities. We also recorded a cumulative effect amount related to regulated operations as a regulatory asset of $221 million, and a cumulative effect charge against earnings of $11 million (net of tax of $6 million) for 2003.

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

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

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    (in Millions)
    Net   Basic and Diluted
Year
  Income
  Earnings per Share
2003
    4.8       .03  
2002
    4.8       .03  
2001
    4.2       .03  

The pro forma effect of the asset retirement obligation had SFAS No. 143 been adopted for all periods presented would increase reported liabilities by $815 million and $807 million as of December 31, 2002 and 2001, respectively.

A reconciliation of the asset retirement obligation for 2003 follows:

         
(in Millions)        
Asset retirement obligations at January 1, 2003
  $ 815  
Accretion
    55  
Liabilities settled
    (4 )
 
   
 
 
Asset retirement obligations at December 31, 2003
  $ 866  
 
   
 
 

SFAS No. 143 also requires the quantification of the estimated cost of removal obligations, arising from other than legal obligations, which have been accrued through depreciation charges. At December 31, 2002, we reclassified approximately $729 million of previously accrued asset removal costs related to our regulated operations, which had been previously netted against accumulated depreciation, to an asset removal cost liability. At December 31, 2003, we reclassified approximately $655 million of these accrued asset removal obligations to regulatory liabilities.

Exit and Disposal Activities

Effective January 1, 2003, we adopted SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which 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. The adoption of this statement had no impact on our consolidated financial statements.

Consolidation of Variable Interest Entities

In January 2003, FASB Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51,” was issued and requires an investor with a majority of the variable interests (primary beneficiary) in a variable interest entity to consolidate the assets, liabilities and results of operations of the entity. A variable interest entity is an entity in which the equity investors do not have controlling interests, the equity investment at risk is insufficient to finance the entity’s activities without receiving additional subordinated financial support from other parties, or equity investors do not share proportionally in gains or losses. FIN 46 was applicable (i) immediately for all variable interest entities created after January 31, 2003; or (ii) in the first fiscal year or interim period beginning after June 15, 2003 for variable interest entities created before February 1, 2003.

In October 2003, the FASB issued Staff Position No. FIN 46-6, which allowed for the deferral of the effective date for applying the provisions of Interpretation No. 46 for all interests in variable interest entities created before February 1, 2003, until the end of the first interim or annual period ending after December 15, 2003.

In December 2003, the FASB issued FIN 46