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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTIONS 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2006
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   (I.R.S. Employer
incorporation or 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   New York Stock Exchange
preferred stock purchase rights    
7.8% Trust Preferred Securities *   New York Stock Exchange
7.50% Trust Originated 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.
 
**   Issued by DTE Energy Trust II. DTE Energy fully and unconditionally guarantees the payments of all amounts due on these securities to the extent DTE Energy Trust II has funds available for payment of such distributions.
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yes o No þ
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ       Accelerated filer o       Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
On June 30, 2006, the aggregate market value of the Registrant’s voting and non-voting common equity held by non-affiliates was approximately $7.2 billion (based on the New York Stock Exchange closing price on such date). There were 177,123,754 shares of common stock outstanding at January 31, 2007.
Certain information in DTE Energy Company’s definitive Proxy Statement for its 2007 Annual Meeting of Common Shareholders to be held May 3, 2007, 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.
 
 

 


 

DTE Energy Company
Annual Report on Form 10-K
Year Ended December 31, 2006
TABLE OF CONTENTS
             
        PAGE  
        1  
 
           
        3  
 
           
Part I
           
  Business, Risk Factors, Unresolved Staff Comments and Properties     4  
 
           
  Legal Proceedings     27  
 
           
  Submission of Matters to a Vote of Security Holders     27  
 
           
           
  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     27  
 
           
  Selected Financial Data     30  
 
           
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     30  
 
           
  Quantitative and Qualitative Disclosures About Market Risk     68  
 
           
  Financial Statements and Supplementary Data     71  
 
           
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     138  
 
           
  Controls and Procedures     138  
 
           
  Other Information     138  
 
           
           
  Directors, Executive Officers and Corporate Governance     138  
 
           
  Executive Compensation     138  
 
           
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     138  
 
           
  Certain Relationships and Related Transactions, and Director Independence     138  
 
           
  Principal Accountant Fees and Services     138  
 
           
           
 
           
  Exhibits and Financial Statement Schedules     139  
 
           
        145  
 First Amendment to Company Deferred Stock Compensation Plan for Non-Employee Directors, effective January 1, 2001
 Second Amendment to Company Deferred Stock Compensation Plan for Non-Employee Directors, effective January 1, 2005
 Third Amendment to Company Deferred Stock Compensation Plan for Non-Employee Directors, effective January 1, 2006
 Third Amendment to Company Executive Deferred Compensation Plan, effective December 31, 2006
 First Amendment to Company Supplemental Retirement Plan, effective January 1, 2002
 Computation of Ratio of Earnings to Fixed Charges
 Subsidiaries of the Company
 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

 


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DEFINITIONS
     
Coke and Coke Battery  
Raw coal is heated to high temperatures in ovens to separate impurities, leaving a carbon residue called coke. Coke is combined with iron ore to create a high metallic iron that is used to produce steel. A series of coke ovens configured in a module is referred to as a battery.
   
 
Company  
DTE Energy Company and any subsidiary companies
   
 
CTA  
Costs to achieve, consisting of project management, consultant support and employee severance, related to the Performance Excellence Process
   
 
Customer Choice  
Statewide initiatives giving customers in Michigan the option to choose alternative suppliers for electricity and gas.
   
 
Detroit Edison  
The Detroit Edison Company (a direct wholly owned subsidiary of DTE Energy Company) and subsidiary companies
   
 
DTE Energy  
DTE Energy Company, directly or indirectly the parent of Detroit Edison, MichCon and numerous non-utility subsidiaries
   
 
EPA  
United States Environmental Protection Agency
   
 
FERC  
Federal Energy Regulatory Commission
   
 
GCR  
A gas cost recovery mechanism authorized by the MPSC, permitting MichCon to pass the cost of natural gas to its customers.
   
 
ITC  
International Transmission Company (until February 28, 2003, a wholly owned subsidiary of DTE Energy Company)
   
 
MDEQ  
Michigan Department of Environmental Quality
   
 
MichCon  
Michigan Consolidated Gas Company (an indirect wholly owned subsidiary of DTE Energy) and subsidiary companies
   
 
MISO  
Midwest Independent System Operator, a Regional Transmission Organization
   
 
MPSC  
Michigan Public Service Commission
   
 
Non-utility  
An entity that is not a public utility. Its conditions of service, prices of goods and services and other operating related matters are not directly regulated by the MPSC or the FERC.
   
 
NRC  
Nuclear Regulatory Commission
   
 
PSCR  
A power supply cost recovery mechanism authorized by the MPSC that allows Detroit Edison to recover through rates its fuel, fuel-related and purchased power expenses. The power supply cost recovery mechanism was suspended under Michigan’s restructuring legislation (signed into law June 5, 2000), which lowered and froze electric customer rates and was reinstated by the MPSC effective January 1, 2004.
   
 
Production tax credits  
Tax credits as authorized under Sections 45K and 45 of the Internal Revenue Code that are designed to stimulate investment in and development of alternate fuel sources. The amount of a production tax credit can vary each year as determined by the Internal Revenue Service.
   
 
Proved Reserves  
Estimated quantities of natural gas, natural gas liquids and crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reserves under existing economic and operating conditions.

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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 absent special regulatory approval would not otherwise be recoverable if customers switch to alternative energy suppliers.
   
 
Subsidiaries  
The direct and indirect subsidiaries of DTE Energy Company
   
 
Synfuels  
The fuel produced through a process involving chemically modifying and binding particles of coal. Synfuels are used for power generation and coke production. Synfuel production generates production tax credits.
   
 
Unconventional Gas  
Includes those oil and gas deposits that originated and are stored in coal bed, tight sandstone and shale formations.
   
 
Units of Measurement  
 
   
 
Bcf  
Billion cubic feet of gas
   
 
Bcfe  
Conversion metric of natural gas, the ratio of 6 Mcf of gas to 1 barrel of oil.
   
 
kWh  
Kilowatthour of electricity
   
 
Mcf  
Thousand cubic feet of gas
   
 
MMcf  
Million cubic feet of gas
   
 
MW  
Megawatt of electricity
   
 
MWh  
Megawatthour of electricity

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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 presently contemplated, projected, estimated or budgeted. Many factors may impact forward-looking statements including, but not limited to, the following:
    the higher price of oil and its impact on the value of production tax credits or the potential requirement to refund proceeds received from synfuel partners;
 
    the uncertainties of successful exploration of gas shale resources and inability to estimate gas reserves with certainty;
 
    the effects of weather and other natural phenomena on operations and sales to customers, and purchases from suppliers;
 
    economic climate and population growth or decline in the geographic areas where we do business;
 
    environmental issues, laws, regulations, and the cost of remediation and compliance;
 
    nuclear regulations and operations associated with nuclear facilities;
 
    implementation of electric and gas Customer Choice programs;
 
    impact of electric and gas utility restructuring in Michigan, including legislative amendments;
 
    employee relations and the impact of collective bargaining agreements;
 
    unplanned outages;
 
    access to capital markets and capital market conditions and the results of other financing efforts which can be affected by credit agency ratings;
 
    the timing and extent of changes in interest rates;
 
    the level of borrowings;
 
    changes in the cost and availability of coal and other raw materials, purchased power and natural gas;
 
    effects of competition;
 
    impact of regulation by the FERC, MPSC, NRC and other applicable governmental proceedings and regulations, including any associated impact on rate structures;
 
    contributions to earnings by non-utility subsidiaries;
 
    changes in and application of federal, state and local tax laws and their interpretations, including the Internal Revenue Code, regulations, rulings, court proceedings and audits;
 
    the ability to recover costs through rate increases;
 
    the availability, cost, coverage and terms of insurance;
 
    the cost of protecting assets against, or damage due to, terrorism;
 
    changes in and application of accounting standards and financial reporting regulations;
 
    changes in federal or state laws and their interpretation with respect to regulation, energy policy and other business issues;
 
    uncollectible accounts receivable;
 
    binding arbitration, litigation and related appeals;
 
    changes in the economic and financial viability of our suppliers, customers and trading counterparties, and the continued ability of such parties to perform their obligations to the Company; and
 
    timing, terms and proceeds from any asset sale or monetization.
New factors emerge from time to time. We cannot predict what factors may arise or how such factors may cause our results to differ materially from those contained in any forward-looking statement. Any forward-looking statements speak only as of the date on which such statements are made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.

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Part I
Items 1. and 2. Business and Properties
General
In 1995, DTE Energy incorporated in the State of Michigan. Our utility operations consist primarily of Detroit Edison and MichCon. We also have five non-utility segments that are engaged in a variety of energy related businesses. In August 2005, the Energy Policy Act of 2005 repealed the Public Utility Holding Company Act of 1935 (PUHCA), effective February 8, 2006. A discussion of the Energy Policy Act of 2005 is in the Management’s Discussion and Analysis section of this Form 10-K.
Detroit Edison is a Michigan corporation organized in 1903 and is a public utility subject to regulation by the MPSC and the FERC. Detroit Edison is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.2 million customers in southeastern Michigan.
MichCon is a Michigan corporation organized in 1898 and is a public utility subject to regulation by the MPSC. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.3 million customers throughout Michigan.
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to such reports are available free of charge through the Investor Relations page of our website: www.dteenergy.com, as soon as reasonably practicable after they are filed with or furnished to the Securities and Exchange Commission (SEC). The information on our website is not, and shall not be deemed to be, a part of this Form 10-K or any other filing we make with the SEC. Our previously filed reports and statements are also available at the SEC’s website: www.sec.gov.
References in this report to “we,” “us,” “our,” “Company” or “DTE” are to DTE Energy and its subsidiaries, collectively.
Corporate Structure
In the third quarter of 2006, we realigned the non-utility segment Power and Industrial Projects business unit to separately present the Synthetic Fuel business. The impending expiration of synfuel tax credits as of December 31, 2007, combined with the sustained volatility of oil prices, increased management focus on synfuels, thereby requiring a separate business segment. In the fourth quarter of 2006, we separated the Fuel Transportation and Marketing segment into Coal and Gas Midstream, and Energy Trading corresponding to additional management focus on the results of these non-utility segments. Based on the following structure, we set strategic goals, allocate resources and evaluate performance. See Note 18 of the Notes to Consolidated Financial Statements for financial information by segment for the last three years.
Electric Utility
    Consists of Detroit Edison, the company’s electric utility whose operations include the power generation and electric distribution facilities that service approximately 2.2 million residential, commercial, industrial and wholesale customers throughout southeastern Michigan.
Gas Utility
    Consists of the gas distribution services provided by MichCon, a gas utility that purchases, stores and distributes natural gas throughout Michigan to approximately 1.3 million residential, commercial and industrial customers and Citizens Gas Fuel Company (Citizens), a gas utility that distributes natural gas in Adrian, Michigan.
Non-Utility Operations
    Coal and Gas Midstream, primarily consisting of coal transportation and marketing, and gas pipelines, processing and storage;

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    Unconventional Gas Production, primarily consisting of unconventional gas project development and production;
 
    Power and Industrial Projects, primarily consisting of on-site energy services, steel-related projects and power generation with services;
 
    Energy Trading, primarily consisting of energy marketing and trading operations; and
 
    Synthetic Fuel, consisting of the operations of nine synfuel plants.
Corporate & Other, primarily consisting of corporate staff functions and certain energy related investments.
(FLOW CHART)
Refer to our Management’s Discussion and Analysis for an in-depth analysis of each segment’s financial results. A description of each business unit follows.
ELECTRIC UTILITY
Description
Our Electric Utility segment consists of Detroit Edison, an electric utility subject to regulation by the MPSC and FERC. Detroit Edison is engaged in the generation, purchase, distribution and sale of electric energy to approximately 2.2 million customers in a 7,600 square mile area in southeastern Michigan.
Our plants are regulated by numerous federal and state governmental agencies, including, but not limited to, the MPSC, the FERC, the NRC, the EPA and the MDEQ. Electricity is generated from our numerous fossil plants, a hydroelectric pumped storage plant and a nuclear plant, and is purchased from electricity generators, suppliers and wholesalers.

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The electricity we produce and purchase is sold to four major classes of customers: residential, commercial, industrial and wholesale, principally throughout Michigan.
                         
Revenue by Service                  
(in Millions)   2006     2005     2004  
Residential
  $ 1,671     $ 1,517     $ 1,345  
Commercial
    1,603       1,331       1,123  
Industrial
    835       697       557  
Wholesale
    109       73       65  
Other
    350       464       234  
 
                 
Subtotal
    4,568       4,082       3,324  
Interconnection sales (1)
    169       380       244  
 
                 
Total Revenue
  $ 4,737     $ 4,462     $ 3,568  
 
                 
 
(1)   Represents power that is not distributed by Detroit Edison.
Weather, economic factors, competition 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.
Our operations are not dependent upon a limited number of customers, and the loss of any one or a few customers would not have a material adverse effect on Detroit Edison.
Fuel Supply and Purchased Power
Our power is generated from a variety of fuels and is supplemented with purchased power. We expect to have an adequate supply of fuel and purchased power to meet our obligation to serve customers. Our generating capability is heavily dependent upon the availability of coal. Coal is purchased from various sources in different geographic areas under agreements that vary in both pricing and terms. We expect to obtain the majority of our coal requirements through long-term contracts with the balance to be obtained through short-term agreements and spot purchases. We have six long-term and two short-term contracts for a total purchase of approximately 35 million tons of low-sulfur western coal to be delivered from 2007 to 2010. We also have ten contracts for the purchase of approximately 8 million tons of Appalachian coal to be delivered from 2007 through 2009. All of these contracts have fixed prices. We have approximately 90% of our 2007 expected coal requirements under contract. Given the geographic diversity of supply, we believe we can meet our expected generation requirements. We 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.
Detroit Edison participates in the energy market through MISO. We offer our generation in the market on a day-ahead and real-time basis and bid for power in the market to serve our load. We are a net purchaser of power which supplements our generation capability to meet customer demand during peak cycles.

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Properties
Detroit Edison owns generating plants and facilities that are located in the State of Michigan. Substantially all of our property is subject to the lien of a mortgage.
Generating plants owned and in service as of December 31, 2006 are as follows:
                 
    Location by   Summer Net    
    Michigan   Rated Capability (1) (2)    
Plant Name   County   (MW)   (%)   Year in Service
Fossil-fueled Steam-Electric
               
Belle River (3)
  St. Clair   1,026   9.2   1984 and 1985
Conners Creek
  Wayne   215   1.9   1951
Greenwood
  St. Clair   785   7.1   1979
Harbor Beach
  Huron   103   0.9   1968
Marysville
  St. Clair   84   0.8   1943 and 1947
Monroe (4)
  Monroe   3,115   28.0   1971, 1973 and 1974
River Rouge
  Wayne   510   4.6   1957 and 1958
St. Clair
  St. Clair   1,415   12.7   1953, 1954, 1959, 1961 and 1969
Trenton Channel
  Wayne   730   6.6   1949 and 1968
 
      7,983   71.8    
Oil or Gas-fueled Peaking Units
  Various   1,102   9.9   1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric Fermi 2 (5)
  Monroe   1,111   10.0   1988
Hydroelectric Pumped Storage Ludington (6)
  Mason   917   8.3   1973
 
      11,113   100.0    
 
(1)   Summer net rated capabilities of generating plants in service are based on periodic load tests and are changed depending on operating experience, the physical condition of units, environmental control limitations and customer requirements for steam, which otherwise would be used for electric generation.
 
(2)   Excludes one oil-fueled unit, St. Clair Unit No. 5 (250 MW), in cold standby status.
 
(3)   The Belle River capability represents Detroit Edison’s entitlement to 81.39% of the capacity and energy of the plant. See Note 8.
 
(4)   The Monroe Power Plant provided 38% of Detroit Edison’s total 2006 power plant generation.
 
(5)   Fermi 2 has a design electrical rating (net) of 1,150 MW.
 
(6)   Represents Detroit Edison’s 49% interest in Ludington with a total capability of 1,872 MW. See Note 8.
Detroit Edison owns and operates 675 distribution substations with a capacity of approximately 33,075,000 kilovolt-amperes (kVA) and approximately 426,700 line transformers with a capacity of approximately 25,883,000 kVA.
Circuit miles of distribution lines owned and in service as of December 31, 2006 are as follows:
                 
Electric Distribution   Circuit Miles
Operating Voltage-Kilovolts (kV)   Overhead   Underground
4.8 kV to 13.2 kV
    28,155       13,747  
24 kV
    101       690  
40 kV
    2,323       332  
120 kV
    70       13  
 
               
 
    30,649       14,782  
 
               
There are numerous interconnections that allow the interchange of electricity between Detroit Edison and electricity providers external to our service area. These interconnections are generally owned and operated by ITC Transmission and connect to neighboring energy companies.

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Regulation
Detroit Edison’s business is subject to the regulatory jurisdiction of various agencies, including, but not limited to, the MPSC, the FERC and the NRC. The MPSC issues orders pertaining to rates, recovery of certain costs, including the costs of generating facilities and regulatory assets, conditions of service, accounting and operating-related matters. Detroit Edison’s MPSC-approved rates charged to customers have historically been designed to allow for the recovery of costs, plus an authorized rate of return on our investments. The FERC regulates Detroit Edison with respect to financing authorization and wholesale electric activities. The NRC has regulatory jurisdiction over all phases of the operation, construction, licensing and decommissioning of Detroit Edison’s nuclear plant operations. We are subject to the requirements of other regulatory agencies with respect to safety, the environment and health.
Since 1996, there have been several important acts, orders, court rulings and legislative actions in the State of Michigan that affect Detroit Edison’s 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 continues to transport the electric supply to the customers’ facilities, thereby retaining distribution margins. The electric Customer Choice program was phased in over a three-year period, with all customers having the option to choose their electric supplier by January 2002.
In 2000, the Michigan Legislature enacted legislation that reduced electric rates by 5% and reaffirmed January 2002 as the date for full implementation of the electric Customer Choice program. This legislation also contained provisions freezing rates through 2003 and preventing rate increases for small business customers through 2004 and for residential customers through 2005. The legislation and an MPSC order issued in 2001 established a methodology to enable Detroit Edison to recover stranded costs related to its generation operations that may not otherwise be recoverable due to electric Customer Choice related lost sales and margins. The legislation also provides for the recovery of the costs associated with the implementation of the electric Customer Choice program. The MPSC has determined that these costs will be treated as regulatory assets. Additionally, the legislation provides for recovery of costs incurred as a result of changes in taxes, laws and other governmental actions including the Clean Air Act.
In 2004, the MPSC issued interim and final rate orders that authorized electric rate increases totaling $374 million, and eliminated transition credits and implemented transition charges for electric Customer Choice customers. The increases were applicable to all customers not subject to a rate cap. The interim order affirmed the resumption of the PSCR mechanism for both capped and uncapped customers, which reduced PSCR revenues. The MPSC also authorized the recovery of approximately $385 million in regulatory assets, including stranded costs. As part of the final order Detroit Edison was ordered to file an application to restructure its electric rates.
In February 2005, Detroit Edison filed a rate restructuring proposal with the MPSC to restructure its electric rates and begin phasing out subsidies within the current pricing structure. In December 2005, the MPSC issued an order that provided for initial steps to improve the current competitive imbalance in Michigan’s electric Customer Choice program. The December 2005 order establishes cost-based power supply rates for Detroit Edison’s full service customers. Electric Customer Choice participants will pay cost-based distribution rates while Detroit Edison’s full service commercial and industrial customers will pay cost-based distribution rates that reflect the cost of the residential rate subsidy. Residential customers continue to pay a subsidized below cost rate for distribution service. These revenue neutral revised rates were effective February 1, 2006. Detroit Edison was also ordered to file a general rate case no later than July 1, 2007, based on 2006 actual results.
In March 2006, the MPSC issued an order directing Detroit Edison to show cause by June 1, 2006 why its retail electric rates should not be reduced in 2007. The MPSC cited certain changes that had occurred since the November 2004 order in Detroit Edison’s last general rate case, or were expected to occur. These changes included: declines in electric Customer Choice program participation, expiration of the

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residential rate caps, and projected reductions in Detroit Edison operating costs. The show cause filing was to reflect sales, costs and financial conditions that were expected to occur by 2007. On June 1, 2006, Detroit Edison filed its response explaining why its electric rates should not be reduced in 2007. Detroit Edison indicated that it will have a revenue deficiency of approximately $45 million beginning in 2007 due to significant capital investments over the next several years for infrastructure improvements to enhance electric service reliability and for mandated environmental expenditures. The impacts of these investments will be partially offset by efficiency and cost-savings measures that have been initiated. Therefore, Detroit Edison requested that the show cause proceeding allow for rate increase adjustments based on the combined effects of investment expenditures and cost-savings programs. The MPSC denied this request and indicated that a full review of rates will be made in Detroit Edison’s next general rate case, which is due to be filed by July 1, 2007. The MPSC issued an order approving a settlement agreement in this proceeding on August 31, 2006. The order provided for an annualized rate reduction of $53 million for 2006, effective September 5, 2006. Beginning January 1, 2007, and continuing until the later of March 31, 2008 or 12 months from the filing date of Detroit Edison’s next main case, rates will be reduced by an additional $26 million, for a total reduction of $79 million. The revenue reduction is net of the recovery of the amortization of the costs associated with the implementation of the Performance Excellence Process, a company wide review of our operations. The settlement agreement provides for some level of realignment of the existing rate structure by allocating a larger percentage share of the rate reduction to the commercial and industrial customer classes than to the residential customer classes. As part of the settlement agreement, a Choice Incentive Mechanism (CIM) was established with a base level of electric choice sales set at 3,400 GWh.
In accordance with the MPSC’s directive in Detroit Edison’s November 2004 rate order, in March 2005, Detroit Edison filed a joint application and testimony in its 2004 PSCR Reconciliation Case and its 2004 Net Stranded Cost Recovery Case. In September 2006, the MPSC issued an order recognizing $19 million of 2004 net stranded costs that required Detroit Edison to write off $112 million of 2004 net stranded costs. The MPSC order resulted in a $39 million reduction in the 2004 PSCR over-collection by allowing Detroit Edison to retain the benefit of third party wholesale sales required to support the electric Customer Choice program and to offset the recognition of the $19 million of 2004 stranded costs. The MPSC order also resulted in reductions to accrued interest on the 2004 and 2005 PSCR amounts of $15 million. The MPSC directed Detroit Edison to include the remaining 2004 PSCR over-collection amount and related interest in the 2005 PSCR Reconciliation which is in an under-collected position. The order resulted in a reduction of pre-tax income of approximately $58 million.
See Note 6 of the Notes to Consolidated Financial Statements.
Energy Assistance Programs
Energy assistance programs, funded by the federal government and the State of Michigan, remain critical to Detroit Edison’s ability to control its uncollectible accounts receivable and collections expenses. Detroit Edison’s uncollectible accounts receivable expense is directly affected by the level of government funded assistance its qualifying customers receive. We work continuously with the State of Michigan and others to determine whether the share of funding allocated to our customers is representative of the number of low-income individuals in our service territory.
Strategy and Competition
We strive to be the preferred supplier of electrical generation in southeast Michigan. We can accomplish this 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 continue to invest in our generating plants, which will improve both plant availability and operating efficiencies. We also are making capital investments in areas that have a positive impact on reliability and environmental compliance with the goal of high customer satisfaction.

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Our distribution operations focus on improving reliability, restoration time and the quality of customer service. We seek to lower our operating costs by improving operating efficiencies. Revenues from year to year will vary due to weather conditions, economic factors, regulatory events and other risk factors as discussed in the “Risk Factors” section that follows.
Effective January 2002, the electric Customer Choice program expanded in Michigan so that all of the Company’s electric customers can choose to purchase their electricity from alternative electric suppliers of generation services. Detroit Edison lost 6% of retail sales in 2006, 12% in 2005 and 18% of such sales in 2004 as a result of customers choosing to purchase power from alternative electric suppliers. Customers participating in the electric Customer Choice program consist primarily of industrial and commercial customers whose MPSC-authorized full service rates exceed their cost of service. Customers who elect to purchase their electricity from alternative electric suppliers by participating in the electric Customer Choice program have an unfavorable effect on our financial performance. The effect of lost sales due to the electric Customer Choice program has reduced our need for purchased power, and, when market conditions are favorable we sell power into the wholesale market, in order to lower costs to full service customers.
Detroit Edison acquires transmission services from ITC Transmission. By FERC order, rates charged by ITC Transmission to Detroit Edison were frozen through December 2004. Thereafter, rates became subject to normal FERC regulation. With the MPSC’s November 2004 final rate order, transmission costs are recoverable through Detroit Edison’s PSCR mechanism.
We are currently involved in a contract dispute with BNSF Railway Company that has been referred to arbitration. Under this contract, BNSF transports western coal east for Detroit Edison and the Coal Transportation and Marketing business. We have filed a breach of contract claim against BNSF for the failure to provide certain services that we believe are required by the contract. The arbitration hearing is scheduled for mid-2007. While we believe we will prevail on the merits in this matter, a negative decision with respect to the significant issues being heard in the arbitration could have an adverse effect on our business.
Competition in the regulated electric distribution business is primarily from the on-site generation of industrial customers and from distributed generation applications by industrial and commercial customers. We do not expect significant competition for distribution to any group of customers in the near term.
GAS UTILITY
Description
Our Gas Utility segment consists of MichCon and Citizens, natural gas utilities subject to regulation by the MPSC. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.3 million residential, commercial and industrial customers in the State of Michigan. MichCon also has subsidiaries involved in the gathering and transmission of natural gas in northern Michigan. MichCon operates one of the largest natural gas distribution and transmission systems in the United States. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.

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Revenue is generated by providing the following major classes of service: gas sales, end user transportation, intermediate transportation and gas storage.
                         
Revenue by Service                  
(in Millions)   2006     2005     2004  
Gas sales
  $ 1,541     $ 1,860     $ 1,435  
End user transportation
    135       134       119  
Intermediate transportation
    69       58       56  
Other
    104       86       72  
 
                 
Total Revenue
  $ 1,849     $ 2,138     $ 1,682  
 
                 
  Gas sales – Includes the sale and delivery of natural gas primarily to residential and small-volume commercial and industrial customers.
 
  End user transportation – Gas delivery service provided primarily to large-volume commercial and industrial customers. Additionally, the service is provided to residential customers, and small-volume commercial and industrial customers who have elected to participate in our Customer Choice program. End user transportation customers purchase natural gas directly from producers or brokers and utilize our pipeline network to transport the gas to their facilities or homes.
 
  Intermediate transportation – Gas delivery service provided to producers, brokers and other gas companies that own the natural gas, but are not the ultimate consumers. Intermediate transportation customers utilize our gathering and high-pressure transmission system to transport the gas to storage fields, processing plants, pipeline interconnections or other locations.
 
  Other – Includes revenues from gas storage, providing appliance maintenance, facility development and other energy-related services.
Our gas sales, end user transportation and intermediate transportation volumes, revenues and net income are impacted by weather. Given the seasonal nature of our business, revenues and net income are concentrated in the first and fourth quarters of the calendar year. By the end of the first quarter, the heating season is largely over, and we typically realize substantially reduced revenues and earnings in the second quarter and losses in the third quarter.
Our operations are not dependent upon a limited number of customers, and the loss of any one or a few customers would not have a material adverse effect on our Gas Utility segment.
Natural Gas Supply
Our gas distribution system has a planned maximum daily send-out capacity of 2.8 Bcf, with approximately 71% of the volume coming from underground storage for 2006. Peak-use requirements are met through utilization of our storage facilities, pipeline transportation capacity, and purchased gas supplies. Because of our geographic diversity of supply and our pipeline transportation and storage capacity, we are able to reliably meet our supply requirements. We believe natural gas supply and pipeline capacity will be sufficiently available to meet market demands in the foreseeable future.
We purchase natural gas supplies in the open market by contracting with producers and marketers, and we maintain a diversified portfolio of natural gas supply contracts. Supplier, producing region, quantity, and available transportation diversify our natural gas supply base. We obtain our natural gas supply from various sources in different geographic areas (Gulf Coast, Mid-Continent, Canada and Michigan) under agreements

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that vary in both pricing and terms. Gas supply pricing is generally tied to NYMEX and published price indices to approximate current market prices.
Properties
We own distribution, transmission and storage properties that are located in the State of Michigan. Our distribution system includes approximately 19,000 miles of distribution mains, approximately 1,188,000 service lines and approximately 1,321,000 active meters. We own approximately 2,600 miles of transmission lines that deliver natural gas to the distribution districts and interconnect our storage fields with the sources of supply and the market areas.
We own properties relating to four underground natural gas storage fields with an aggregate working gas storage capacity of approximately 124 Bcf. These facilities are important in providing reliable and cost-effective service to our customers. In addition, we sell storage services to third parties. Most of the company’s distribution and transmission property are located on property owned by others and used by the company through easements, permits or licenses. Substantially all of our property is subject to the lien of a mortgage.
We are directly connected to interstate pipelines, providing access to most of the major natural gas producing regions in the Gulf Coast, Mid-Continent and Canadian regions.
The company’s primary long-term transportation contracts are as follows:
                 
    Availability (MMcf/d)   Contract expiration
Panhandle Eastern Pipeline Company
    75       2009  
Trunkline Gas Company
    10       2009  
Viking Gas Transmission Company
    50       2010  
TransCanada PipeLines Limited
    50       2010  
Great Lakes Gas Transmission L.P.
    30       2011  
ANR Pipeline Company
    245       2011  
Vector Pipeline L.P.
    50       2012  
We own 840 miles of transportation and gathering pipelines in the northern lower peninsula of Michigan. We lease a portion of our pipeline system to the Vector Pipeline Partnership (an affiliate) through a capital lease arrangement. See Note 13 of the Notes to Consolidated Financial Statements.
Regulation
We are 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 other operating-related matters. We are subject to the requirements of other regulatory agencies with respect to safety, the environment and health.
In the late 1990s, the MPSC began an initiative designed to give all of Michigan’s natural gas customers added choices and the opportunity to benefit from lower gas costs resulting from competition. In 1999, the MPSC approved a comprehensive experimental three-year gas Customer Choice program that allowed an increasing number of customers to purchase natural gas from suppliers other than their local utility. In December 2001, the MPSC issued an order that continued the gas Customer Choice program on a permanent and expanding basis. The permanent gas Customer Choice program was phased in over a three-year period, with all customers having the option to choose their gas supplier by April 2004. Since MichCon continues to transport and deliver the gas to the participating customer premises at prices comparable to margins earned on gas sales, customers switching to other suppliers have little impact on MichCon’s earnings.

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In April 2005, the MPSC issued a final rate order which increased MichCon’s base rates by $61 million annually effective April 29, 2005.
See Note 6 of the Notes to the Consolidated Financial Statements.
Energy Assistance Program
Energy assistance programs, funded by the federal government and the State of Michigan, remain critical to MichCon’s ability to control its uncollectible accounts receivable and collections expenses. MichCon’s uncollectible accounts receivable expense is directly affected by the level of government funded assistance its qualifying customers receive. We work continuously with the State of Michigan and others to determine whether the share of funding allocated to our customers is representative of the number of low-income individuals in our service territory.
Strategy and Competition
Our strategy is to be a preferred provider of natural gas in Michigan. As a result of more efficient furnaces and appliances, and customer conservation due to high natural gas prices, we expect future sales volumes to remain at current levels or slightly decline. We continue to provide energy-related services that capitalize on our expertise, capabilities and efficient systems. We continue to focus on lowering our operating costs by improving operating efficiencies.
Competition in the gas business primarily involves other natural gas providers, as well as providers of alternative fuels and energy sources. The primary focus of competition for end user transportation is cost and reliability. Some large commercial and industrial customers have the ability to switch to alternative fuel sources such as coal, electricity, oil and steam. If these customers were to choose an alternative fuel source, they would not have a need for our end-user transportation service. In addition, some of these customers could bypass our pipeline system and have their gas delivered directly from an interstate pipeline. We compete against alternative fuel sources by providing competitive pricing and reliable service, supported by our storage capacity.
Our extensive transmission pipeline system has enabled us to market 500 to 600 Bcf annually for intermediate transportation services for Michigan gas producers, marketers, distribution companies and other pipeline companies. We operate in a central geographic location with connections to major Mid-western interstate pipelines that extend throughout the Midwest, eastern United States and eastern Canada.
NON-UTILITY OPERATIONS
Coal and Gas Midstream
Description
Coal and Gas Midstream primarily consists of the operations of Coal Transportation and Marketing, and the Pipelines, Processing and Storage businesses.
Coal Transportation and Marketing
Coal Transportation and Marketing provides fuel, transportation, and equipment management services tailored to the individual requirements of each customer. We specialize in minimizing fuel costs and maximizing reliability of supply for energy-intensive customers. Our external customers include electric utilities, merchant power producers, integrated steel mills and large industrial companies with significant energy requirements. Additionally, we participate in coal trading, coal-to-power tolling transactions and the purchase and sale of emissions credits. Coal-to-power tolling is another facet of the trading function, where we buy and arrange transportation of coal to a power plant that has excess generating capacity.

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The plant then burns the coal and produces electricity for a fee and returns it via the grid to DTE Energy Trading, which uses the power to fulfill contracts or meet market needs.
                         
(in Millions)   2006   2005   2004
Tons of Coal Shipped (1)
    34       42       40  
 
(1)   Includes intercompany transactions of 14 tons, 20 tons, and 18 tons in 2006, 2005, and 2004, respectively.
Pipelines, Processing and Storage
The Pipelines, Processing and Storage business owns and manages a network of natural gas transmission pipelines, storage facilities and gas processing facilities. We have a partnership interest in Vector Pipeline (Vector), an interstate transmission pipeline, which connects Michigan to Chicago and Ontario. We specialize in providing natural gas storage and transportation services in the Midwest and Northeast. We have interests in six processing plants that extract carbon dioxide from Antrim gas production in northern Michigan, making it suitable for transportation to nearby customers. Additionally, we have storage capacity capable of storing up to 75.7 Bcf in natural gas storage fields located in Michigan. The Washington 10 storage facility is a 66 Bcf high deliverability storage field having bi-directional interconnections with Vector Pipeline and MichCon providing customers access to the Chicago, Michigan and Ontario hubs.
Properties
The Pipelines, Processing and Storage business holds the following property:
                 
Property Classification   % Owned   Description   Location
Pipelines
               
Vector Pipeline
    40 %   348-mile pipeline with 1,000 MMcf per day capacity   Midwest
Processing Plants
    90 %   197 MMcf per day capacity   Northern Michigan

Storage
               
Washington 28
    50 %   9.7 Bcf of storage capacity   Washington Twp, MI
Washington 10
    100 %   66 Bcf of storage capacity   Washington Twp, MI
The assets of these businesses are complementary with other DTE Energy assets. Pursuant to an operating agreement, MichCon provides physical operations, maintenance and technical support for the Washington 28 and Washington 10 storage facilities.
Strategy and Competition
Our Coal Transportation and Marketing business is one of the leading North American coal marketers. We have a reputation as being an efficient manager of transportation assets. Trends such as railroad and mining consolidation and the lack of certainty in developing new mines by many mining firms could have an impact on how we compete in the future. We will continue to work with suppliers and the railroads to promote secure and competitive access to coal to meet the energy requirements of our customers. We will seek to build our capacity to transport greater amounts of western coal and to expand into coal terminals. We are currently involved in a contract dispute with BNSF Railway Company that has been referred to arbitration. Under this contract, BNSF transports western coal east for Detroit Edison and the Coal Transportation and Marketing business. We have filed a breach of contract claim against BNSF for the failure to provide certain services that we believe are required by the contract. The arbitration hearing is scheduled for mid-2007. While we believe we will prevail on the merits in this matter, a negative decision with respect to the significant issues being heard in the arbitration could have an adverse effect on our ability to grow the Coal Transportation and Marketing business as currently contemplated.

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The Pipelines, Processing and Storage business focuses on asset development opportunities in the Midwest-to-Northeast region to supply natural gas to meet growing demand. We expect much of the growth in the demand for natural gas in the U.S. to occur within the Mid-Atlantic and New England regions. These regions currently lack the pipeline and gas storage infrastructure necessary to deliver gas volumes to meet growing demand. Vector is an interstate pipeline that is filling a large portion of that need, and is complemented by our Michigan storage facilities. Vector received FERC approval in October 2006 for a 200 MMcf per day expansion of long-haul capacity scheduled to be in service by November 2007. In April 2006, the Washington 10 storage facility expanded working capacity from 51.4 to 66 Bcf. In October 2006, we purchased the lessor interest in the 66 Bcf Washington 10 gas storage field. Prior to the purchase, we leased the storage rights. Another opportunity is Millennium Pipeline in New York, in which we have a 26.25% interest. In December 2006, Millennium Pipeline received FERC approval for construction and operation and is expected to be in service in late 2008. The Millennium Pipeline will be able to transport up to 525 MMcf per day. The gas supply for Millennium could be sourced from Michigan storage facilities or from Vector Pipeline for consumption in the Northeast U.S.
Unconventional Gas Production
Description
Our Unconventional Gas Production business is engaged in natural gas exploration, development and production primarily within the Antrim shale in the northern lower peninsula of Michigan and the Barnett shale in north Texas. We are an experienced operator in the Antrim shale where we manage one of the industry’s largest inventories of proved gas shale reserves. We continue to develop properties in both areas as we explore monetization alternatives.
During 2006, we invested $186 million acquiring, testing, developing and producing our Antrim and Barnett shale acreage. In 2006, we added proved reserves of 219 Bcfe in both the Antrim and Barnett shales, resulting in year end total proved reserves of 616 Bcfe. The Barnett and Antrim shale wells yielded 4.1 Bcfe and 21.5 Bcfe of production, respectively, in 2006 for a total of 25.6 Bcfe. Barnett shale leasehold acres increased to 89,808 gross acres (80,530 net of interest of others) after reduction by opportunistic sales of 11,193 acres. We drilled a total of 206 development wells (165.2 net of interest of others) including 64 wells (54.8 net of interest of others) in the Barnett shale acreage with a success rate of 100% in 2006. Included were 4 test wells (3.2 net of interest of others) in unproved areas of the southern portion of our Barnett shale acreage holdings. Production commenced in the Bosque and Hill Counties of Texas in 2006. Testing of Barnett’s southern acreage is ongoing and will continue in 2007.
Properties
Unconventional Gas Production owns interests in the following producing wells and acreage as of December 31:

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    2006     2005     2004  
    Gross     Net(1)     Gross     Net(1)     Gross     Net (1)  
Producing Wells and Acreage
                                               
Producing Wells (2)
                                               
Antrim shale
    2,148       1,700       2,010       1,630       1,878       1,523  
Barnett shale
    123       110       65       55       5       1  
 
                                   
 
    2,271       1,810       2,075       1,685       1,883       1,524  
 
                                   
 
                                               
Developed Lease Acreage (3)
                                               
Antrim shale
    283,007       228,232       278,789       217,643       266,064       213,959  
Barnett shale
    17,965       16,045       15,524       14,367       1,262       316  
 
                                   
 
    300,972       244,277       294,313       232,010       267,326       214,275  
 
                                   
 
                                               
Undeveloped Lease Acreage (4)
                                               
Antrim shale
    80,380       66,184       86,028       73,056       92,328       79,025  
Barnett shale
    71,842       64,485       72,280       61,627       54,530       48,541  
 
                                   
 
    152,222       130,669       158,308       134,683       146,858       127,566  
 
                                   
 
(1)   Excludes the interest of others.
 
(2)   Producing wells is the number of wells that are found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
 
(3)   Developed lease acreage is the number of acres that are allocated or assignable to productive wells or wells capable of production.
 
(4)   Undeveloped lease acreage is the number of acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.
Strategy and Competition
We manage and operate our Antrim and Barnett shale gas properties to maximize returns on investment and increase earnings with the overriding goal of optimizing the cost of producing reserves and adding additional proved reserves. A long-term fixed price obligation that fixed the price of gas sold at $3.33 for 1.8 Bcf of Antrim shale production expired in 2006. This creates pricing opportunities and we have and will continue to remarket Antrim shale gas production at current higher market rates.
Additional long-term fixed price obligation data for the next five years follows:
                                         
    2007   2008   2009   2010   2011
Long-term fixed price obligations
                                       
 
                                       
Antrim
                                       
Volume- Bcf
    17.6       16.2       15.0       15.0       11.9  
Price- $/Mcf
  $ 3.19     $ 3.74     $ 3.48     $ 3.59     $ 3.70  
 
                                       
Barnett
                                       
Volume- Bcf
    1.8       1.3       1.1       0.5        
Price- $/Mcf
  $ 8.45     $ 8.15     $ 7.73     $ 7.29     $  
Current natural gas prices and successes within the Barnett shale are resulting in more capital being invested into the region. This competition for opportunities, goods and services increases costs. However, our experience in the Antrim shale and our experienced Barnett shale personnel provide an advantage in addressing potential cost increases.
In 2007, we expect to drill 130 to 145 wells in the Antrim shale and 50 to 55 wells in the Barnett shale. Combined investment for both areas is expected to be approximately $150 million to $170 million during 2007. Successful testing on unproved acreage may yield additional significant investment opportunities.
We are exploring the sale of a portion of our Unconventional Gas Production assets which will allow us to monetize value from our more mature holdings, while retaining the ability to benefit from the upside of our earlier stage holdings.

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Power and Industrial Projects
Description
Power and Industrial Projects is comprised primarily of projects that deliver utility-type services to industrial, commercial and institutional customers, and biomass energy projects. We provided utility-type services using project assets usually located on the customers’ premises in the steel, automotive, pulp and paper, airport and other industries. These services include pulverized coal and petroleum coke supply, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. We own and operate three gas-fired peaking electric generating plants and a biomass-fired electric generating plant and operate one additional gas-fired power plant under contract. Additionally, we own a gas-fired peaking electric generating plant that was taken out of service in September 2006. We develop, own and operate landfill gas recovery systems throughout the United States. We produce metallurgical coke from two coke batteries. The production of coke from our coke batteries generates production tax credits (assuming no phase-out).
Properties
The following are significant Power and Industrial Projects:
                 
Facility   Location   % Owned   Service Type
Steel
               
PCI Enterprises, Inc.
  River Rouge, MI     100 %   Pulverized Coal
DTE Sparrows Point
  Sparrows Point, MD     100 %   Pulverized Coal
EES Coke Battery, LLC
  River Rouge, MI     100 %   Metallurgical Coke Supply
Indiana Harbor Coke Co., LP
  East Chicago, IN     5 %   Metallurgical Coke Supply
 
               
Automotive
             
DTE Energy Center
  Various sites in MI, IN, OH     50 %   Electric Distribution, Chiller Water, Waste Water, Compressed Air, Mist and Dust Collectors
DTE Northwind
  Detroit, MI     100 %   Steam and Chilled Water
DTE Moraine
  Moraine, OH     100 %   Compressed Air
DTE Tonawanda
  Tonawanda, NY     100 %   Chilled and Waste Water
 
              Steam, Cooling Tower Water,
Defiance Energy
  Defiance, OH     100 %   Chilled Water, Compressed Air
Heritage
  Dearborn, MI     100 %   Electric Distribution
Lordstown Energy
  Lordstown, OH     100 %   Steam, Chilled Water, Compressed Air and Reverse Osmosis Water
 
               
Pulp and Paper
               
Mobile Energy Services
  Mobile, AL     50 %   Electric Generation and Steam
Tembec
  St. Francisville, LA     100 %   Electric Generation and Steam
 
               
Airport
               
Metro Energy
  Romulus, MI     100 %   Electricity, Hot and Chilled Water
Pittsburgh
  Pittsburg, PA     100 %   Hot and Chilled Water
 
               
Other Industries
               
DTE PetCoke
  Vicksburg, MS     100 %   Pulverized Petroleum Coke
Pursuant to an operating agreement with PCI Enterprises, Inc., Detroit Edison provides operations and maintenance services for the pulverized coal facility located at Detroit Edison’s River Rouge power plant.
Production tax credits, related to one coke battery that expired in 2002, were reinstated for the years 2006 through 2009. The coke battery facilities produce coke that is used in blast furnaces within the steel industry.

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(Dollars in Millions)   2006     2005     2004  
Production Tax Credits Generated
                       
Coke Batteries:
                       
Allocated to DTE Energy
  $ 6     $ 2     $ 2  
 
                 
Non-Utility Power Generation
Description
We operate peaking, gas-fired and biomass-fired electric generating plants.
Properties
The following are significant properties operated by Non-Utility Power Generation:
                     
                Capacity
Facility   Location   % Owned   (in MW)
DTE Georgetown
  Indianapolis, IN     100 %     80  
DTE River Rouge (1)
  River Rouge, MI     100 %     240  
Crete Energy Ventures
  Crete, IL     50 %     320  
DTE East China
  East China Twp, MI     100 %     320  
Woodland Biomass
  Woodland, CA     99 %     25  
 
                   
 
                985  
 
                   
 
(1)   No longer in service effective September 2006.
Production tax credits are available at one Non-Utility Power Generation facility. The facility produces electricity using renewable resources.
                         
(Dollars in Millions)   2006     2005     2004  
Production Tax Credits Generated
                       
Allocated to DTE Energy
  $ 1     $     $  
 
                 
Landfill Gas Recovery
We develop, own and operate landfill gas recovery systems in the U.S. Landfill gas, a byproduct of solid waste decomposition, is composed of approximately equal portions of methane and carbon dioxide. We develop landfill gas recovery systems that capture the gas and provide local utilities, industry and consumers with an opportunity to use a competitive, renewable source of energy, in addition to providing environmental benefits by reducing greenhouse gas emissions. We also co-own, with the Coal Transportation and Marketing segment, a coal mine methane gathering system and gas processing facility in southern Illinois. This processed methane is sold into the natural gas transmission system. Many of our facilities generate production tax credits that will expire at the end of 2007.
Landfill gas recovery has operations in 12 states.
                         
(Dollars in Millions)   2006   2005   2004
Landfill Sites
    26       32       29  
Gas Produced (in Bcf)
    22.9       20.2       23.2  
Tax Credits Generated (1)
  $ 5     $ 8     $ 8  
 
(1)   DTE Energy’s portion of tax credits generated.

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Strategy and Competition
Power and Industrial Projects will continue leveraging its extensive energy-related operating experience and project management capability to develop and grow our on-site energy business. We also will continue to pursue opportunities to provide asset management and operations services to third parties.
We anticipate building around our core strengths in the markets where we operate. In determining the markets in which to compete, we examine closely the regulatory and competitive environment, the number of competitors and our ability to achieve sustainable margins. We plan to maximize the effectiveness of our inter-related businesses as we expand from our current regional focus. As we pursue growth opportunities, our first priority will be to achieve value-added returns.
We intend to focus on the following areas for growth:
    Providing operating services to owners of industrial and power plants;
 
    Acquiring and developing solid fuel-fired power plants and landfill gas recovery facilities; and
 
    Expanding energy projects.
We are exploring the combination of a sale of an equity interest in, and recapitalization of, some of the assets of the Power and Industrial Projects business, including the sale or restructuring of the power generation assets. In February 2007, we entered into an agreement to sell our Georgetown peaking electric generating facility. The sale is subject to receipt of regulatory approval and is expected to close in the second half of 2007.
Energy Trading
Description
Energy Trading focuses on physical power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s power plants and the optimization of contracted natural gas pipelines and storage capacity positions. Our customer base is predominantly utilities, local distribution companies, large industrials, and other marketing and trading companies. We enter into derivative financial instruments as part of our marketing and hedging activities. Most of the derivative financial instruments are accounted for under the mark-to-market method, which results in earnings recognition of unrealized gains and losses from changes in the fair value of the derivatives. We utilize forwards, futures, swaps and option contracts to mitigate risk associated with our marketing and trading activity as well as for proprietary trading within defined risk guidelines. Energy Trading provides commodity risk management services to the other businesses within DTE Energy.
Strategy and Competition
Our strategy for our trading business is to deliver value-added services to our customers. We seek to manage this business in a manner consistent with and complementary to the growth of our other business segments. We focus on physical marketing and the optimization of our portfolio of energy assets. We compete with electric and gas marketers, traders, utilities and other energy providers. We have risk management and credit processes to monitor and mitigate risk. We are exploring strategic options for the energy trading business.
Synthetic Fuel
Description
Synfuel plants chemically change coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. 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. Production tax credits are provided for the production and sale of solid synthetic fuel produced from coal and are available through December 31, 2007. The synthetic fuel plants generate operating losses which we expect to be offset by production tax credits. The value of a production tax credit is adjusted annually by an inflation factor and published annually by the Internal Revenue Service (IRS) and is reduced, or eliminated, if the Reference Price of a barrel of oil exceeds certain thresholds.
We are the operator of nine synthetic fuel production facilities throughout the United States. On May 12, 2006, we idled production at all nine of the synthetic fuel facilities. The decision to idle synfuel production was driven by the level and volatility of oil prices at that time. During the idle period, we took various steps to reduce our oil price exposure, including, renegotiation of a significant number of commercial agreements. Beginning September 5, 2006 through October 4, 2006, we resumed production

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at each of the nine synfuel facilities due to these amended commercial agreements and declines in the level of oil prices.
Since 2002, we have sold interests in all nine of our synfuel plants, ranging from a 49%-99% share in each, or approximately 91% of our total production capacity. We consolidate these projects due to our controlling influence and continuing involvement.
                         
(Dollars in Millions)   2006     2005     2004  
Production Tax Credits Generated
                       
Synfuel Plants
                       
Allocated to DTE Energy
  $ 23     $ 45     $ 29  
Allocated to partners
    260       562       411  
 
                 
 
  $ 283     $ 607     $ 440  
 
                 
Properties
The following are our synthetic fuels projects:
                         
Facility   Location   % Owned   Industry Served
DTE Red Mountain, LLC
  Tarrant, AL     51 %   Foundry Coke/Steel
DTE Belews Creek, LLC
  Belews Creek, NC     1 %   Utility
DTE Utah Synfuels, LLC
  Price, UT     1 %   Industrial/Utility
DTE Indy Coke, LLC
  Moundsville, WV     1 %   Utility
DTE Clover, LLC
  Bledsoe, KY     5 %   Utility
DTE Smith Branch, LLC
  Pineville, WV     1 %   Steel/Export
DTE River Hill, LLC
  Clover, VA     51 %   Utility
DTE Buckeye, LLC (2 plants)
  Cheshire, OH     1 %   Utility
Strategy and Competition
Due to our hedging strategy implemented in 2006, we expect to continue to operate the synfuel plants through December 31, 2007, when synfuel-related production tax credits expire.
CORPORATE & OTHER
Description
Corporate & Other includes various corporate staff functions. Because these functions support the entire Company, their costs are allocated to the various segments based on services utilized. Therefore, the effect of the allocation on each segment can vary from year to year. Additionally, Corporate & Other holds certain non-utility debt, assets held for sale and investments in energy-related companies and funds.

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Strategy and Competition
Our energy-related investment strategy is to create a profitable portfolio by investing in companies or funds that facilitate the creation of new businesses, expand growth opportunities for existing businesses or enable performance improvements in our existing businesses.
ENVIRONMENTAL MATTERS
We are subject to extensive environmental regulation. Additional costs may result as the effects of various substances 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. The following table summarizes our estimated significant future environmental expenditures:
                                 
(in Millions)   Electric     Gas     Non- Utility     Total  
Air
  $ 2,185     $     $     $ 2,185  
Water
    53             14       67  
MGP Sites
    4       41             45  
Other Clean Up Sites
    12       1             13  
 
                       
Estimated total future expenditures
  $ 2,254     $ 42     $ 14     $ 2,310  
 
                       
 
                               
Estimated 2007 expenditures
  $ 234     $ 5     $ 14     $ 253  
 
                       
Air - Detroit Edison is subject to EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. In March 2005, EPA issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. The cost to address environmental air issues is estimated through 2018.
Water – In response to an EPA regulation, Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of studies to be conducted over the next one to two years, Detroit Edison may be required to perform some mitigation activities, including, the possible installation of additional control technologies to reduce the environmental impact of the intake structures. However, a recent court decision remanded back to the EPA several provisions of the federal regulation resulting in a delay in complying with the regulation.
MGP Sites - Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. The facilities, which produced gas for heating and other uses, have been designated as MGP sites. Gas Utility owns, or previously owned, fifteen such former MGP sites. In addition to the MGP sites, the company is also in the process of cleaning up other contaminated sites. As a result of these determinations, we have recorded liabilities related to these sites. Cleanup activities associated with these sites will be conducted over the next several years.
Detroit Edison conducted remedial investigations at contaminated sites, including two MGP sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is expected to be incurred over the next several years. In addition, Detroit Edison will be making capital improvements to the ash landfill in 2007.

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Non-utility – Our non-utility affiliates are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants. We are in the process of installing new environmental equipment at our coke battery facility in Michigan. We expect the project to be completed within one year. Our non-utility affiliates are substantially in compliance with all environmental requirements.
Greater details on environmental issues are provided in the following Notes to Consolidated Financial Statements:
         
Note
  Title  
  6
  Regulatory Matters
  7
  Nuclear Operations
EMPLOYEES
The following table shows our employees as of December 31, 2006:
                         
    Represented   Non-represented   Total
Detroit Edison
    3,724       3,493       7,217  
MichCon
    1,386       707       2,093  
Other
    308       909       1,217  
 
                       
Total
    5,418       5,109       10,527  
 
                       
There are several bargaining units for our represented employees. Approximately 3,245 of our represented employees are under contracts that expire in June 2007 and 970 employees are under contracts that expire in October 2007. The contracts of the remaining represented employees expire at various dates in 2008 and 2009.
EXECUTIVE OFFICERS OF DTE ENERGY
                 
            Present  
            Position  
Name   Age (1)   Present Position   Held Since  
Anthony F. Earley, Jr.
  57   Chairman of the Board and Chief Executive Officer     8-1-98  
Gerard M. Anderson
  48   Chief Operating Officer and     10-31-05  
 
      President     6-23-04  
Stephen E. Ewing (2)
  62   Vice Chairman, DTE Energy     10-31-05  
 
      President and Chief Operating Officer, MichCon     4-28-05  
Robert J. Buckler
  57   President and Chief Operating Officer, Detroit Edison     10-31-05  
 
      Group President, DTE Energy     5-31-05  
David E. Meador
  49   Executive Vice President and Chief Financial Officer     6-23-04  
Lynne Ellyn
  55   Senior Vice President and Chief Information Officer     12-31-01  
Paul C. Hillegonds
  57   Senior Vice President     5-16-05  
Ron A. May
  55   Senior Vice President     1-22-04  
Bruce D. Peterson
  50   Senior Vice President and General Counsel     6-25-02  
Gerardo Norcia
  44   Executive Vice President, MichCon     10-31-05  
Larry E. Steward
  54   Vice President     1-15-01  
Peter B. Oleksiak
  40   Vice President and Controller     12-5-05  
Sandra K. Ennis
  50   Corporate Secretary     8-4-05  
 
(1)   As of December 31, 2006
 
(2)   Retired from the company effective December 31, 2006
Under our Bylaws, the officers of DTE Energy are elected annually by the Board of Directors at a meeting held for such purpose, each to serve until the next annual meeting of directors or until their respective successors are chosen and qualified. With the exception of Messrs. Hillegonds, Peterson and

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Norcia, all of the above officers have been employed by DTE Energy in one or more management capacities during the past five years.
Paul C. Hillegonds was elected Senior Vice President effective May 16, 2005. Mr. Hillegonds was president of Detroit Renaissance for eight years prior to joining DTE Energy.
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.
Gerardo Norcia was elected Executive Vice President, MichCon on October 31, 2005. Mr. Norcia was President, DTE Gas Storage, Pipelines and Processing since joining DTE Energy on November 4, 2002. He was a vice president of Union Gas prior to joining DTE Energy.
Pursuant to Article VI of our Articles of Incorporation, directors of DTE Energy will not be personally liable to the Company or its shareholders in the performance of their duties to the full extent permitted by law.
Article VII of our Articles of Incorporation provides that each current or former director or officer of DTE Energy, or each current and former employee or agent of the Company or a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise (including the heirs, executors, administrators or estate of such person), shall be indemnified by the Company to the full extent permitted by the Michigan Business Corporation Act or any other applicable laws as presently or hereafter in effect. In addition, we have entered into indemnification agreements with all of our officers and directors; these agreements set forth procedures for claims for indemnification as well as contractually obligating us to provide indemnification to the maximum extent permitted by law.
We and our directors and officers in their capacities as such are insured against liability for alleged wrongful acts (to the extent defined) under eight insurance policies providing aggregate coverage in the amount of $185 million.
Item 1A. Company Risk Factors
There are various risks associated with the operations of DTE Energy’s utility and non-utility businesses. To provide a framework to understand the operating environment of DTE Energy, we are providing a brief explanation of the more significant risks associated with our businesses. Although we have tried to identify and discuss key risk factors, others could emerge in the future. Each of the following risks could affect our performance.
Our ability to utilize production tax credits may be limited. To reduce U.S. dependence on imported oil, the Internal Revenue Code provides production tax credits as an incentive for taxpayers to produce fuels from alternative sources. We have generated production tax credits from the synfuel, coke battery, landfill gas recovery and gas production operations. We have received favorable private letter rulings on all of the synfuel facilities. All production tax credits taken after 2003 are subject to audit by the Internal Revenue Service (IRS). If our production tax credits were disallowed in whole or in part as a result of an IRS audit, there could be additional tax liabilities owed for previously recognized tax credits that could significantly impact our earnings and cash flows. The value of future credits generated may be affected by potential legislation. Moreover, the opportunity to earn additional production tax credits related to the generation of synfuels and recovery of landfill gas will expire at the end of 2007. The combination of IRS audits of production tax credits, supply and demand for investment in credit producing activities and potential legislation could have an impact on our earnings and cash flows. We have also provided certain guarantees and indemnities in conjunction with the sales of interests in the synfuel facilities.
This incentive provided by production tax credits is not deemed necessary if the price of oil increases and provides significant market incentives for the production of these fuels. As such, the tax credit in a given year is reduced if the Reference Price of oil within that year exceeds a threshold price. The Reference Price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil. We project the yearly average wellhead price per barrel of oil for the year to be approximately $6 lower than the NYMEX price for light, sweet crude oil. The threshold price at which the credit begins to

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be reduced was set in 1980 and is adjusted annually for inflation. For 2006, we estimate the threshold price at which the tax credit would begin to be reduced is $55 per barrel and would be completely phased out if the Reference Price reached $69 per barrel. As of December 31, 2006, the average NYMEX daily closing price of a barrel of oil was approximately $66 for 2006, equating to an estimated Reference Price of $60, which we estimate to be within the phase-out range. To mitigate the effect of a potential phase out and minimize operating losses, on May 12, 2006 we idled production at all nine of the synfuel facilities. The decision to idle synfuel production was driven by the level and volatility of oil prices at that time. Beginning September 5, 2006 through October 4, 2006, we resumed production at each of the nine synfuel facilities due to declines in the level of oil prices.
Our estimates of gas reserves are subject to change. We cannot assure that our estimates of our Antrim and Barnett gas reserves are accurate. Estimates of proved gas reserves and the future net cash flows attributable to those reserves are prepared by independent engineers. There are numerous uncertainties inherent in estimating quantities of proved gas reserves and cash flows attributable to such reserves, including factors beyond our control and that of our engineers. Reserve engineering is a subjective process of estimating underground accumulations of gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding expenditures for future development and exploration activities, and of engineering and geological interpretation and judgment. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based upon production history, development and exploration activities and prices of gas. Actual future production, revenue, taxes, development expenditures, operating expenses, underlying information, quantities of recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and underlying information we used. In addition, different reserve engineers may make different estimates of reserves and cash flows based on the same available data.
Michigan’s electric Customer Choice program is negatively impacting our financial performance. The electric Customer Choice program, as originally contemplated in Michigan, anticipated an eventual transition to a totally deregulated and competitive environment where customers would be charged market-based rates for their electricity. The State of Michigan currently experiences a hybrid market, where the MPSC continues to regulate electric rates for our customers, while alternative electric suppliers charge market-based rates. In addition, such regulated electric rates for certain groups of our customers exceed the cost of service to those customers. Due to distorted pricing mechanisms during the initial implementation period of electric Customer Choice, many commercial customers chose alternative electric suppliers. Recent MPSC rate orders have removed some of the pricing disparity. Recent higher wholesale electric prices have also resulted in some former electric Customer Choice customers migrating back to Detroit Edison for electric generation service. Even with the electric Customer Choice-related rate relief received in Detroit Edison’s 2004 and 2005 orders, there continues to be considerable financial risk associated with the electric Customer Choice program. Electric Customer Choice migration is sensitive to market price and bundled electric service price increases. The hybrid market in Michigan also causes uncertainity as it relates to investment in new generating capacity.
Weather significantly affects operations. Deviations from normal hot and cold weather conditions affect our earnings and cash flow. Mild temperatures can result in decreased utilization of our assets, lowering income and cash flow. Damage due to ice storms, tornadoes, or high winds can damage our infrastructure and require us to perform emergency repairs and incur material unplanned expenses. The expenses of storm restoration efforts may not be recoverable through the regulatory process.
We are subject to rate regulation. Electric and gas rates for our utilities are set by the MPSC and the FERC and cannot be increased without regulatory authorization. We may be impacted by new regulations or interpretations by the MPSC, the FERC or other regulatory bodies. New legislation, regulations or interpretations could change how our business operates, impact our ability to recover costs through rate increases or require us to incur additional expenses.

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Our non-utility operations may not perform to our expectations. We rely on our non-utility operations for a significant portion of our earnings. If our current and contemplated non-utility investments do not perform at expected levels, we could experience diminished earnings potential and a corresponding decline in our shareholder value.
We rely on cash flows from subsidiaries. Cash flows from our utility and non-utility 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 interest and dividends would be restricted.
Adverse changes in our credit ratings may negatively affect us. Increased scrutiny of the energy industry and regulatory changes, as well as changes in our economic performance, could result in credit agencies reexamining our credit rating. While credit ratings reflect the opinions of the credit agencies issuing such ratings and may not necessarily reflect actual performance, a downgrade in our credit rating could restrict or discontinue our ability to access capital markets at attractive rates and increase our borrowing costs. In addition, a reduction in credit rating may require us to post collateral related to various trading contracts, which would impact our liquidity.
Our ability to access capital markets at attractive interest rates is important. Our ability to access capital markets is important to operate our businesses. Heightened concerns about the energy industry, the level of borrowing by other energy companies and the market as a whole could limit our access to capital markets. Changes in interest rates could increase our borrowing costs and negatively impact our financial performance.
Regional and national economic conditions can have an unfavorable impact on us. Our businesses follow the economic cycles of the customers we serve. Should national or regional economic conditions decline, reduced volumes of electricity and gas we supply will result in decreased earnings and cash flow. Economic conditions in our service territory also impact our collections of accounts receivable and financial results.
Environmental laws and liability may be costly. We are subject to numerous environmental regulations. These regulations govern air emissions, water quality, wastewater discharge, and disposal of solid and hazardous waste. Compliance with these regulations can significantly increase capital spending, operating expenses and plant down times. These laws and regulations require us to seek a variety of environmental licenses, permits, inspections and other regulatory approvals. We may also incur liabilities as a result of potential future requirements to address the climate change issue. The regulatory environment is subject to significant change; therefore, we cannot predict how future issues may impact the company.
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 potentially responsible parties.
Since there can be no assurances that environmental costs may be recovered through the regulatory process, our financial performance may be negatively impacted as a result of environmental matters.
Operation of a nuclear facility subjects us to risk. Ownership of an operating nuclear generating plant subjects us to significant additional risks. These risks include among others, plant security, environmental regulation and remediation, and operational factors that can significantly impact the performance and cost of operating a nuclear facility. While we maintain insurance for various nuclear-related risks, there can be no assurances that such insurance will be sufficient to cover our costs in the event of an accident or business interruption at our nuclear generating plant, which may affect our financial performance.

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The supply and price of fuel and other commodities may impact our financial results. We are dependent on coal for much of our electrical generating capacity. Price fluctuations and fuel supply disruptions could have a negative impact on our ability to profitably generate electricity. Our access to natural gas supplies is critical to ensure reliability of service for our utility gas customers. We have hedging strategies in place to mitigate negative fluctuations in commodity supply prices, but there can be no assurances that our financial performance will not be negatively impacted by price fluctuations. The price of natural gas also impacts the market for our non-utility businesses that compete with utilities and alternative electric suppliers.
A work interruption may adversely affect us. Unions represent approximately 5,400 of our employees. A union choosing to strike as a negotiating tactic would have an impact on our business. We are unable to predict the effects a work stoppage would have on our costs of operation and financial performance.
Unplanned power plant outages may be costly. Unforeseen maintenance may be required to safely produce electricity or comply with environmental regulations. As a result of unforeseen maintenance, we may be required to make spot market purchases of electricity that exceed our costs of generation. Our financial performance may be negatively affected if we are unable to recover such increased costs.
Michigan tax reform may be costly. The State of Michigan is experiencing a revenue shortfall. We are a significant taxpayer in the State of Michigan. The legislature is expected to change the tax laws in 2007, and we could face increased taxes.
We may not be fully covered by insurance. While we have a comprehensive insurance program in place to provide coverage for various types of risks, catastrophic damage as a result of acts of God, terrorism, war or a combination of significant unforeseen events could impact our operations and economic losses might not be covered in full by insurance.
Terrorism could affect our business. Damage to downstream infrastructure or our own assets by terrorism would impact our operations. We have increased security as a result of past events and further security increases are possible.
Our participation in energy trading markets subjects us to risk. Events in the energy trading industry have increased the level of scrutiny on the energy trading business and the energy industry as a whole. In certain situations we may also be required to post collateral to support trading operations. We have established risk policies to manage the business.
Failure to successfully implement new processes and information systems could interrupt our operations. Our businesses depend on numerous information systems for operations and financial information and billings. We are in the midst of a multi-year Company-wide initiative to improve existing processes and implement new core information systems. We launched the first phase of our Enterprise Business Systems project in 2005. Additional phases of implementation are planned for 2007. Failure to successfully implement new processes and new core information systems could interrupt our operations.
Benefits of the Performance Excellence Process to the Company could be less than the Company has projected. In 2005, we initiated a company-wide review of our operations called the Performance Excellence Process with the overarching goal to become more competitive by reducing costs, eliminating waste and optimizing business processes while improving customer service. Actual results achieved through this process could be less than the Company’s expectations.
The inability to consummate any strategic transactions for our non-utility operations could affect our expected cash flows. As part of a strategic review of our non-utility operations, we are considering various actions including the sale, restructuring or recapitalization of various non-utility businesses. If we are not able to consummate any strategic transactions on favorable terms or timing, our expected cash flows could be lower than anticipated.

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Item 1B. Unresolved Staff Comments
None.
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 Consolidated Financial Statements:
     
     Note   Title
 
    6
  Regulatory Matters
    7
  Nuclear Operations
   15
  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 2006.
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed on the New York Stock Exchange, which is the principal market for such stock. 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
Year   Quarter   High   Low   Per Share
2006
  First   $ 44.23     $ 40.00     $ 0.515  
 
  Second   $ 41.91     $ 38.77     $ 0.515  
 
  Third   $ 43.63     $ 40.26     $ 0.515  
 
  Fourth   $ 49.24     $ 41.37     $ 0.530  
 
                           
2005
  First   $ 46.99     $ 42.40     $ 0.515  
 
  Second   $ 48.31     $ 44.40     $ 0.515  
 
  Third   $ 48.22     $ 44.11     $ 0.515  
 
  Fourth   $ 46.65     $ 41.39     $ 0.515  
At December 31, 2006, there were 177,138,060 shares of our common stock outstanding. These shares were held by a total of 89,984 shareholders of record.

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Our Bylaws nullify Chapter 7B of the Michigan Business Corporation Act (Act). This Act regulates shareholder rights when an individual’s stock ownership reaches 20% of a Michigan corporation’s outstanding shares. A shareholder seeking control of the Company cannot require our Board of Directors to call a meeting to vote on issues related to corporate control within 10 days, as stipulated by the Act. See Note 10 of the Notes to Consolidated Financial Statements for information concerning the Shareholders’ Rights Agreement.
We paid cash dividends on our common stock of $365 million in 2006, $360 million in 2005, and $354 million in 2004. 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 for the foreseeable future. In fourth quarter of 2006, we announced a quarterly dividend increase, effective January 15, 2007, from $0.515 per share to $0.53 per share.
All of our equity compensation plans that provide for the annual awarding of stock-based compensation have been approved by shareholders. See Note 17 of the Notes to Consolidated Financial Statements for additional detail.
See the following table for information as of December 31, 2006.
                         
    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
    5,667,197     $ 41.60       7,654,802  

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UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table provides information about Company purchases of equity securities that are registered by the Company pursuant to Section 12 of the Exchange Act for the year ended December 31, 2006:
                                         
    Total             Total Number of             Maximum Dollar  
    Number of     Average     Shares Purchased     Average     Value that May Yet  
    Shares     Price Paid     as Part of Publicly     Price Paid     Be Purchased  
    Purchased     Per Share     Announced Plans or     Per Share     Under the Plans or  
Period   (1)     (1)     Programs (2)     (2)     Programs (2)  
01/01/06 — 01/31/06
                            $ 700,000,000  
02/01/06 — 02/28/06
                              700,000,000  
03/01/06 — 03/31/06
    199,555       42.70                     700,000,000  
04/01/06 — 04/30/06
    37,525       40.65                     700,000,000  
05/01/06 — 05/31/06
                              700,000,000  
06/01/06 — 06/30/06
    6,725       41.13                     700,000,000  
07/01/06 — 07/31/06
    1,000       40.83                     700,000,000  
08/01/06 — 08/31/06
                              700,000,000  
09/01/06 — 09/30/06
    1,500       40.71                     700,000,000  
10/01/06 — 10/31/06
                              700,000,000  
11/01/06 — 11/30/06
                              700,000,000  
12/01/06 — 12/31/06
    36,250       49.10       1,000,000       48.47       651,506,040  
 
                                 
Total
    282,555       43.19       1,000,000                  
 
                                 
 
(1)   Represents shares of common stock purchased on the open market to provide shares to participants under various employee compensation and incentive programs. These purchases were not made pursuant to a publicly announced plan or program.
 
(2)   In January 2005, the DTE Energy Board authorized the repurchase of up to $700 million in common stock through 2008. The authorization provides Company management with flexibility to pursue share repurchases from time to time, and will depend on future asset monetizations, cash flows and other investment opportunities.

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Item 6. Selected Financial Data
The following selected financial data should be read in conjunction with the accompanying Management’s Discussion and Analysis and Notes to the Consolidated Financial Statements.
                                         
(in Millions, except per share amounts)   2006     2005     2004     2003     2002  
Operating Revenues
  $ 9,022     $ 9,021     $ 7,069     $ 6,999     $ 6,680  
 
                             
Net Income (Loss)
                                       
Total from continuing operations
  $ 437     $ 577     $ 464     $ 475     $ 598  
Discontinued operations
    (5 )     (37 )     (33 )     73       34  
Cumulative effect of accounting changes
    1       (3 )           (27 )      
 
                             
Net Income
  $ 433     $ 537     $ 431     $ 521     $ 632  
 
                             
 
                                       
Diluted Earnings Per Share
                                       
Total from continuing operations
  $ 2.45     $ 3.28     $ 2.68     $ 2.83     $ 3.62  
Discontinued operations
    (.03 )     (.21 )     (.19 )     .42       .21  
Cumulative effect of accounting changes
    .01       (.02 )           (.16 )      
 
                             
Diluted Earnings Per Share
  $ 2.43     $ 3.05     $ 2.49     $ 3.09     $ 3.83  
 
                             
 
                                       
Financial Information
                                       
Dividends declared per share of common stock
  $ 2.075     $ 2.06     $ 2.06     $ 2.06     $ 2.06  
Total assets
  $ 23,785     $ 23,335     $ 21,297     $ 20,753     $ 19,985  
Long-term debt, including capital leases
  $ 7,474     $ 7,080     $ 7,606     $ 7,669     $ 7,803  
Shareholders’ equity
  $ 5,849     $ 5,769     $ 5,548     $ 5,287     $ 4,565  
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
OVERVIEW
DTE Energy is a diversified energy company with 2006 revenues in excess of $9 billion and approximately $24 billion in assets. We are the parent company of Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales, distribution and storage services throughout southeastern Michigan. We operate five energy-related non-utility segments with operations throughout the United States.
The following table summarizes our financial results:
                         
(in Millions, except Earnings per Share)   2006   2005   2004
Income from Continuing Operations
  $ 437     $ 577     $ 464  
Earnings per Diluted share
  $ 2.45     $ 3.28     $ 2.68  
Net Income
  $ 433     $ 537     $ 431  
Earnings per Diluted Share
  $ 2.43     $ 3.05     $ 2.49  
The decrease in 2006 net income is primarily due to the temporary idling of synfuel plants along with the associated impairments and reserves, and impairments within our Power and Industrial Projects segment. This decrease was partially offset by higher earnings at our electric utility, Detroit Edison, and Energy Trading segment mark-to-market losses in 2005 which did not recur in 2006.

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The items discussed below influenced our current financial performance and may affect future results:
  Effects of weather and collectibility of accounts receivable on utility operations;
  Impact of regulatory decisions on our utility operations;
  Investments in our Unconventional Gas Production business;
  Results in our Energy Trading business;
  Synfuel-related earnings and the impact of temporarily idling synfuel facilities in 2006; and
  Cost reduction efforts and required capital investment.
UTILITY OPERATIONS
Weather - Earnings from our utility operations are seasonal and very sensitive to weather. Electric utility earnings are primarily dependent on hot summer weather, while the gas utility’s results are primarily dependent on cold winter weather. During 2006, we experienced milder than normal weather conditions.
Additionally, we occasionally experience various types of storms that damage our electric distribution infrastructure resulting in power outages. Restoration and other costs associated with storm-related power outages lowered pretax earnings by $46 million in 2006, $82 million in 2005 and $48 million in 2004.
Receivables - Both utilities continue to experience high levels of past due receivables, especially within our Gas Utility operations. The increase is attributable to economic conditions, higher natural gas prices and a lack of adequate levels of assistance for low-income customers.
We have taken aggressive actions to reduce the level of past due receivables including, increased customer disconnections, contracting with collection agencies and working with the State of Michigan and others to increase the share of low-income funding allocated to our customers. In 2006, we sold previously written-off accounts of $43 million resulting in a gain and net proceeds of $1.9 million. The gain was recorded as a recovery through bad debt expense, which is included within Operation and maintenance expense.
As a result of these factors, our allowance for doubtful accounts expense for the two utilities increased to $123 million in 2006 from $98 million in 2005 and from $105 million in 2004.
The April 2005 MPSC gas rate order provided for an uncollectible true-up mechanism for MichCon. We filed the 2005 annual reconciliation, comparing our actual uncollectible expense to our designated revenue recovery of approximately $37 million on an annual basis. The MPSC approved the 2005 annual reconciliation on December 21, 2006 allowing MichCon to surcharge the $11 million excess beginning in January 2007.
We expect to file the 2006 annual reconciliation with the MPSC no later than March 31, 2007 comparing our actual 2006 uncollectible expense to our designated revenue recovery of approximately $37 million. Ninety percent of the difference for the year will be requested to be surcharged as part of the annual reconciliation proceeding before the MPSC. We have accrued $33 million under the 2006 uncollectible true-up mechanism.
Regulatory activity - In accordance with the MPSC’s directive in Detroit Edison’s November 2004 rate order, in March 2005, Detroit Edison filed a joint application and testimony in its 2004 PSCR Reconciliation Case and its 2004 Net Stranded Cost Recovery Case. In September 2006, the MPSC issued an order recognizing $19 million of 2004 net stranded costs that required Detroit Edison to write off $112 million of 2004 net stranded costs. The MPSC order resulted in a $39 million reduction in the 2004 PSCR over-collection by allowing Detroit Edison to retain the benefit of third party wholesale sales

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required to support the electric Customer Choice program and to offset the recognition of the $19 million of 2004 stranded costs. The MPSC order also resulted in reductions in accrued interest on the 2004 and 2005 PSCR amounts of $15 million. The MPSC directed Detroit Edison to include the remaining 2004 PSCR over-collection amount and related interest in the 2005 PSCR Reconciliation which is in an under-collected position. The order resulted in a reduction of pre-tax income of approximately $58 million.
The following graph depicts the total electric Customer Choice volumes for customers who have purchased power from an alternative electric supplier:
Electric Customer Choice Volumes in MWh
(BAR GRAPH)
In March 2006, the MPSC issued an order directing Detroit Edison to show cause by June 1, 2006 why its retail electric rates should not be reduced in 2007. The MPSC issued an order approving the settlement agreement in this proceeding on August 31, 2006. The order provided for an annualized rate reduction of $53 million for 2006, effective September 5, 2006. Beginning January 1, 2007, and continuing until the later of March 31, 2008 or 12 months from the filing date of Detroit Edison’s next main rate case, rates will be reduced by an additional $26 million, for a total reduction of $79 million. Detroit Edison experienced a rate reduction of approximately $13 million in 2006 as a result of this order. The revenue reduction is net of the recovery of the amortization of the costs associated with the implementation of the Performance Excellence Process. The settlement agreement provides for some level of realignment of the existing rate structure by allocating a larger percentage share of the rate reduction to the commercial and industrial customer classes than to the residential customer classes.
Coal Supply — Our generating fleet produces approximately 70% of its electricity from coal. Increasing coal demand from domestic and international markets has resulted in significant price increases. In addition, difficulty in recruiting workers, obtaining environmental permits and finding economically recoverable amounts of new coal has resulted in decreasing coal output from the central Appalachian region. Furthermore, as a result of environmental regulation and declining eastern coal stocks, demand for cleaner burning western coal has increased. This increased demand for western coal has also resulted in a corresponding demand for western rail shipping, straining railroad capacity, resulting in longer lead times for western coal shipments.
Nuclear Fuel - We operate one nuclear facility that undergoes a periodic refueling outage approximately every eighteen months. Uranium prices have been rising due to supply concerns. In the future, there may be additional nuclear facilities constructed in the industry that may place additional pressure on uranium supplies and prices. We have a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. We are obligated to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold. The fee is a component of nuclear fuel expense. Delays

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have occurred in the DOE’s program for the acceptance and disposal of spent nuclear fuel at a permanent repository. Until the DOE is able to fulfill its obligation under the contract, we are responsible for the spent nuclear fuel storage. We are currently expanding the Fermi 2 spent fuel pool capacity to meet our storage requirements through 2009. We are a party in the litigation against the DOE for both past and future costs associated with the DOE’s failure to accept spent nuclear fuel under the timetable set forth in the Federal Nuclear Waste Policy Act of 1982.
NON-UTILITY OPERATIONS
We have made significant investments in non-utility asset-intensive businesses. We employ disciplined investment criteria when assessing opportunities that leverage our assets, skill and expertise. Specifically, we invest in targeted energy markets with attractive competitive dynamics where meaningful scale is in alignment with our risk profile. A number of factors have impacted our non-utility businesses including the effect of oil prices on the synthetic fuel business, losses from certain power generation assets, losses from our waste coal recovery and landfill gas recovery businesses, and earnings volatility in our energy trading business. As part of a strategic review of our non-utility operations, we are considering various actions including the sale, restructuring or recapitalization of various non-utility businesses which we expect may generate over $800 million in cash proceeds in 2007. We plan to continue to invest in focused areas that have the strongest opportunities.
The primary source of recent investment capital has been cash flow from the synfuel business. We have hedged a portion the risk of an oil price-related phase-out of production tax credits in the synfuel business. We now anticipate approximately $900 million of synfuel-related cash impacts from 2007 through 2009, which consists of cash from operations and proceeds from option hedges, and approximately $500 million of tax credit carryforward utilization and other tax benefits that are expected to reduce future tax payments. Tax credit carryforward utilization in part could be extended past 2009, if taxable income is reduced from current forecasts.
Coal and Gas Midstream
We are continuing to build our capacity to transport greater amounts of western coal and to expand into coal terminals to allow for increased coal storage and blending. We are currently involved in a contract dispute with BNSF Railway Company that has been referred to arbitration. Under this contract, BNSF transports western coal east for Detroit Edison and the Coal Transportation and Marketing business. We have filed a breach of contract claim against BNSF for the failure to provide certain services that we believe are required by the contract. The arbitration hearing is scheduled for mid-2007. While we believe we will prevail on the merits in this matter, a negative decision with respect to the significant issues being heard in the arbitration could have an adverse effect on our ability to grow the Coal Transportation and Marketing business as currently contemplated.
Pipelines, Processing and Storage is continuing its steady growth plan of expansion of storage capacity in Michigan and expanding and building new pipeline capacity to serve markets in the Midwest and northeast United States.
Unconventional Gas Production
Current natural gas prices provide attractive opportunities for our Unconventional Gas Production business segment. We are an experienced operator with more than 15 years of experience in the Antrim shale in northern Michigan, and we continue to expand our operations in the Barnett shale basin in north Texas, where recent leasehold acquisitions have increased our total leasehold acreage to 89,808 acres (80,530 net of interest of others) after reduction by opportunistic sales of 11,193 acres.
We are exploring the sale of a portion of our Unconventional Gas Production assets which will allow us to monetize value from our more mature holdings, while retaining the ability to benefit from the upside of our earlier stage holdings.

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Antrim shale — We intend to develop existing acreage using the latest vertical and horizontal drilling and fracture stimulation techniques. Our long-term fixed-price obligations for production of Antrim continue to expire in 2007. This will create opportunities to remarket Antrim production at significantly higher current market rates.
                         
Michigan – Antrim Shale            
    2006   2005   2004
Net Producing Wells
    1,700       1,630       1,523  
 
                       
Production Volume (Bcfe)
    22       22       23  
 
                       
Proved Reserves (Bcfe)
    442       338       335  
 
                       
Net Developed Acreage
    228,232       217,643       213,959  
Net Undeveloped Acreage
    66,184       73,056       79,025  
 
                       
Capital Expenditures (in Millions)
  $ 49     $ 37     $ 22  
Future Undiscounted Net Cash Flows (in Millions)(1)
  $ 1,636     $ 1,307     $ 760  
 
                       
Average gas price with hedges (per Mcf)
  $ 3.41     $ 3.10     $ 3.10  
Average gas price without hedges (per Mcf)(2)
  $ 6.61     $ 7.73     $ 5.57  
 
(1)   Represents the standardized measure of discounted future net cash flows as calculated by an independent engineering firm utilizing extensive estimates. The estimated future net cash flow computations should not be considered to represent our estimate of the expected revenues or the current value of existing proved reserves and do not include the impact of hedge contracts.
 
(2)   The gas produced in the Antrim shale is subject to hedges that began to expire in 2006. For 2007, we anticipate remarketing an additional 1.8 Bcf.
Barnett shale - We anticipate significant opportunities in our existing Barnett shale acreage and expect continued extension of producing areas within the Fort Worth Basin. We are currently in the test and development phase for unproved and recently acquired Barnett shale acreage.
                         
Texas – Barnett Shale            
    2006   2005   2004
Net Producing Wells
    110       55       1  
 
                       
Production Volume (Bcfe)
    4       1        
 
                       
Proved Reserves (Bcfe)
    174       59       8  
 
                       
Net Developed Acreage
    16,045       14,637       316  
Net Undeveloped Acreage
    64,485       61,627       48,541  
 
                       
Capital Expenditures (in Millions)
  $ 137     $ 107     $ 16  
Future Undiscounted Net Cash Flows (in Millions) (1)
  $ 472     $ 127     $ 7  
 
                       
Average gas price (per Mcf)
  $ 5.66     $ 9.01     $ 5.70  
 
(1)   Represents the standardized measure of discounted future net cash flows as calculated by an independent engineering firm utilizing extensive estimates. The estimated future net cash flow computations should not be considered to represent our estimate of the expected revenues or the current value of existing proved reserves and do not include the impact of hedge contracts.
Current natural gas prices and successes within the Barnett shale are resulting in more capital being invested into the region. The competition for opportunities and goods and services may result in increased operating costs. However, our experience in the Antrim shale and our experienced Barnett shale personnel provide an advantage in addressing potential cost increases. We invested $186 million in

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2006 and expect to invest a combined amount of approximately $150 million to $170 million in our unconventional gas business in 2007.
As a component of our risk management strategy for our Barnett shale reserves, we hedged a portion of our proved developed producing reserves to secure an attractive investment return. As of December 31, 2006, we entered into a series of cash flow hedges for 4.7 Bcf of anticipated gas production through 2010 at an average price of $8.08 per Mcf.
Power and Industrial Projects
Power and Industrial Projects is comprised primarily of projects that deliver utility-type services to industrial, commercial and institutional customers, and biomass energy projects. We provide utility-type services using project assets usually located on the customers’ premises in the steel, automotive, pulp and paper, airport and other industries. These services include pulverized coal and petroleum coke supply, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. We own and operate three gas-fired peaking electric generating plants and a biomass-fired electric generating plant and operate one additional gas-fired power plant under contract. Additionally, we own a gas-fired peaking electric generating plant that was taken out of service in September 2006. We develop, own and operate landfill gas recovery systems throughout the United States. We produce coke from two coke batteries. The production of coke from our coke batteries generates production tax credits (assuming no phase-out).
We are exploring the combination of a sale of an equity interest in, and recapitalization of, some of the assets of the Power and Industrial Projects business, including the sale or restructuring of the power generation assets. In February 2007, we entered into an agreement to sell our Georgetown peaking electric generating facility. The sale is subject to receipt of regulatory approval and is expected to close in the second half of 2007.
Energy Trading
Significant portions of the electric and gas marketing and trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as contracted natural gas pipelines and storage capacity positions. Most financial instruments are deemed derivatives, whereas the gas inventory, pipelines and storage assets are not derivatives. As a result, this segment may experience earnings volatility as derivatives are marked to market without revaluing the underlying non-derivative contracts and assets. This results in gains and losses that are recognized in different accounting periods. We may incur mark-to-market accounting gains or losses in one period that will reverse in subsequent periods when transactions are settled.
During 2005, our earnings were negatively impacted by the economically favorable decision to delay previously planned withdrawals from gas storage due to a decrease in the current price for natural gas and an increase in the forward price for natural gas. In addition, we entered into forward power contracts to economically hedge certain physical and capacity power contracts. The financial impacts of these timing differences have begun to reverse and have favorably impacted results during 2006. We are exploring strategic options for the energy trading business.
Synthetic Fuel
Synthetic Fuel Operations
Synfuel plants chemically change coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits are provided for the production and sale of solid synthetic fuel produced from coal and are available through December 31, 2007. The synthetic fuel plants generate operating losses which we expect to be offset by production tax credits. The value of a production tax credit is adjusted annually by an inflation factor and published annually by the Internal Revenue Service (IRS). The value is reduced if the Reference Price of a barrel of oil exceeds certain thresholds.

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We are the operator of nine synthetic fuel production facilities throughout the United States. On May 12, 2006, we idled production at all nine of the synthetic fuel facilities. The decision to idle synfuel production was driven by the level and volatility of oil prices at that time. During the idle period, we took various steps to reduce our oil price exposure, including renegotiation of a significant number of commercial agreements. Beginning September 5, 2006 through October 4, 2006, we resumed production at each of the nine synfuel facilities due to these amended commercial agreements and declines in the level of oil prices.
Recognition of Synfuel Gains
To optimize income and cash flow from the synfuel operations, we sold interests in all nine of the facilities, representing 91% of the total production capacity as of December 31, 2006. Proceeds from the sales are contingent upon production levels and the value of credits generated. Gains from the sale of an interest in a synfuel project are recognized when there is persuasive evidence that the sales proceeds have become fixed or determinable, the probability of refund is considered remote and collectibility is assured. In substance, we receive synfuel gains and reduced operating losses in exchange for tax credits associated with the projects sold.
The gain from the sale of synfuel facilities is generally comprised of fixed and variable components. The fixed component represents note payments, is not subject to refund, and is recognized as a gain when earned and collectibility is assured. The variable component is based on an estimate of tax credits allocated to our partners and is subject to refund based on the annual oil price phase-out. The variable component is recognized as a gain only when the probability of refund is considered remote and collectibility is assured. Additionally, our partners reimburse us (through the project entity) for the operating losses of the synfuel facilities, referred to as capital contributions. In the event that the tax credit is phased out, we are contractually obligated to refund an amount equal to all or a portion of the operating losses funded by our partners. To assess the probability and estimate the amount of refund, we use valuation and analysis models that calculate the probability of the Reference Price of oil for the year being within or exceeding the phase-out range. Due to changes in the agreements with certain of our synfuel partners and the exercise of existing rights by other synfuels partners, a higher percentage of the payments in 2006 were variable payments. As a result, a larger portion of the 2006 synfuel payments are subject to refund as a result of the phase-out; and therefore reduced the gain associated with the payments.
Crude Oil Prices
The Reference Price of a barrel of oil is an estimate by the IRS of the annual average wellhead price per barrel for domestic crude oil. The value of the production tax credit in a given year is reduced if the Reference Price of oil over the year exceeds a threshold price and is eliminated entirely if that same Reference Price exceeds a phase-out price. During 2006, the annual average wellhead price is projected to be approximately $6 lower than the New York Mercantile Exchange (NYMEX) price for light, sweet crude oil. The actual or estimated Reference Price and beginning and ending phase-out prices per barrel of oil for 2005 through 2007 are as follows:
                         
            Beginning Phase-Out   Ending Phase-Out
    Reference Price   Price   Price
2005 (actual)
  $ 50.26     $ 53.20     $ 66.79  
2006 (estimated)
  $ 60     $ 55     $ 69  
2007 (estimated)
  Not Available   $ 56     $ 70  
The NYMEX daily closing price of a barrel of oil for 2006 averaged approximately $66, which is approximately equal to a Reference Price of $60 per barrel, which we estimate to be within the phase-out range. The actual tax credit phase-out for 2006 will not be certain until the Reference Price is published by the IRS in April 2007. There is a risk of at least a partial phase-out of the production tax credits in 2007, which could adversely impact our results of operations, cash flow, and financial condition.

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Hedging of Synfuel Cash Flows
As discussed in Note 2 of the Notes to Consolidated Financial Statements, we have entered into derivative and other contracts to economically hedge a portion of our synfuel cash flow exposure to the risk of oil prices increasing. The derivative contracts are marked-to-market with changes in fair value recorded as an adjustment to synfuel gains. To manage our exposure in 2007 to the risk of an increase in oil prices that could substantially reduce or eliminate synfuel sales proceeds, we entered into a series of derivative contracts covering a specified number of barrels of oil. The derivative contracts involve purchased and written call options that provide for net cash settlement at expiration based on the full years’ 2007 average NYMEX trading prices for light, sweet crude oil in relation to the strike prices of each option. If the average NYMEX prices of oil in 2007 are less than approximately $60 per barrel, the derivatives will yield no payment. If the average NYMEX prices of oil exceed approximately $60 per barrel, the derivatives will yield a payment equal to the excess of the average NYMEX price over these initial strike prices, multiplied by the number of barrels covered, up to a maximum price of approximately $76 per barrel. These contracts are based on various terms to take advantage of increases in oil prices. We recorded pretax mark-to-market gains of $60 million during 2006 and $47 million in 2005, and a $12 million loss in 2004. The fair value changes are recorded as adjustments to the gain from selling interests in synfuel facilities and are included in the Asset gains and losses, reserves and impairments, net line item in the Consolidated Statement of Operations. We paid approximately $50 million for 2006 hedges, for which we received payments of approximately $156 million upon settlement of these hedges in January 2007. Through December 31, 2006, we paid approximately $103 million for 2007 hedges which will provide protection for a significant portion of our cash flows related to the synfuel production during 2007. As part of our synfuel- related risk management strategy, we continue to evaluate alternatives available to mitigate unhedged exposure to oil price volatility. As our risk management position changes due to market volatility, we may adjust our hedging strategy in response to changing conditions.
Risks and Exposures
Since there was the likelihood that the Reference Price for a barrel of oil would remain above the threshold at which synfuel-related production tax credits began to phase-out, we deferred gain recognition associated with variable and certain fixed note payments in 2006 until the end of the year when the probability of refund was remote and collectibility was assured. We deferred all variable gains for the first three quarters of 2006 and 2005. We recognized $43 million of fixed gains and $14 million of variable gains in 2006, compared to fixed gains of $132 million and variable gains of $187 million in 2005. All or a portion of the deferred gains will be recognized when and if the gain recognition criteria is met. Additionally, we may establish reserves for potential refunds of amounts related to partners’ capital contributions associated with operating losses allocated to their account. As previously discussed, in the event of a tax credit phase-out, we are contractually obligated to refund to our partners all or a portion of the operating losses funded by our partners.
In 2006, we recorded reserves and impairments of $157 million, consisting of a $79 million reserve for capital contributions related to operating losses and an impairment of $78 million for synfuel-related fixed assets and inventory. The fixed asset impairment was partially offset by $70 million included in the Minority Interest line on our Consolidated Statement of Operations, representing our partners’ share of the asset write down.
Cash from synfuel activity is at risk of a phase-out of the production tax credits. We expect approximately $900 million of synfuel-related cash impacts from 2007 through 2009, which consists of cash from operations, asset sales, and proceeds from option hedges, and approximately $500 million of tax credit carryforward utilization and other tax benefits that are expected to reduce future tax payments. The expected cash flow of approximately $900 million is economically hedged against the movement in oil prices. In addition, a goodwill write-off of up to $4 million will likely be required in 2007 due to the production tax credit phase-out, the inability to generate new production tax credits after 2007 and the resulting discontinuance of synfuel production. We have fixed note receivables associated with the sales of interests in the synfuel facilities. A partial or full phase-out of production tax credits could adversely affect the collectibility of our receivables. The cash flow impact would likely reduce our ability to execute our investment and growth strategy.
OPERATING SYSTEM AND PERFORMANCE EXCELLENCE PROCESS
We continuously review and adjust our cost structure and seek improvements in our processes. Beginning in 2002, we adopted the DTE Energy Operating System, which is the application of tools and operating practices that have resulted in operating efficiencies, inventory reductions and improvements in

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technology systems, among other enhancements. Some of these cost reductions may be returned to our customers in the form of lower PSCR charges and the remaining amounts may impact our profitability.
As an extension of this effort, in mid-2005, we initiated a company-wide review of our operations called the Performance Excellence Process. The overarching goal has been and remains to become more competitive by reducing costs, eliminating waste and optimizing business processes while improving customer service. Many of our customers are under intense economic pressure and will benefit from our efforts to keep down our costs and their rates. Additionally, we will need significant resources in the future to invest in the infrastructure necessary to compete. Specifically, we began a series of focused improvement initiatives within our Electric and Gas Utilities, and our corporate support function.
The process is rigorous and challenging and seeks to yield sustainable performance to our customers and shareholders. We have identified the Performance Excellence Process as critical to our long-term growth strategy. Detroit Edison’s CTA is estimated to total between $160 million and $190 million. MichCon’s CTA is estimated to total between $55 million and $60 million.We estimate savings of approximately $45 million in operation and maintenance expenses and capital costs were realized in 2006. In 2006, we recorded CTA of approximately $134 million. CTA in 2006 exceeded our savings, but we expect to realize sustained net cost savings beginning in 2007.
In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison and MichCon, commencing in 2006, to defer the incremental CTA. Further, the order provides for Detroit Edison and MichCon to amortize the CTA deferrals over a ten-year period beginning with the year subsequent to the year the CTA was deferred. Detroit Edison deferred approximately $102 million of CTA in 2006 as a regulatory asset and will begin amortizing deferred 2006 costs in 2007 as the recovery of these costs was provided for by the MPSC in the order approving the settlement in the show cause proceeding. MichCon cannot defer CTA costs at this time because a recovery mechanism has not been established.
CAPITAL INVESTMENT
We anticipate significant capital investment across all of our business segments. Most of our capital expenditures will be concentrated within our utility segments. Our electric utility currently expects to invest approximately $4.3 billion, including increased environmental requirements and reliability enhancement projects through 2011. Our gas utility currently expects to invest approximately $1.0 billion on system expansion, pipeline safety and reliability enhancement projects through the same period. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment.
In 2005, we launched the first phase of our Enterprise Business Systems project, an enterprise resource planning system initiative to improve existing processes and to implement new core information systems. Through December 2006, we have spent approximately $330 million on this project and we anticipate spending an additional $45 million to $70 million over the next year as the remaining system elements are developed and implemented.
In the future, we may build a new base-load coal or nuclear electric generating plant. The last base-load plant constructed within our electric utility service territory was approximately twenty years ago.
OUTLOOK
The next few years will be a period of rapid change for DTE Energy and for the energy industry. Our strong utility base, combined with our integrated non-utility operations, position us well for long-term growth. Due to the enactment of the Energy Policy Act of 2005 and the repeal of the Public Utility Holding Company Act of 1935, there are fewer barriers to mergers and acquisitions of utility companies at the federal level. However, the expected industry consolidation, resulting in the creation of large regional utility providers, has been recently impacted by actions of regulators in certain states affected by the proposed transactions.

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Looking forward, we will focus on several areas that we expect will improve future performance:
    continuing to pursue regulatory stability and investment recovery for our utilities;
 
    managing the growth of our utility asset base;
 
    enhancing our cost structure across all business segments;
 
    improving our Electric and Gas Utility customer satisfaction; and
 
    investing in businesses that integrate our assets and leverage our skills and expertise.
Along with pursuing a leaner organization, we anticipate approximately $900 million of synfuel-related cash impacts from 2007 through 2009, which consists of cash from operations and proceeds from option hedges, and approximately $500 million of tax credit carryforward utilization and other tax benefits that are expected to reduce future tax payments. The redeployment of this cash represents a unique opportunity to increase shareholder value and strengthen our balance sheet. We expect to use any such cash and the potential cash from monetization of certain of our non-utility assets and operations to reduce debt and repurchase common stock, and to continue to pursue growth investments that meet our strict risk-return and value creation criteria. Our objectives for cash redeployment are to strengthen the balance sheet and coverage ratios to improve our current credit rating and outlook, and to have any monetizations be accretive to earnings per share.
RESULTS OF OPERATIONS
Net income in 2006 was $433 million, or $2.43 per diluted share, compared to net income of $537 million, or $3.05 per diluted share in 2005 and net income of $431 million, or $2.49 per diluted share in 2004. Excluding discontinued operations and the cumulative effect of accounting changes, our income from continuing operations in 2006 was $437 million, or $2.45 per diluted share, compared to income of $577 million, or $3.28 per diluted share in 2005 and income of $464 million, or $2.68 per diluted share in 2004. The following sections provide a detailed discussion of our segments’ operating performance and future outlook.
Segments realigned — In the third quarter of 2006, we realigned the non-utility segment Power and Industrial Projects business unit to separately present the Synthetic Fuel business. The impending expiration of synfuel tax credits as of December 31, 2007, combined with the sustained volatility of oil prices, increased management focus on synfuels, thereby requiring a separate business segment. In the fourth quarter of 2006, we separated the Fuel Transportation and Marketing segment into Coal and Gas Midstream, and Energy Trading corresponding to additional management focus on the results of these non-utility segments. Based on the following structure, we set strategic goals, allocate resources and evaluate performance:
    Electric Utility, consisting of Detroit Edison;
 
    Gas Utility, primarily consisting of MichCon;
 
    Non-utility Operations
    Coal and Gas Midstream, primarily consisting of coal transportation and marketing, gas pipelines and storage;
 
    Unconventional Gas Production, primarily consisting of unconventional gas project development and production;
 
    Power and Industrial Projects, primarily consisting of on-site energy services, steel-related projects and power generation with services;
 
    Energy Trading, consisting of energy marketing and trading operations; and
 
    Synthetic Fuel, consisting of the operations of the nine synfuel plants.

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    Corporate & Other, primarily consisting of corporate staff functions and certain energy technology investments.
                         
(in Millions, except per share data)   2006     2005     2004  
Net Income by Segment:
                       
Electric Utility
  $ 325     $ 277     $ 150  
Gas Utility
    50       37       20  
Non-utility Operations:
                       
Coal and Gas Midstream
    50       45       33  
Unconventional Gas Production
    9       4       6  
Power and Industrial Projects
    (80 )     4       (17 )
Energy Trading
    96       (43 )     85  
Synthetic Fuel
    48       305       199  
 
                       
Corporate & Other
    (61 )     (52 )     (12 )
 
Income (Loss) from Continuing Operations:
                       
Utility
    375       314       170  
Non-utility
    123       315       306  
Corporate & Other
    (61 )     (52 )     (12 )
 
                 
 
    437       577       464  
Discontinued Operations
    (5 )     (37 )     (33 )
Cumulative Effect of Accounting Changes
    1       (3 )      
 
                 
Net Income
  $ 433     $ 537     $ 431  
 
                 
 
                       
Diluted Earnings (Loss) Per Share
                       
Total Utility
  $ 2.10     $ 1.78     $ .98  
Non-utility Operations
    .69       1.79       1.77  
Corporate & Other
    (.34 )     (.29 )     (.07 )
 
                 
Income from Continuing Operations
    2.45       3.28       2.68  
Discontinued Operations
    (.03 )     (.21 )     (.19 )
Cumulative Effect of Accounting Changes
    .01       (.02 )      
 
                 
Net Income
  $ 2.43     $ 3.05     $ 2.49  
 
                 
    The earnings per share of any segment does not represent a direct legal interest in the assets and liabilities allocated to any one segment but rather represents a direct equity interest in DTE Energy’s assets and liabilities as a whole.
ELECTRIC UTILITY
Our Electric Utility segment consists of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electric energy to approximately 2.2 million customers in southeastern Michigan.
Factors impacting income: Our net income increased $48 million and $127 million in 2006 and 2005, respectively. These results primarily reflect higher gross margins, partially offset by increased depreciation and amortization expenses. Additionally, 2005 results were affected by higher rates due to the November 2004 MPSC final rate order, return of customers from the electric Customer Choice program, warmer weather and lower operations and maintenance expenses, partially offset by a portion of higher fuel and purchased power costs, which were unrecoverable as a result of residential rate caps (which expired January 1, 2006), and increased depreciation and amortization expenses.

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(in Millions)   2006     2005     2004  
Operating Revenues
  $ 4,737     $ 4,462     $ 3,568  
Fuel and Purchased Power
    1,566       1,590       885  
 
                 
Gross Margin
    3,171       2,872       2,683  
Operation and Maintenance
    1,336       1,308       1,395  
Depreciation and Amortization
    809       640       523  
Taxes Other Than Income
    252       241       249  
Asset (Gains) and Losses, Net
    (6 )     (26 )     (1 )
 
                 
Operating Income
    780       709       517  
Other (Income) and Deductions
    294       283       303  
Income Tax Provision
    161       149       64  
 
                 
Net Income
  $ 325     $ 277     $ 150  
 
                 
 
                       
Operating Income as a Percent of Operating Revenues
    16 %     16 %     14 %
Gross margin increased $299 million during 2006 and $189 million in 2005. The 2006 improvement was primarily due to increased rates due to the expiration of the residential rate cap on January 1, 2006 and returning sales from electric Customer Choice, partially offset by milder weather. The increase in 2005 was due to higher demand resulting from warmer weather and increased rates due to the November 2004 MPSC final rate order, partially offset by unrecovered power supply costs as a result of residential rate caps (which expired January 1, 2006) and a poor Michigan economy. Gross margin was favorably impacted by decreased electric Customer Choice penetration, whereby we lost 6% of retail sales to electric Customer Choice customers in 2006 and 12% of such sales during 2005 as retail customers migrated back to us as their electric generation provider rather than remaining with alternative suppliers. Pursuant to the MPSC final rate order, transmission expense, previously recorded in operation and maintenance expenses in 2004, is now reflected in purchased power expenses. The PSCR mechanism provides related revenues for the transmission expense.
The following table displays changes in various gross margin components relative to the comparable prior period:
                 
Increase (Decrease) in Gross Margin Components Compared to Prior Year            
(in Millions)   2006     2005  
Weather-related margin impacts
  $ (81 )   $ 166  
Removal of residential rate caps effective January 1, 2006
    186        
Return of customers from electric Customer Choice
    156       79  
Service territory economic performance
    (16 )     (23 )
Impact of MPSC 2004 rate orders
    26       116  
Unrecovered power supply costs — residential customers
          (73 )
Transmission charges
          (93 )
Other, net
    28       17  
 
           
Increase in gross margin performance
  $ 299     $ 189  
 
           

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Power Generated and Purchased            
(in Thousands of MWh)   2006   2005   2004
Power Plant Generation
                                               
Fossil
    39,686       70 %     40,756       73 %     39,432       75 %
Nuclear
    7,477       13       8,754       16       8,440       16  
             
 
    47,163       83       49,510       89       47,872       91  
Purchased Power
    9,861       17       6,378       11       4,650       9  
             
System Output
    57,024       100 %     55,888       100 %     52,522       100 %
Less Line Loss and Internal Use
    (3,603 )             (3,205 )             (3,574 )        
 
                                               
Net System Output
    53,421               52,683               48,948          
 
                                               
 
                                               
Average Unit Cost ($/MWh)
                                               
Generation (1)
  $ 15.61             $ 15.47             $ 12.98          
 
                                               
Purchased Power (2)
  $ 53.71             $ 89.37             $ 37.06          
 
                                               
Overall Average Unit Cost
  $ 22.20             $ 23.90             $ 15.11          
 
                                               
 
(1)   Represents fuel costs associated with power plants.
 
(2)   The change in purchased power costs were driven primarily by seasonal demand and coal and gas prices.
                         
(in Thousands of MWh)   2006     2005     2004  
Electric Sales
                       
Residential
    15,769       16,812       15,081  
Commercial
    17,948       15,618       13,425  
Industrial
    13,235       12,317       11,472  
Wholesale
    2,826       2,329       2,197  
Other
    402       390       401  
 
                 
 
    50,180       47,466       42,576  
Interconnection sales (1)
    3,241       5,217       6,372  
 
                 
Total Electric Sales
    53,421       52,683       48,948  
 
                 
 
                       
Electric Deliveries
                       
Retail and Wholesale
    50,180       47,466       42,576  
Electric Customer Choice
    2,694       6,760       9,245  
Electric Customer Choice—Self Generators (2)
    909       518       595  
 
                 
Total Electric Sales and Deliveries
    53,783       54,744       52,416  
 
                 
 
(1)   Represents power that is not distributed by Detroit Edison.
 
(2)   Represents deliveries for self generators who have purchased power from alternative energy suppliers to supplement their power requirements.
Operation and maintenance expense increased $28 million in 2006 and decreased $87 million in 2005. The 2006 increase was primarily due to increased distribution system maintenance of $35 million and increased plant outages of $33 million which was partially offset by $36 million of lower storm expenses. Pursuant to MPSC authorization, Detroit Edison deferred approximately $102 million of CTA in 2006. The comparability of 2005 to 2004 is affected by the November 2004 MPSC final rate order which required transmission and MISO expenses to be included in purchased power expense with related revenues to be recorded through the PSCR mechanism. Additionally, the DTE Energy parent company no longer allocated merger-related interest as a result of the November 2004 MPSC final rate order, which was partially offset by higher 2005 storm expenses.
Depreciation and amortization expense increased $169 million and $117 million in 2006 and 2005, respectively. The 2006 increase was due to a $112 million net stranded cost write-off related to the September 2006 MPSC order regarding stranded costs and a $19 million increase in our asset retirement obligation at our Fermi 1 nuclear facility. We also had increased amortization of regulatory assets of $19 million related to electric Customer Choice and $8 million related to our securitized assets. The 2005 increase reflects the income effect of recording regulatory assets in 2004, which lowered depreciation and

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amortization expenses. The regulatory asset deferrals totaled $46 million in 2005 and $107 million in 2004. Additionally, higher 2005 sales volumes compared to 2004 resulted in greater amortization of regulatory assets.
Asset (gains) and losses, net decreased $20 million in 2006 and increased $25 million in 2005 primarily as a result of our 2005 sale of land near our headquarters in Detroit, Michigan.
Other income and deductions expense increased $11 million in 2006 and decreased $20 million in 2005. The 2006 increase is attributable to higher interest expense due to increased long-term debt. The 2005 decrease is due primarily to lower interest expense as a result of lower interest rates and a favorable adjustment related to tax audit settlements.
Outlook — We continue to improve the operating performance of Detroit Edison. During the past year, we have resolved a portion of our regulatory issues and continue to pursue additional regulatory and/or legislative solutions for structural problems within the Michigan market structure, primarily electric Customer Choice and the need to adjust rates for each customer class to reflect the full cost of service.
Concurrently, we will move forward in our efforts to continue to improve performance. Looking forward, additional issues, such as rising prices for coal, health care and higher levels of capital spending, will result in us taking meaningful action to address our costs while continuing to provide quality customer service. We will utilize the DTE Energy Operating System and the Performance Excellence Process to seek opportunities to improve productivity, remove waste and decrease our costs while improving customer satisfaction.
Long term, we will be required to invest an estimated $2.4 billion on emission controls through 2018. Should we be able to recover these costs in future rate cases, we may experience a growth in earnings.
Additionally, our service territory may require additional generation capacity. A new base-load generating plant has not been built within the State of Michigan in the last 20 years. Should our regulatory environment be conducive to such a significant capital expenditure, we may build or expand a new base- load coal or nuclear facility. While we have not decided on construction of a new base-load nuclear facility, in February 2007, we announced that we will prepare a license application for construction and operation of a new nuclear power plant on the site of Fermi 2. By completing the license application before the end of 2008, we may qualify for financial incentives under the federal Energy Policy Act of 2005. We are also studying the possible transfer of a gas-fired peaking electric generating plant from our non-utility operations to our electric utility to support future power generation requirements.
The following variables, either in combination or acting alone, could impact our future results:
    amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals, or new legislation;
 
    our ability to reduce costs and maximize plant performance;
 
    variations in market prices of power, coal and gas;
 
    economic conditions within the State of Michigan;
 
    weather, including the severity and frequency of storms; and
 
    levels of customer participation in the electric Customer Choice program.
We expect cash flows and operating performance will continue to be at risk due to the electric Customer Choice program until the issues associated with this program are adequately addressed. We will accrue as regulatory assets any future unrecovered generation-related fixed costs (stranded costs) due to electric Customer Choice that we believe are recoverable under Michigan legislation and MPSC orders. We cannot predict the outcome of these matters. See Note 6 of the Notes to Consolidated Financial Statements.
In January 2007, the MPSC submitted the State of Michigan’s 21st Century Energy Plan to the Governor of Michigan. The plan recommends that Michigan’s future energy needs be met through a combination of

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renewable resources and cleanest generating technology, with significant energy savings achieved by increased energy efficiency. The plan also recommends:
    a requirement that all retail electric suppliers obtain at least 10 percent of their energy supplies from renewable resources by 2015;
 
    an opportunity for utility-built generation, contingent upon the granting of a certificate of need and competitive bidding of engineering, procurement and construction services;
 
    investigating the cost of a requirement to bury certain power lines; and
 
    creation of a Michigan Energy Efficiency Program, administered by a third party under the direction of the MPSC with initial funding estimated at $68 million.
We continue to review the energy plan and are unable to predict the impact on the Company of the implementation of the plan.
GAS UTILITY
Our Gas Utility segment consists of MichCon and Citizens Fuel Gas Company (Citizens), natural gas utilities subject to regulation by the MPSC. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.3 million residential, commercial and industrial customers in the State of Michigan. MichCon also has subsidiaries involved in the gathering and transmission of natural gas in northern Michigan. MichCon operates one of the largest natural gas distribution and transmission systems in the United States. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.
Factors impacting income: Gas Utility’s net income increased $13 million in 2006 and increased $17 million in 2005. The variances were primarily attributable to increased rates and the impacts in 2005 of the MPSC’s April 2005 gas cost recovery and gas rate orders and the effect of milder weather in 2006.
The 2005 MPSC gas rate order disallowed recovery of 90% of the costs of a computer billing system that was in place prior to DTE Energy’s acquisition of MCN Energy in 2001. MichCon impaired this asset by approximately $42 million in the first quarter of 2005. This disallowance was not reflected at the DTE Energy level since this impairment was previously reserved at the time of the MCN acquisition in 2001.
                         
(in Millions)   2006     2005     2004  
Operating Revenues
  $ 1,849     $ 2,138     $ 1,682  
Cost of Gas
    1,157       1,490       1,071  
 
                 
Gross Margin
    692       648       611  
Operation and Maintenance
    431       424       403  
Depreciation and Amortization
    94       95       103  
Taxes Other Than Income
    53       43       49  
Asset (Gains) and Losses, Net
          4       (3 )
 
                 
Operating Income
    114       82       59  
Other (Income) and Deductions
    53       47       48  
Income Tax Provision (Benefit)
    11       (2 )     (9 )
 
                 
Net Income
  $ 50     $ 37     $ 20  
 
                 
 
                       
Operating Income as a Percent of Operating Revenues
    6 %     4 %     4 %
Gross margin increased $44 million and $37 million in 2006 and 2005, respectively. Gross margins were favorably affected by higher base rate revenues of $15 million and $42 million in 2006 and 2005, respectively. Revenue associated with the uncollectible expense tracking mechanism authorized by the MPSC in the April 2005 gas rate order, increased $22 million and $11 million in 2006 and 2005, respectively. Additionally, 2006 was impacted by a $17 million favorable impact in lost gas recognized and an increase of $24 million in midstream services including storage and transportation. Partially offsetting these increases were declines of $31 million due to warmer than normal weather and $26 million as a result of customer conservation and lower volumes. The comparability of 2006 to 2005 is also affected

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by an adjustment we recorded in the first quarter of 2005 related to an April 2005 MPSC order in our 2002 GCR reconciliation case that disallowed $26 million representing unbilled revenues at December 2001.
                         
    2006     2005     2004  
Gas Markets (in Millions)
                       
Gas sales
  $ 1,541     $ 1,860     $ 1,435  
End user transportation
    135       134       119  
 
                 
 
    1,676       1,994       1,554  
Intermediate transportation
    69       58       56  
Other
    104       86       72  
 
                 
 
  $ 1,849     $ 2,138     $ 1,682  
 
                 
 
                       
Gas Markets (in Bcf)
                       
Gas sales
    138       168       173  
End user transportation
    136       157       145  
 
                 
 
    274       325       318  
Intermediate transportation
    373       432       536  
 
                 
 
    647       757       854  
 
                 
The 2005 final rate order provided revenue for an uncollectible expense true-up mechanism (UETM) to mitigate the effect of increasing uncollectible expense. The revenue recorded related to the UETM was $33 million for 2006 and $11 million for 2005.
Uncollectible Accounts Expense
    (BAR GRAPH)

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Operation and maintenance expense increased $7 million and $21 million in 2006 and 2005, respectively. The 2006 increase is due to a $14 million increase in uncollectible accounts receivable expense, reflecting higher past due amounts attributable to an increase in gas prices, continued weak economic conditions, and inadequate government-sponsored assistance for low-income customers. In 2006, we recorded $24 million in implementation costs associated with our Performance Excellence Process and we recognized $9 million of lower injuries and damages expenses and lower labor and employee incentives. The comparability of 2006 to 2005 and the comparability of 2005 to 2004 was affected by an adjustment we recorded in the second quarter of 2005 for the disallowance of $11 million in environmental costs due to the April 2005 final gas rate order and the requirement to defer negative pension expense as a regulatory liability. Additionally, the comparability was impacted by the DTE Energy parent company no longer allocating $9 million of merger-related interest to MichCon effective in April 2005.
Asset (gains) and losses, net increased $4 million and decreased $7 million in 2006 and 2005, respectively. The 2006 change was due to a $3 million gain on the sale of investment rights related to storage field construction which was offset by a $3 million loss due to a reduction to MichCon’s 2004 GCR underrecovery related to the accounting treatment of the injected base gas remaining in the New Haven storage field when it was sold in early 2004. The $7 million decline in 2005 was primarily the result of a write-off of certain computer equipment and related depreciation resulting from the April 2005 final rate order.
Income tax provision increased by $13 million in 2006 and income tax benefit decreased $7 million in 2005 primarily due to variations in pre-tax earnings.
Outlook — Operating results are expected to vary due to regulatory proceedings, weather, changes in economic conditions, customer conservation and process improvements. Higher gas prices and economic conditions have resulted in continued pressure on receivables and working capital requirements that are partially mitigated by the GCR mechanism. In the April 2005 final gas rate order, the MPSC adopted MichCon’s proposed tracking mechanism for uncollectible accounts receivable. Each year, MichCon will file an application comparing its actual uncollectible expense for the prior calendar year to its designated revenue recovery of approximately $37 million. Ninety percent of the difference will be refunded or surcharged after an annual reconciliation proceeding before the MPSC.
We will utilize the DTE Energy Operating System and the Performance Excellence Process to seek opportunities to improve productivity, remove waste and decrease our costs while improving customer satisfaction.
NON-UTILITY OPERATIONS
Coal and Gas Midstream
Coal and Gas Midstream consists of Coal Transportation and Marketing and the Pipelines, Processing and Storage businesses.
Coal Transportation and Marketing provides fuel, transportation and rail equipment management services. We specialize in minimizing fuel costs and maximizing reliability of supply for energy-intensive customers. Additionally, we participate in coal marketing and coal-to-power tolling transactions, as well as the purchase and sale of emissions credits. We perform coal mine methane extraction, in which we recover methane gas from mine voids for processing and delivery to natural gas pipelines, industrial users, or for small power generation projects.
Pipelines, Processing and Storage owns a partnership interest in an interstate transmission pipeline, six carbon dioxide processing facilities and two natural gas storage fields. The pipeline and storage assets are primarily supported by stable, long-term fixed price revenue contracts. The assets of these businesses are well integrated with other DTE Energy operations. Pursuant to an operating agreement, MichCon provides

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physical operations, maintenance and technical support for the Washington 28 and Washington 10 storage facilities.
Factors impacting income: Net income increased $5 million and $12 million in 2006 and 2005, respectively.
                         
(in Millions)   2006     2005     2004  
Operating Revenues
  $ 707     $ 707     $ 589  
Operation and Maintenance
    628       653       542  
Depreciation and Amortization
    4       3       3  
Taxes Other Than Income
    5       4       4  
 
                 
Operating Income
    70       47       40  
Other (Income) and Deductions
    (8 )     (20 )     (12 )
Income Tax Provision
    28       22       19  
 
                 
Net Income
  $ 50     $ 45     $ 33  
 
                 
Operating revenues remained the same in 2006 and increased $118 million in 2005. In 2006 our Coal Transportation and Marketing business experienced lower synfuel related volumes which were offset by an increase in storage revenues in the Pipelines, Processing and Storage business. During 2005, our Coal Transportation and Marketing business experienced higher throughput volumes and increased prices for coal.
Operation and maintenance expense decreased $25 million in 2006 and increased $111 million in 2005. The 2006 decrease was due to lower synfuel related volumes and decreased expenses at our Coal Transportation and Marketing business due to decreased marketing volume. During 2005, our Coal Transportation and Marketing business experienced higher throughput volumes and increased prices for coal.
Other (income) and deductions decreased $12 million in 2006 and increased $8 million in 2005. The 2006 decrease is primarily attributed to higher interest expense as a result of our storage expansion construction.
Income tax provision increased $6 million for 2006 and increased $3 million in 2005 reflecting variations in pre-tax income.
Outlook — We expect to continue to grow our Coal Transportation and Marketing business in a manner consistent with, and complementary to, the growth of our other business segments. However, a portion of our Coal Transportation and Marketing revenues and net income are dependent upon our Synfuel operations and were adversely impacted by the temporary idling of the synfuel facilities in 2006. Coal Transportation and Marketing is involved in a contract dispute with BNSF Railway Company that has been referred to arbitration. See Note 15 of the Notes to Consolidated Financial Statements.
Our Pipeline, Processing and Storage business will continue its steady growth plan. In April 2006, Pipelines, Processing and Storage placed into service over 14 Bcf of storage capacity at an existing Michigan storage field and plans to file a MPSC application early in 2007 for a new gas storage reservoir which will increase its overall working gas storage capacity by 8.0 Bcf to a total of 74 Bcf. In December 2006, Washington 28 filed an application with the MPSC requesting an increase in its working gas storage capacity to 16.0 Bcf. Vector Pipeline has secured long-term market commitments to support an expansion project, for approximately 200 MMcf per day, with a projected in-service date of November 2007. Vector Pipeline received FERC approval for this expansion in October 2006. Pipeline, Processing and Storage has a 26.25% ownership interest in Millennium Pipeline which received FERC approval for construction and operation in December 2006. Millennium Pipeline is scheduled to be in service in late 2008. In October 2006, we purchased the lessor interest in the 66 Bcf Washington 10 gas storage field. Prior to the purchase, we leased the storage rights and lease obligations

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were recorded as operating leases. We plan to expand existing assets and develop new assets which are typically supported with long-term customer commitments.
Unconventional Gas Production
Unconventional Gas Production is primarily engaged in natural gas exploration, development and production. Our Unconventional Gas Production business produces gas from the Antrim and Barnett shales and sells most of the gas to the Energy Trading segment.
Factors impacting income: Net income increased $5 million in 2006 and decreased $2 million in 2005. The 2006 results were primarily impacted by an increase in Barnett shale production and an increase in net gas prices for Antrim shale. Partially offsetting these revenue increases were higher operating and depletion expenses associated with increased production and the operation of new wells. The decline in 2005 was due to higher operating and Michigan severance tax expenses.
                         
(in Millions)   2006     2005     2004  
Operating Revenues
  $ 99     $ 74     $ 71  
Operation and Maintenance
    37       30       27  
Depreciation, Depletion and Amortization
    27       20       18  
Taxes Other Than Income
    11       11       7  
Asset (Gains) and Losses, Net
    (3 )            
 
                 
Operating Income
    27       13       19  
Other (Income) and Deductions
    13       8       10  
Income Tax Provision
    5       1       3  
 
                 
Net Income
  $ 9     $ 4     $ 6  
 
                 
Operating revenues increased $25 million in 2006 due to increased Barnett shale production and increased $3 million in 2005 due primarily to higher gas prices.
Operation and maintenance expense increased $7 million in 2006 and $3 million in 2005. Increases are associated with the addition of approximately 285 net producing wells during the three-year period.
Depreciation, depletion and amortization increased $7 million in 2006 and $2 million in 2005. The year-to-year increases were associated with higher gas production and higher finding costs associated with Barnett shale wells.
Taxes other than income were the same in 2006 due to severance taxes that were impacted by lower gas prices, which was offset by higher gas production, and increased $4 million in 2005 due to higher severance taxes associated with gas price increases on relatively flat Antrim gas volumes.
Assets (gains) and losses, net increased $3 million in 2006 primarily due to the sale of a working interest in unproved property.
Other (income) and deductions increased $5 million in 2006 and decreased $2 million in 2005. Interest expense was the primary contributor to the variances. The 2006 increase in interest expense was attributed to higher average affiliate notes payable balances.
Outlook — We expect to continue to develop our proved areas and test unproved areas in Michigan and Texas. Evaluation of Barnett shale test wells in up to three new areas is ongoing. During 2007, we expect Barnett Shale production of 8.7 Bcfe of natural gas compared with approximately 4.1 Bcfe in 2006 and Antrim Shale production roughly equivalent to the 21.5 Bcfe produced in 2006. We expect to invest a combined amount of approximately $150 million to $170 million in our Unconventional Gas Production business in 2007. We are exploring the sale of a portion of our Unconventional Gas Production assets

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which will allow us to monetize value from our more mature holdings, while retaining the ability to benefit from the upside of our earlier stage holdings.
Power and Industrial Projects
Power and Industrial Projects is comprised primarily of projects that deliver utility-type services to industrial, commercial and institutional customers, and biomass energy projects. We provide utility-type services using project assets usually located on the customers’ premises in the steel, automotive, pulp and paper, airport and other industries. These services include pulverized coal and petroleum coke supply, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. We own and operate three gas-fired peaking electric generating plants and a biomass-fired electric generating plant and operate one additional gas-fired power plant under contract. Additionally, we own a gas-fired peaking electric generating plant that was taken out of service in September 2006. We develop, own and operate landfill gas recovery systems throughout the United States. We produce metallurgical coke from two coke batteries. The production of coke from our coke batteries generates production tax credits.
Factors impacting income: Power and Industrial Projects’ reported a net loss of $80 million in 2006 and net income of $4 million in 2005. The 2006 net loss is primarily due to impairments. The 2005 net income is attributed to the acquisitions of four on-site energy projects and coke operations in 2005.
                         
(in Millions)   2006     2005     2004  
Operating Revenues
  $ 409     $ 428     $ 448  
Operation and Maintenance
    366       329       384  
Depreciation and Amortization
    48       48       53  
Taxes other than Income
    12       14       8  
Asset (Gains) and Losses, Reserves and Impairments, Net
    75       (1 )      
 
                 
Operating Income (Loss)
    (92 )     38       3  
Other (Income) and Deductions
    43       4       28  
Minority Interest
    1       37       11  
Income Taxes
                       
Provision (Benefit)
    (44 )     5       (10 )
Production Tax Credits
    (12 )     (12 )     (9 )
 
                 
 
    (56 )     (7 )     (19 )
 
                 
Net Income (Loss)
  $ (80 )   $ 4     $ (17 )
 
                 
Operating revenues decreased $19 million in 2006 and $20 million in 2005. The 2006 decrease is primarily due to lower coke prices and lower pulverized coal sales. The 2005 decrease reflects the impact from the sale of our interest in a coke battery in 2005 offset by increases at another owned coke battery due to increased output and increased prices. The 2006 and 2005 decreases were partially offset by increased revenue from our on-site energy projects, reflecting the addition of new facilities, completion of new long-term utility services contracts with a large automotive company and a large manufacturer of paper products.
Operation and maintenance expense increased $37 million in 2006 and decreased $55 million in 2005, reflecting the 2005 acquisitions of three on-site energy projects and coke operations. The 2005 decrease reflects the impact from the sale of an interest in a coke battery in 2005 resulting in a decrease in expense offset by increases in costs at another owned coke battery reflecting increased output.
Asset (gains) and losses, reserves and impairments, net increased $76 million in 2006. In 2006, we recorded a $42 million impairment for one of our 100% owned natural gas-fired generating plants and a $14 million impairment at our landfill gas recovery unit relating to the write-down of long-lived assets at several landfill sites. Also, during 2006, we recorded a pre-tax impairment loss of $19 million for the write down of fixed assets and patents at our waste coal recovery business.

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Other income and deductions increased $39 million in 2006 primarily due to a $32 million impairment of a 50% equity interest in a natural gas-fired generating plant.
Income taxes declined $49 million in 2006 and increased $12 million in 2005, reflecting changes in pre-tax income.
Outlook – Power and Industrial Projects will continue leveraging its extensive energy-related operating experience and project management capability to develop and grow the on-site energy business. The coke battery and landfill gas recovery businesses generate production tax credits that are subject to an oil price-related phase-out. Due to the relatively low level of production tax credits generated by our coke battery and landfill gas recovery business, a partial or full phase-out of production tax credits in these two businesses is not expected to have a material adverse impact on our Consolidated Statements of Operations, Cash Flow and Financial Position. We are exploring the combination of a sale of an equity interest in, and recapitalization of, some of the assets of the Power and Industrial Projects business, including the sale or restructuring of the power generation assets. In February 2007, we entered into an agreement to sell our Georgetown peaking electric generating facility. The sale is subject to receipt of regulatory approval and is expected to close in the second half of 2007.
Energy Trading
Energy Trading focuses on physical power and gas marketing, structured transactions, enhancement of returns from DTE Energy’s power plants and the optimization of contracted natural gas pipelines and storage capacity positions. Our customer base is predominantly utilities, local distribution companies, large industrials, and other marketing and trading companies. We enter into derivative financial instruments as part of our marketing and hedging activities. Most of the derivative financial instruments are accounted for under the mark-to-market method, which results in earnings recognition of unrealized gains and losses from changes in the fair value of the derivatives. We utilize forwards, futures, swaps and option contracts to mitigate risk associated with our marketing and trading activity as well as for proprietary trading within defined risk guidelines. Energy Trading is integral in providing commodity risk management services to the other unregulated businesses within DTE Energy.
Factors impacting income: Net income increased $139 million in 2006 and decreased $128 million in 2005. The 2006 increase is attributed to increased mark-to-market and realized power and gas positions that resulted from significant 2005 mark-to-market losses on derivative contracts used to economically hedge our gas in storage and forward power contracts. The 2005 decrease is attributed to decreased mark-to-market and realized power and gas positions.
                         
(in Millions)   2006     2005     2004  
Operating Revenues
  $ 830     $ 977     $ 665  
Fuel, Purchased Power and Gas
    616       984       486  
 
                 
Gross Margin
    214       (7 )     179  
Operation and Maintenance
    65       43       41  
Depreciation and Amortization
    6       4       3  
Taxes Other Than Income
    1       (1 )      
 
                 
Operating Income (Loss)
    142       (53 )     135  
Other (Income) and Deductions
    (3 )     13       5  
Income Tax Provision (Benefit)
    49       (23 )     45  
 
                 
Net Income (Loss)
  $ 96     $ (43 )   $ 85  
 
                 
Gross margin increased $221 million in 2006 and decreased $186 million in 2005. The 2006 increase is attributed to a $168 million mark-to-market increase on power and gas positions and a $57 million increase in realized power and gas positions. The 2006 results reflect the timing differences from 2005 that largely reversed and favorably impacted earnings. The 2005 decrease is due to a $121 million mark-to-market decrease on power and gas positions and a $66 million decrease in realized power and gas positions. The 2005 results reflect the economically favorable decision in early 2005 to delay previously planned withdrawals from gas storage due to a decrease in the current price for natural gas and an increase in the forward price for natural gas.

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Operation and maintenance expense increased $22 million in 2006 and $2 million in 2005. The 2006 increases were due to higher incentive expenses of $14 million resulting from our strong economic performance and higher corporate allocation charges of $10 million.
Other income and deductions decreased $16 million in 2006 and increased $8 million in 2005. The 2006 decrease is attributed to $6 million of lower intercompany interest expense and $8 million of higher intercompany interest income resulting from favorable operating cash flows to fund intercompany loans.
Income tax provision increased $72 million in 2006 and decreased $68 million in 2005 primarily due to variations in pre-tax earnings.
Outlook - Significant portions of the Energy Trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as capacity positions of natural gas storage and pipelines and power transmission contracts. The financial instruments are deemed derivatives, whereas the owned gas inventory, pipelines and storage assets are not derivatives. As a result, we will experience earnings volatility as derivatives are marked to market without revaluing the underlying non-derivative assets. The majority of such earnings volatility is associated with the natural gas storage cycle, which does not coincide with the calendar and fiscal year, but runs annually from April of one year to March of the next year. Our strategy is to economically manage the price risk of storage with over-the-counter forwards and futures. This results in gains and losses that are recognized in different interim and annual accounting periods. We are exploring strategic options for the energy trading business.
See “Fair Value of Contracts” section that follows.
Synthetic Fuel
Synthetic Fuel is comprised of the nine synfuel plants that we operate and that produce synthetic fuel. The production of synthetic fuel from the synfuel plants generates production tax credits.
Factors impacting income: Synthetic Fuel net income decreased $257 million in 2006 and increased $106 million in 2005. The decline in 2006 was due to higher oil prices resulting in reduced gains from selling interests in our synfuel plants, lower levels of production tax credits and asset impairments and reserves. The increase in 2005 reflects higher gains recognized from selling interests in our synfuel plants, gains on synfuel hedges, and increased levels of production tax credits.
                         
(in Millions)   2006     2005     2004  
Operating Revenues
  $ 863     $ 927     $ 650  
Operation and Maintenance
    1,019       1,167       832  
Depreciation and Amortization
    24       58       33  
Taxes other than Income
    12       20       8  
Asset (Gains) and Losses, Reserves and Impairments, Net
    40       (367 )     (219 )
 
                 
Operating Income (Loss)
    (232 )     49       (4 )
Other (Income) and Deductions
    (20 )     (34 )     (43 )
Minority Interest
    (251 )     (318 )     (223 )
Income Taxes
                       
Provision (Benefit)
    14       139       92  
Production Tax Credits
    (23 )     (43 )     (29 )
 
                 
 
    (9 )     96       63  
 
                 
Net Income
  $ 48     $ 305     $ 199  
 
                 
Operating revenues decreased $64 million in 2006 and increased $277 million in 2005. Revenues were lower in 2006 due to our decision to temporarily idle production at all nine of the synfuel facilities. Revenues increased in 2005 primarily reflecting higher synfuel sales due to increased production.
Operation and maintenance expense decreased $148 million in 2006 and increased $335 million in 2005. Operation and maintenance expense declined in 2006 due to our decision to temporarily idle production at

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all nine of the synfuel facilities for a portion of the year. Operating and maintenance expense in 2005 increased reflecting costs associated with increased synthetic fuel production.
Asset (gains) and losses, reserves and impairments, net decreased $407 million in 2006 and increased $148 million in 2005. In 2006 and 2005, we deferred gains from the sale of the synfuel facilities, including in 2006, a portion of gains related to fixed payments. Due to the increase in oil prices and the resulting decrease in production and sales volumes, we recorded an accrual for contractual partners’ obligations of $79 million pre-tax in 2006 reflecting the possible refund of amounts equal to our partners’ capital contributions or for operating losses that would normally be paid by our partners. We recorded other synfuel-related reserves and impairments in 2006 of $78 million. To economically hedge our exposure to the risk of an increase in oil prices and the resulting reduction in synfuel sales proceeds, we entered into derivative and other contracts. The derivative contracts are marked-to-market with changes in their fair value recorded as an adjustment to synfuel gains. We recorded net 2006 synfuel hedge mark-to-market gains of $60 million compared with net 2005 synfuel hedge mark-to-market gains of $47 million. In 2004, we recorded mark- to-market losses of $12 million. See Note 14 of the Notes to Consolidated Financial Statements.
                         
(in Millions)                  
Components of Synfuel (Gains) Losses, Reserves and Impairments, Net   2006     2005     2004  
Gains recognized associated with fixed payments
  $ (43 )   $ (132 )   $ (95 )
Gains recognized associated with variable payments
    (14 )     (187 )     (136 )
 
Reserves recorded for contractual partners’ obligations
    79              
Other reserves and impairments, including partners’ share (1)
    78              
Hedge (gains) losses (mark-to-market)
                       
Hedges for 2005 exposure
          (2 )     12  
Hedges for 2006 exposure
    (66 )     (40 )      
Hedges for 2007 exposure
    6       (6 )      
 
                 
 
  $ 40     $ (367 )   $ (219 )
 
                 
 
(1)   Includes $70 million in 2006, representing our partners’ share of the asset impairment, included in Minority Interest.
Minority interest decreased $67 million in 2006 and increased $95 million in 2005, reflecting our partners’ share of operating losses associated with synfuel operations, as well as our partners’ $70 million share of the asset impairment in 2006. The sale of interests in our synfuel facilities during prior periods resulted in allocating a larger percentage of such losses to our partners.
Income taxes declined $105 million in 2006 and increased $33 million in 2005, reflecting changes in pre-tax income due to synfuel related loss reserves and the impairment of fixed assets, compared to pre-tax income in 2005.
Outlook – Due to the implementation of our hedging strategy, we expect to continue to operate the synfuel plants through December 31, 2007, when synfuel-related production tax credits expire.
CORPORATE & OTHER
Corporate & Other includes various corporate staff functions. As these functions support the entire Company, their costs are fully allocated to the various segments based on services utilized. Therefore the effect of the allocation on each segment can vary from year to year. Additionally, Corporate & Other holds certain non-utility debt, assets held for sale, and energy-related investments.
Factors impacting income: Corporate & Other results declined by $9 million in 2006 and declined $40 million in 2005. The 2006 decline was primarily due to higher Michigan Single Business Taxes. The 2005 decline was primarily a result of the parent company not allocating merger interest to Detroit Edison and MichCon. Partially offsetting 2005 increased expenses were reduced Michigan Single Business Taxes and gains on the sale of non-strategic assets.

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DISCONTINUED OPERATIONS
DTE Georgetown (Georgetown) — We own Georgetown, an 80 MW natural gas-fired peaking electric generating plant. In the fourth quarter of 2006, management approved the marketing of Georgetown for sale. In December 2006, Georgetown met the SFAS No. 144 criteria of an asset “held for sale” and we reported its operating results as a discontinued operation. We did not recognize an impairment loss since the carrying value of Georgetown’s assets, less costs to sell approximated its fair value. In February 2007, we entered into an agreement to sell our Georgetown peaking electric generating facility. The sale is subject to receipt of regulatory approval and is expected to close in the second half of 2007.
DTE Energy Technologies (Dtech) - We own Dtech, which assembled, marketed, distributed and serviced distributed generation products, provided application engineering, and monitored and managed on-site generation system operations. In July 2005, management approved the restructuring of this business resulting in the identification of certain assets and liabilities to be sold or abandoned, primarily associated with standby and continuous duty generation sales and service. We recognized a net of tax restructuring loss of $23 million during the third quarter of 2005 primarily representing the write down to fair value of the assets of Dtech, less costs to sell, and the write-off of goodwill. As we execute the restructuring plan, there may be adjustments to amounts recorded related to the impairment and exit costs.
Southern Missouri Gas Company (SMGC) - We owned SMGC, a public utility engaged in the distribution, transmission and sale of natural gas in southern Missouri. In the first quarter of 2004, management approved the marketing of SMGC for sale. As of March 31, 2004, SMGC met the criteria of an asset “held for sale” and we have reported its operating results as a discontinued operation. We recognized a net of tax impairment loss of approximately $7 million, representing the write-down to fair value of the assets of SMGC, less costs to sell, and the write-off of allocated goodwill. In November 2004, we entered into a definitive agreement providing for the sale of SMGC. Regulatory approval was received in April 2005 and the sale closed in May 2005. During the second quarter of 2005, we recognized a net of tax gain of $2 million.
International Transmission Company (ITC) - In February 2003, we sold ITC, our electric transmission business, to affiliates of Kohlberg Kravis Roberts & Co. and Trimaran Capital Partners, LLC. Through December 31, 2004, we recorded a gain of $58 million (net of tax). During the second quarter of 2005, the gain was adjusted to $56 million (net of tax).
See Note 4 of the Notes to Consolidated Financial Statements.
CUMULATIVE EFFECT OF ACCOUNTING CHANGES
Effective January 1, 2006, we adopted SFAS No. 123(R), Share-Based Payment, using the modified prospective transition method. The cumulative effect of the adoption of SFAS 123(R) was an increase in net income of $1 million as a result of estimating forfeitures for previously granted stock awards and performance shares.
In the fourth quarter of 2005, we adopted FASB Interpretation FIN No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS No. 143 that required additional new accounting rules for asset retirement obligations. The cumulative effect of adopting these new accounting rules reduced 2005 earnings by $3 million.
CAPITAL RESOURCES AND LIQUIDITY
Cash Requirements
We use cash to maintain and expand our electric and gas utilities and to grow our non-utility businesses, retire and pay interest on long-term debt and pay dividends. Our strategic direction anticipates base level capital investments and expenditures for existing businesses in 2007 of up to $1.4 billion. The capital needs

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of our utilities will increase due primarily to environmental related expenditures. We may spend an additional $125 million on growth-related projects within our non-utility businesses in 2007.
Capital spending for general corporate purposes will increase in 2007, primarily as a result of environmental spending. We anticipate environmental expenditures of approximately $253 million in 2007 and up to approximately $2.3 billion of future capital expenditures to satisfy both existing and proposed new requirements.
We expect non-utility capital spending will approximate $300 million to $400 million annually for the next several years. Capital spending for growth of existing or new businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria.
Debt maturing in 2007 totals approximately $346 million.
We believe that we will have sufficient internal and external capital resources to fund anticipated capital requirements.
                         
(in Millions)   2006     2005     2004  
Cash and Cash Equivalents
                       
Cash Flow From (Used For)
                       
Operating activities:
                       
Net income
  $ 433     $ 537     $ 431  
Depreciation, depletion and amortization
    1,014       872       744  
Deferred income taxes
    28       147       129  
Gain on sale of synfuel and other assets, net and synfuel impairment
    28       (405 )     (236 )
Working capital and other
    (47 )     (150 )     (73 )
 
                 
 
    1,456       1,001       995  
 
                 
Investing activities:
                       
Plant and equipment expenditures – utility
    (1,126 )     (850 )     (815 )
Plant and equipment expenditures – non-utility
    (277 )     (215 )     (89 )
Acquisitions, net of cash acquired
    (42 )     (50 )      
Proceeds from sale of synfuels and other assets
    313       409       325  
Restricted cash and other investments
    (62 )     (96 )     (102 )
 
                 
 
    (1,194 )     (802 )     (681 )
 
                 
Financing activities:
                       
Issuance of long-term debt and common stock
    629       1,041       777  
Redemption of long-term debt
    (687 )     (1,266 )     (759 )
Short-term borrowings, net
    291       437       33  
Repurchase of common stock
    (61 )     (13 )      
Dividends on common stock and other
    (375 )     (366 )     (363 )
 
                 
 
    (203 )     (167 )     (312 )
 
                 
Net Increase in Cash and Cash Equivalents
  $ 59     $ 32     $ 2  
 
                 
Cash from Operating Activities
A majority of the Company’s operating cash flow is provided by our electric and gas utilities, which are significantly influenced by factors such as weather, electric Customer Choice, regulatory deferrals, regulatory outcomes, economic conditions and operating costs. Our non-utility businesses also provide sources of cash flow to the enterprise, primarily from the synthetic fuels business, which we believe, subject to considerations discussed below, will provide up to approximately $900 million of cash during 2007-2009.
Cash from operations totaling $1.5 billion in 2006 was up $455 million from the comparable 2005 period. The operating cash flow comparison reflects an increase of $352 million in net income, after adjusting for

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non-cash items (depreciation, depletion, amortization, deferred taxes and gains), and a $103 million decrease in working capital and other requirements. Most of the improvement was driven by higher net income at Detroit Edison which was the result of improved revenues and gross margin stemming from a full year of higher rates granted in the 2004 rate orders and lower customer choice penetration. The working capital improvement was driven by MichCon which resulted primarily from declining GCR factors which had the effect of lowering customer accounts receivable balances. This improvement was partially offset by working capital requirements at Detroit Edison which resulted from pension and VEBA contributions totaling $271 million in 2006.
Cash from operations totaling $1.0 billion in 2005 was up $6 million from the comparable 2004 period. The operating cash flow comparison reflects an increase of over $83 million in net income, after adjusting for non-cash items (depreciation, depletion, amortization, deferred taxes and gains), substantially offset by a $77 million increase in working capital and other requirements. Most of the improvement was driven by higher net income at Detroit Edison which was the result of improved revenues and gross margin stemming from higher rates granted in the 2004 rate orders, warmer weather, and lower customer choice penetration. The offsetting increase in working capital requirements was driven by a $127 million PSCR under-recovery in 2005 as compared to a $112 million over-recovery in 2004. Working capital requirements also reflect the higher cost of gas at MichCon and our Energy Trading segment. MichCon’s working capital and other requirements were $136 million higher in 2005 compared to 2004 primarily due to the impact of higher gas costs. This impact was reflected by accounts receivable balances that were $198 million higher at December 31, 2005 than the previous year at MichCon. The increase in working capital requirements was mitigated by lower income tax payments in 2005 and company initiatives to improve cash flow, including better inventory management, cash sales transactions and the utilization of letters of credit.
Outlook — We expect cash flow from operations to increase over the long-term primarily due to improvements from higher earnings at our utilities. We are incurring costs associated with implementation of our Performance Excellence Process, but we expect to realize sustained net cost savings beginning in 2007. We also may be impacted by the delayed collection of underrecoveries of our PSCR and GCR costs and electric and gas accounts receivable as a result of MPSC orders. Gas prices are likely to be a source of volatility with regard to working capital requirements for the foreseeable future. We are continuing our efforts to identify opportunities to improve cash flow through working capital initiatives.
We anticipate approximately $900 million of synfuel-related cash impacts from 2007 through 2009, which consists of cash from operations and proceeds from option hedges, and approximately $500 million of tax credit carryforward utilization and other tax benefits that are expected to reduce future tax payments. The redeployment of this cash represents a unique opportunity to increase shareholder value and strengthen our balance sheet. We expect to use any such cash and the potential cash from monetization of certain of our non-utility assets and operations to reduce debt and repurchase common stock, and to continue to pursue growth investments that meet our strict risk-return and value creation criteria. We repurchased one million shares of common stock in December 2006. Our objectives for cash redeployment are to strengthen the balance sheet and coverage ratios to improve our current credit rating and outlook, and to have any monetization be accretive to earnings per share.
Cash from Investing Activities
Cash inflows associated with investing activities are primarily generated from the sale of assets. In any given year, we will look to realize cash from under-performing or non-strategic assets. Capital spending within the utility business is primarily to maintain our generation and distribution infrastructure, comply with environmental regulations and gas pipeline replacements. Capital spending within our non-utility businesses is for ongoing maintenance and expansion. The balance of non-utility spending is for growth, which we manage very carefully. We look to make investments that meet strict criteria in terms of strategy, management skills, risks and returns. All new investments are analyzed for their rates of return and cash payback on a risk adjusted basis. We have been disciplined in how we deploy capital and will not make investments unless they meet our criteria. For new business lines, we invest tentatively based on research and analysis. We start with a limited investment, we evaluate results and either expand or exit the business based on those results. In any given year, the amount of growth capital will be

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determined by the underlying cash flows of the Company with a clear understanding of any potential impact on our credit ratings.
Net cash outflows relating to investing activities increased $392 million in 2006 compared to 2005. The 2006 change was primarily due to increased capital expenditures. The increase in capital expenditures was driven by environmental, Enterprise Business Systems development and distribution projects at Detroit Edison, pipeline reliability and inventory management projects at MichCon, and growth-oriented projects across our non-utility segments.
Net cash outflows relating to investing activities increased $121 million in 2005. The increase was primarily due to increased capital expenditures, partially offset by higher synfuel proceeds. Spending on growth project investments increased $123 million in 2005 while spending on environmental projects was $44 million higher than the 2004 period.
Longer term, with the expected improvement at our utilities and assuming continued cash generation from the synfuel business, cash flows are expected to improve. We will continue to pursue opportunities to grow our businesses in a disciplined fashion if we can find opportunities that meet our strategic, financial and risk criteria.
Cash from Financing Activities
We rely on both short-term borrowing and long-term financing as a source of funding for our capital requirements not satisfied by the Company’s operations. Short-term borrowings, which are mostly in the form of commercial paper borrowings, provide us with the liquidity needed on a daily basis. Our commercial paper program is supported by our unsecured credit facilities.
Our strategy is to have a targeted debt portfolio blend as to fixed and variable interest rates and maturity. We continually evaluate our leverage target, which is currently 50% to 52%, to ensure it is consistent with our objective to have a strong investment grade debt rating. We have completed a number of refinancings with the effect of extending the average maturity of our long-term debt and strengthening our balance sheet. The extension of the average maturity was accomplished at interest rates that lowered our debt costs.
Net cash used for financing activities increased $36 million during 2006 compared to 2005, due mostly to a decrease in short-term borrowings and issuance of common stock and long-term debt, partially offset by a decrease in debt redemptions.
Net cash used for financing activities improved $145 million in 2005 due primarily to the issuance of common stock which resulted from the conversion of our equity security units.
See Notes 11 and 12 of the Notes to Consolidated Financial Statements.
In August 2006, DTE Energy and Detroit Edison filed a combined shelf registration statement for the issuance of securities in an unlimited amount for three years from its effective date. MichCon has a separate effective registration statement providing for the issuance of $200 million of securities.
Common stock issuances or repurchases can also be a source or use of cash. In January 2005, we announced that the DTE Energy Board of Directors has authorized the repurchase of up to $700 million in common stock through 2008. The authorization provides Company management with flexibility to pursue share repurchases from time to time, and will depend on future cash flows and investment opportunities. We repurchased one million shares of our common stock in December 2006. We also contributed $170 million of DTE Energy common stock to our pension plan in the first quarter of 2004. In August 2005, we issued 3.7 million shares of common stock in conjunction with the settlement of the stock purchase component of our equity security units.

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Contractual Obligations
The following table details our contractual obligations for debt redemptions, leases, purchase obligations and other long-term obligations as of December 31, 2006:
                                         
            Less                        
(in Millions)           Than                     After  
Contractual Obligations   Total     1 Year     1-3 Years     4-5 Years     5 Years  
Long-term debt:
                                       
Mortgage bonds, notes and other
  $ 6,163     $ 236     $ 1,124     $ 1,061     $ 3,742  
Securitization bonds
    1,295       111       391       314       479  
Trust preferred-linked securities
    289                         289  
Capital lease obligations
    120       14       44       21       41  
Interest
    6,433       471       1,298       659       4,005  
Operating leases
    333       53       102       51       127  
Electric, gas, fuel, transportation and storage purchase obligations (1)
    6,249       3,007       2,437       135       670  
Other long-term obligations
    291       157       75       25       34  
 
                             
 
Total obligations
  $ 21,173     $ 4,049     $ 5,471     $ 2,266     $ 9,387  
 
                             
 
(1)   Excludes amounts associated with full requirements contracts where no stated minimum purchase volume is required.
Credit Ratings
Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. Management believes that the current credit ratings of the Company provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to the company may affect our ability to access these funding sources or cause an increase in the return required by investors.
We have issued guarantees for the benefit of various non-utility subsidiaries. In the event that our credit rating is downgraded to below investment grade, certain of these guarantees would require us to post cash or letters of credit valued at approximately $383 million at December 31, 2006. Additionally, upon a downgrade, our trading business could be required to restrict operations and our access to the short-term commercial paper market could be restricted or eliminated. While we currently do not anticipate such a downgrade, we cannot predict the outcome of current or future credit rating agency reviews. The following table shows our credit rating as determined by three nationally respected credit rating agencies. All ratings are considered investment grade and affect the value of the related securities.
                 
        Credit Rating Agency
        Standard &   Moody’s Investors   Fitch
Entity   Description   Poor’s   Service   Ratings
DTE Energy
  Senior Unsecured Debt   BBB-   Baa2   BBB
 
  Commercial Paper   A-2   P-2   F2
Detroit Edison
  Senior Secured Debt   BBB+   A3   A-
 
  Commercial Paper   A-2   P-2   F2
MichCon
  Senior Secured Debt   BBB   A3   A-
 
  Commercial Paper   A-2   P-2   F2

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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, production tax credits, goodwill, pension and postretirement costs, the allowance for doubtful accounts, and legal and tax reserves.
Regulation
A significant portion of our business is subject to regulation. Detroit Edison and MichCon currently meet the criteria of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. Application of this standard results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses. SFAS No. 71 requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Future regulatory changes or changes in the competitive environment could result in discontinuing the application of SFAS No. 71 for some or all of our businesses.
If we were to discontinue the application of SFAS No. 71 on all our operations, we estimate that the extraordinary loss would be as follows:
         
(in Millions)        
Utility        
Detroit Edison (1) 
  $ (161 )
MichCon
    (46 )
 
     
Total
  $ (207 )
 
     
 
(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. See Note 6 of the Notes to Consolidated Financial Statements.
Risk Management and Trading Activities
All derivatives are recorded at fair value and shown as “Assets or 1iabilities from risk management and trading activities” in the Consolidated Statement of Financial Position. Risk management activities are accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended.
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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Production Tax Credits
We generate production tax credits from our synfuel, coke battery and landfill gas recovery operations. We recognize earnings as tax credits are generated at our facilities in one of two ways. First, to the extent we have sold an interest in our synfuel facilities to third parties, we recognize gains as synfuel is produced and sold, and when there is persuasive evidence that the sales proceeds have become fixed or determinable, when probability of refund is considered remote and collectibility is reasonably assured. Second, to the extent we generate credits to our own account, we recognize earnings through reduced tax expense.
All production tax credits are subject to audit by the IRS. However, all of our synfuel facilities have received favorable private letter rulings from the IRS with respect to their operations. Audits of five of our synfuel facilities were successfully completed in the past two years. If production tax credits were disallowed in whole or in part as a result of an IRS audit, there could be a significant write-off of previously recorded earnings from such tax credits.
Tax credits generated by our facilities were $295 million in 2006 as compared to $617 million in 2005, and $449 million in 2004. The portion of tax credits generated for our own account was $35 million in 2006, as compared to $55 million in 2005, and $38 million in 2004, with the remaining credits generated allocated to third party partners.
Goodwill
Certain of our business units have goodwill resulting from purchase business combinations. In accordance with SFAS No. 142, Goodwill and Other Intangible Assets, each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In order to perform these impairment tests, we must determine the reporting unit’s fair value using valuation techniques, which use estimates of discounted future cash flows to be generated by the reporting unit. These cash flow valuations involve a number of estimates that require broad assumptions and significant judgment by management regarding future performance. To the extent estimated cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill, which would adversely impact our earnings.
As of December 31, 2006, our goodwill totaled $2.1 billion. The majority of our goodwill is allocated to our utility reporting units. The value of the utility reporting units may be significantly impacted by rate orders and the regulatory environment.
We also have $4 million of goodwill allocated to the Synthetic Fuel reporting unit. The value of the Synthetic Fuel reporting unit has been impacted by the anticipated phase-out of tax credits. As of December 31, 2006, we have evaluated the impact of a phase-out of synfuel tax credits on our valuation assumptions. We have determined that the fair value of the Synthetic Fuel reporting unit exceeds the carrying value and no impairment of goodwill exists. These assumptions may change as the value of the synfuel tax credits change.
During 2005 we recorded an impairment of $16 million to goodwill related to discontinuing the operations of Dtech.
Based on our 2006 goodwill impairment test, we determined that the fair value of our remaining operating reporting units exceed their carrying value and no impairment existed. We will continue to monitor our estimates and assumptions regarding future cash flows. While we believe our assumptions are reasonable, actual results may differ from our projections.

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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 $125 million in 2006 (including Special Termination Benefits of $49 million), $90 million in 2005, and $81 million in 2004. Postretirement benefits costs for all plans were $197 million in 2006 (including Special Termination Benefits of $8 million), $155 million in 2005, and $125 million in 2004. Pension and postretirement benefits costs for 2006 are calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on our plan assets of 8.75%. In developing our expected long-term rate of return assumption, we evaluated input from our consultants, including their review of asset class risk and return expectations as well as inflation assumptions. Projected returns are based on broad equity and bond markets. Our 2007 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, 20% in fixed income markets, and 15% 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 8.75% is a reasonable long-term rate of return on our plan assets for 2007. 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. Accordingly, the future value of assets will be impacted as previously deferred gains or losses are recorded. We have unrecognized net gains due to the performance of the financial markets. As of December 31, 2006, we had $39 million of cumulative gains that remain to be recognized in the calculation of the market-related value of assets.
The discount rate that we utilize for determining future pension and postretirement benefit obligations is based on a yield curve approach and a review of bonds that receive one of the two highest ratings given by a recognized rating agency. The yield curve approach matches projected plan pension and postretirement benefit payment streams with bond portfolios reflecting actual liability duration unique to our plans. The discount rate determined on this basis decreased from 5.9% at December 31, 2005 to 5.7% at December 31, 2006. Due to recent company contributions, financial market performance and lower discount rates, we estimate that our 2007 pension costs will approximate $66 million (excluding Special Termination Benefits) compared to $85 million (excluding Special Termination Benefits) in 2006 and our 2007 postretirement benefit costs will approximate $184 million compared to $189 million (excluding Special Termination Benefits of $8 million) in 2006. In the last several years, we have made modifications to the pension and postretirement benefit plans to mitigate the earnings impact of higher costs. Future actual pension and postretirement benefit costs will depend on future investment performance, changes in future discount rates and various other factors related to plan design. Additionally, future pension costs for Detroit Edison will be affected by a pension tracking mechanism, which was authorized by the MPSC in its November 2004 rate order. The tracking mechanism provides for the recovery or refunding of pension costs above or below the amount reflected in Detroit Edison’s base rates. In April 2005, the MPSC approved the deferral of the non-capitalized portion of MichCon’s negative pension expense. MichCon will record a regulatory liability for any negative pension costs, as determined under generally accepted accounting principles.
Lowering the expected long-term rate of return on our plan assets by one-percentage-point would have increased our 2006 qualified pension costs by approximately $22 million. Lowering the discount rate and the salary increase assumptions by one-percentage-point would have increased our 2006 pension costs by approximately $10 million. Lowering the health care cost trend assumptions by one-percentage-point would have decreased our postretirement benefit service and interest costs for 2006 by approximately $25 million.

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The market value of our pension and postretirement benefit plan assets has been affected by the financial markets. The value of our plan assets was $3.3 billion at December 31, 2004 and November 30, 2005. The value at November 30, 2006 was $3.5 billion. The investment performance returns and declining discount rates required us to recognize an additional minimum pension liability, an intangible asset and an entry to other comprehensive loss (shareholders’ equity) in 2004 and 2005. At December 31, 2006, we adopted SFAS No. 158 that required us to recognize the underfunded status of our pension and other postretirement plans. The impact of the adoption of SFAS 158 was an increase in pension and postretirement benefit liabilities of approximately $1.3 billion. We requested and received agreement from the MPSC to record the additional liability amounts for the Detroit Edison and MichCon benefit plans on the Statement of Financial Position as a Regulatory asset. As a result, Regulatory assets were increased by approximately $1.2 billion. The remainder of the increase in pension and postretirement benefit liabilities is included in Accumulated Other Comprehensive Loss, net of tax.
Pension and postretirement costs and pension cash funding requirements may increase in future years without substantial returns in the financial markets. We made a $170 million contribution to our pension plan in the form of DTE Energy common stock in 2004. We did not make pension contributions in 2005 and made a $180 million cash contribution in 2006. At the discretion of management, we anticipate making up to a $180 million contribution to our qualified pension plans in 2007 and up to $600 million over the next five years. Also, we anticipate making up to a $15 million contribution to our nonqualified benefit plans in 2007 and up to $35 million over the next five years. We contributed $80 million to our postretirement plans in 2004. We did not contribute to our postretirement plans in 2005 and made a $116 million contribution to our postretirement benefit plans in 2006. At the discretion of management, we anticipate making up to a $116 million contribution to our postretirement plans in 2007 and up to $580 million over the next five years.
In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act was signed into law. This Act provides for a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the benefit established by law. The effects of the subsidy on the measurement of net periodic postretirement benefit costs reduced costs by $17 million in 2006, $20 million in 2005 and $16 million in 2004.
See Note 16 of the Notes to Consolidated Financial Statements.
Allowance for Doubtful Accounts
We establish an allowance for doubtful accounts based upon factors surrounding the credit risk of specific customers, historical trends, economic conditions, age of receivables and other information. Higher customer bills due to increased gas prices, the lack of adequate levels of assistance for low-income customers and economic conditions have also contributed to the increase in past due receivables. As a result of these factors, our allowance for doubtful accounts increased in 2005 and 2006. We believe the allowance for doubtful accounts is based on reasonable estimates. As part of the 2005 rate order for MichCon, the MPSC provided for the establishment of an uncollectible accounts tracking mechanism that partially mitigates the impact associated with MichCon uncollectible expenses. However, failure to make continued progress in collecting our past due receivables in light of rising energy prices would unfavorably affect operating results and cash flow.
Legal and Tax Reserves
We are involved in various legal and tax proceedings, claims and litigation arising in the ordinary course of business. We regularly assess our liabilities and contingencies in connection with asserted or potential matters, and establish reserves when appropriate. Legal reserves are based upon management’s assessment of pending and threatened legal proceedings and claims against the Company. Tax reserves are based upon management’s assessment of potential adjustments to tax positions taken. We regularly review ongoing tax audits and prior audit experience, in addition to current tax and accounting authority in assessing potential adjustments.
ENVIRONMENTAL MATTERS
Protecting the environment, as well as correcting past environmental damage, continues to be a focus of state and federal regulators. Legislation and/or rulemaking could further impact the electric utility

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industry including Detroit Edison. The EPA and the MDEQ have aggressive programs to clean-up contaminated property.
Electric Utility
Air - Detroit Edison is subject to EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. In March 2005, EPA issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, Detroit Edison has spent approximately $875 million through 2006. We estimate Detroit Edison will incur future capital expenditures of up to $222 million in 2007 and up to $2 billion of additional capital expenditures through 2018 to satisfy both the existing and proposed new control requirements.
The EPA has ongoing enforcement actions against several major electric utilities citing violations of new source provisions of the Clean Air Act. Detroit Edison received and responded to information requests from the EPA on this subject. The EPA has not initiated proceedings against Detroit Edison. In October 2003, the EPA promulgated revised regulations to clarify new source review provisions going forward. Several states and environmental organizations have challenged these regulations and, in December 2003, a stay was issued 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.
We may also incur liabilities as a result of potential future requirements to address the climate change issue. There may be legislative action to address the issue of changes in climate that result from the build up of greenhouse gases, including carbon dioxide and methane, in the atmosphere. We cannot predict the impact any legislative action may have on the Company.
Water – In response to an EPA regulation, currently under judicial review, Detroit Edison may be required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of the studies to be conducted over the next several years, Detroit Edison may be required to install additional control technologies to reduce the impacts of the intakes. Initially, we estimated that we will incur up to approximately $53 million over the next three to five years in additional capital expenditures to comply with these requirements. However, a recent court decision remanded back to the EPA several provisions of the federal regulation which may result in a delay in compliance requirements. The court decision also raised the possibility that the Company may have to install cooling towers at some facilities. We cannot predict the effect on Detroit Edison of this court decision or any resulting regulations.
Contaminated Sites - Detroit Edison conducted remedial investigations at contaminated sites, including two former MGP sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. We have a reserve balance of $11 million as of December 31, 2006 for the remediation of these sites over the next several years. In addition, Detroit Edison expects to make approximately $5 million of capital improvements to the ash landfill in 2007.
Gas Utility
Contaminated Sites - Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. Gas Utility owns, or previously owned, 15 former MGP sites. Investigations have revealed contamination related to the by–products of gas manufacturing at each site. In addition to the MPG sites, Gas Utility is also in the process of cleaning up other contaminated sites. Cleanup activities associated with these sites will be conducted over the next several years. As a result of these determinations, we have recorded liabilities of $41 million and $1 million for the MGPs and other contaminated sites, respectively. It is estimated that Gas Utility may incur $5 million in expenses related to cleanup costs in 2007.

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In 1993, a cost deferral and rate recovery mechanism was approved by the MPSC for investigation and remediation costs incurred at former MGP sites in excess of this reserve. After a study was completed in 1995, Gas Utility accrued an additional liability and a corresponding regulatory asset of $35 million. During 2006, we spent approximately $2 million investigating and remediating these former MGP sites. In December 2006, we retained multiple environmental consultants to estimate the project cost to remediate each MGP site. We accrued an additional $7 million in remediation liabilities associated with former MGP holders and additional cleanup cost, to increase the reserve balance to $41 million as of December 31, 2006.
Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and thereby affect the Company’s financial position and cash flows. However, we anticipate the cost deferral and rate recovery mechanism approved by the MPSC will prevent environmental costs from having a material adverse impact on our results of operations.
Other
Our non-utility affiliates are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants. We are in the process of installing new environmental equipment at our coke battery facility in Michigan. We expect the project to be completed within one year. Our non-utility affiliates are substantially in compliance with all environmental requirements.
Various state and federal laws regulate our handling, storage and disposal of waste materials. The EPA and the MDEQ have aggressive programs to manage the clean up of contaminated property. We have extensive land holdings and, from time to time, must investigate claims of improperly disposed contaminants. We anticipate our utility and non-utility companies may periodically be included in various types of environmental proceedings.
ENTERPRISE BUSINESS SYSTEMS
In 2003, we began the development of our Enterprise Business Systems (EBS) project, an enterprise resource planning  system initiative to improve existing processes and to implement new core information systems, relating to finance, human resources, supply chain and work management. As part of this initiative, we are implementing EBS software including, among others, products developed by SAP AG and MRO Software, Inc. The first phase of implementation occurred in 2005 in the regulated electric fossil generation unit. Additional phases of implementation are planned for 2007. The conversion of data and the implementation and operation of the EBS will be continuously monitored and reviewed and should ultimately strengthen our internal control structure and lead to increased cost efficiencies. Although our implementation plan includes detailed testing and contingency arrangements to ensure a smooth and successful transition, we can provide no assurance that complications will not arise that could interrupt our operations.
We have spent approximately $330 million through the end of 2006 and expect total spending over the life of the project to be between $375 million and $400 million. We expect the benefits of lower costs, faster business cycles, repeatable and optimized processes, enhanced internal controls, improvements in inventory management and reductions in system support costs to outweigh the expense of our investment in this initiative.
MISO
The MISO was formed in 1996 by its member transmission owners and in December 2001 received FERC approval as a Regional Transmission Organization (RTO) authorized to provide regional transmission services as prescribed by FERC in its Order 2000. Order 2000 requires an RTO to perform eight functions, including tariff administration, transmission system congestion management, provision of ancillary services to support transmission operations, market monitoring, interregional coordination and

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the coordination of system planning and expansion. MISO’s independence from ownership of either generation or transmission facilities is intended to enable it to ensure fair access to the transmission grid, and through its congestion management role, MISO is also charged with ensuring grid reliability. MISO’s initial provision of transmission services in December 2001 was known as Day 1 operations.
In keeping with Order 2000, which permits RTOs to provide real-time energy imbalance services and a market-based mechanism for congestion management, MISO, on April 1, 2005, launched its Midwest Energy Market, or Day 2 operations, and began regional wholesale electric market operations and transmission service throughout its area. A key feature of the Midwest Energy Market is the establishment of Locational Marginal Prices (LMPs) which provide price transparency for the sale and purchase of wholesale electricity at different locations in the market territory. The LMP is the market clearing price at a specific pricing location in the Midwest Energy Market that is equal to the cost of supplying the next increment of load at that location. The value of an LMP is the same whether a purchase or sale is made at that location. Detroit Edison participates in the Midwest Energy Market by offering its generation on a day-ahead and real time basis and by bidding for power in the market to serve its load. The cost of power procured from the market net of any gain realized from generation sold into the market is included and recovered through the PSCR mechanism. In addition, LMPs are expected to encourage new generation to locate where the power produced is of most value to the load and is expected to identify where new transmission facilities are needed to relieve grid congestion.
MISO is compensated for assuring grid reliability and for supporting the energy market through FERC-approved rates charged to load. Detroit Edison became a non-transmission owning member of MISO in compliance with section 10w (1) of PA 141. The MPSC has ordered that MISO costs charged to Detroit Edison should be recovered through the PSCR mechanism.
FEDERAL ENERGY POLICY ACT OF 2005
In August 2005, the Energy Policy Act of 2005 (Energy Act) was signed into law. Among other provisions, the Energy Act:
  establishes mandatory electric reliability standards;
 
  repeals the Public Utility Holding Company Act of 1935;
 
  renews the Price Anderson Act for twenty years which provides liability protection for nuclear power plants;
 
  provides financial incentives for nuclear license applications completed by 2008;
 
  increases funding levels for the Low-Income Home Energy Assistance Program; and
 
  increases FERC oversight responsibilities for the electric utility industry.
The implementation of the Energy Act requires proceedings at the state level and development of regulations by the FERC, as well as other federal agencies. The impact of the Energy Act on our results of operations will depend on the implementation of final rules and cannot be fully determined at this time.
NEW ACCOUNTING PRONOUNCEMENTS
See Note 3 of the Notes to Consolidated Financial Statements.
FAIR VALUE OF CONTRACTS
The following disclosures provide enhanced transparency of the derivative activities and position of our trading businesses and our other businesses.
We use the criteria in Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted, to determine if certain contracts must be accounted for as derivative instruments. The rules for determining whether a contract meets the criteria for derivative accounting are numerous and complex. Moreover, significant judgment is required to

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determine whether a contract requires derivative accounting, and similar contracts can sometimes be accounted for differently. If a contract is accounted for as a derivative instrument, it is recorded in the financial statements as “Assets or Liabilities from risk management and trading activities”, at the fair value of the contract. The recorded fair value of the contract is then adjusted quarterly to reflect any change in the fair value of the contract, a practice known as mark-to-market (MTM) accounting.
Fair value represents the amount at which willing parties would transact an arms-length transaction. To determine the fair value of contracts accounted for as derivative instruments, we use a combination of quoted market prices and mathematical valuation models. Valuation models require various inputs, including forward prices, volatility, interest rates, and exercise periods.
Contracts we typically classify as derivative instruments are power, gas and oil forwards, futures, options and swaps, as well as foreign currency contracts. Items we do not generally account for as derivatives (and which are therefore excluded from the following tables) include gas inventory, gas storage and transportation arrangements, full-requirements power contracts and gas and oil reserves. As subsequently discussed, we have fully reserved the value of derivative contracts beyond the liquid trading timeframe thereby not impacting income.
The subsequent tables contain the following four categories represented by their operating characteristics and key risks.
  “Proprietary Trading” represents derivative activity transacted with the intent of taking a view, capturing market price changes, or putting capital at risk. This activity is speculative in nature as opposed to hedging an existing exposure.
 
  “Structured Contracts” represents derivative activity transacted with the intent to capture profits by originating substantially hedged positions with wholesale energy marketers, utilities, retail aggregators and alternative energy suppliers. Although transactions are generally executed with a buyer and seller simultaneously, some positions remain open until a suitable offsetting transaction can be executed.
 
  “Economic Hedges” represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas production and trades associated with owned transportation and storage capacity. Changes in the value of derivatives in this category economically offset changes in the value of underlying non-derivative positions, which do not qualify for fair value accounting. The difference in accounting treatment of derivatives in this category and the underlying non-derivative positions can result in significant earnings volatility as discussed in more detail in the preceding Results of Operations section.
 
  “Other Non-Trading Activities” primarily represent derivative activity associated with our gas reserves and synfuel operations. A substantial portion of the price risk associated with the gas reserves has been mitigated through 2013. Changes in the value of the hedges are recorded as “Assets or Liabilities from risk management and trading activities,” with an offset in other comprehensive income to the extent that the hedges are deemed effective. Oil-related derivative contracts have been executed to economically hedge cash flow risks related to underlying, non-derivative synfuel related positions through 2007. The amounts shown in the following tables exclude the value of the underlying gas reserves and synfuel proceeds including changes therein.

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Roll-Forward of Mark-to-Market Energy Contract Net Assets
The following tables provide details on changes in our mark-to-market net asset or (liability) position during 2006:
                                                 
                                    Other        
    Trading Activities     Non-        
    Proprietary     Structured     Economic             Trading        
(in Millions)   Trading     Contracts     Hedges     Total     Activities     Total  
MTM at December 31, 2005
  $ (108 )   $ (136 )   $ (110 )   $ (354 )   $ (140 )   $ (494 )
 
                                   
Reclassed to realized upon settlement
    (21 )     83       57       119       92       211  
Liquidation of in-the-money positions (1)
                (123 )     (123 )           (123 )
Changes in fair value recorded to income
    (5 )     35       140       170       (6 )     164  
Amortization of option premiums
    114       (2 )           112       (40 )     72  
 
                                   
Amounts recorded to unrealized income
    88       116       74       278       46       324  
Amounts recorded in OCI
          14             14       (3 )     11  
Option premiums paid and other
    11       4             15       73       88  
 
                                   
MTM at December 31, 2006
  $ (9 )   $ (2 )   $ (36 )   $ (47 )   $ (24 )   $ (71 )
 
                                   
 
(1)   In conjunction with our overall tax planning and cash initiatives, we monetized certain in-the-money contracts while simultaneously entering into at-the-market contracts with various counterparties. This had the impact of optimizing taxable income and cash flow while having minimal impact on earnings.
The following table provides a current and noncurrent analysis of “Assets and Liabilities from risk management and trading activities”, as reflected on the Consolidated Statement of Financial Position as of December 31, 2006. Amounts that relate to contracts that become due within twelve months are classified as current and all remaining amounts are classified as noncurrent.
                                                         
                                            Other        
    Trading Activities     Non-     Total  
    Proprietary     Structured     Economic                     Trading     Assets  
(in Millions)   Trading     Contracts     Hedges     Eliminations     Totals     Activities     (Liabilities)  
Current assets
  $ 62     $ 193     $ 108     $ (57 )   $ 306     $ 155     $ 461  
Noncurrent assets
    7       55       108       (7 )     163       1       164  
 
                                         
Total MTM assets
    69       248       216       (64 )     469       156       625  
 
                                         
 
                                                       
Current liabilities
    (71 )     (189 )     (132 )     57       (335 )     (102 )     (437 )
Noncurrent liabilities
    (7 )     (61 )     (120 )     7       (181 )     (78 )     (259 )
 
                                         
Total MTM liabilities
    (78 )     (250 )     (252 )     64       (516 )     (180 )     (696 )
 
                                         
 
                                                       
Total MTM net assets (liabilities)
  $ (9 )   $ (2 )   $ (36 )   $     $ (47 )   $ (24 )   $ (71 )
 
                                         
Maturity of Fair Value of MTM Energy Contract Net Assets
We fully reserve all unrealized gains and losses related to periods beyond the liquid trading timeframe. Our intent is to recognize MTM activity only when pricing data is obtained from active quotes and published indexes. Actively quoted and published indexes include exchange traded (i.e., NYMEX) and over-the-counter positions for which broker quotes are available. Although the NYMEX has currently quoted prices for the next 72 months, broker quotes for gas and power are generally available for 18 and 24 months into the future, respectively, we fully reserve all unrealized gains and losses related to periods beyond the liquid trading timeframe and which therefore do not impact income.
As a result of adherence to generally accepted accounting principles, the tables above do not include the expected favorable earnings impacts of certain non-derivative gas storage and power contracts. We entered into economically favorable transactions in early 2005 to delay previously planned withdrawals from gas storage due to a decrease in the current price for natural gas and an increase in the forward price

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for natural gas. We anticipate the financial impact of this timing difference will reverse when the gas is withdrawn from storage in the current storage cycle and is sold at prices significantly in excess of the cost of gas in storage. In addition, we entered into forward power contracts to economically hedge certain physical and capacity power contracts. We expect the timing difference on the forward power contracts will be fully realized by the end of 2007.
The table below shows the maturity of our MTM positions:
                                         
                            2010        
(in Millions)                           and     Total Fair  
Source of Fair Value   2007     2008     2009     Beyond     Value  
Proprietary Trading
  $ (9 )   $     $     $     $ (9 )
Structured Contracts
    4       (6 )     (4 )     4       (2 )
Economic Hedges
    (24 )     (8 )     (4 )           (36 )
 
                             
Total Energy Trading Activities
    (29 )     (14 )     (8 )     4       (47 )
Other Non-Trading Activities
    53       (61 )     (16 )           (24 )
 
                             
Total
  $ 24     $ (75 )   $ (24 )   $ 4     $ (71 )
 
                             

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk
DTE Energy has commodity price risk in both utility and non-utility businesses arising from market price fluctuations.
The Electric and Gas utility businesses have risks in conjunction with the anticipated purchases of coal, natural gas, uranium, electricity, and base metals to meet their service obligations. Further, changes in the price of electricity can impact the level of exposure of Customer Choice programs and uncollectible expenses at the Electric Utility. In addition, changes in the price of natural gas can impact the valuation of lost gas, storage sales revenue and uncollectible expenses at the Gas Utility.
To limit our exposure to commodity price fluctuations, the Utility businesses have applied various approaches to manage this risk. The approaches include forward energy, capacity, storage and futures contracts, as well as regulatory rate-recovery mechanisms. Regulatory rate-recovery occurs in the form of PSCR and GCR mechanisms (see Note 1 of the Notes to Consolidated Financial Statements) and a tracking mechanism to mitigate some losses from customer migration due to electric Customer Choice programs.
The non-utility businesses have risk in conjunction with electricity, natural gas, crude oil and coal.
Our Power and Industrial Projects and Synthetic Fuel segments are subject to crude oil, electricity, natural gas and coal based product price risk. As previously discussed, production tax credits generated by DTE Energy’s synfuel, coke battery and landfill gas recovery operations are subject to phase-out if domestic crude oil prices reach certain levels. The benefits associated with tax credits may be subject to changes in federal tax law. Also, we have entered into a series of derivative contracts for 2007 to economically hedge the impact of oil prices on a portion of our synfuel cash flow. See Note 14 of the Notes to Consolidated Financial Statements. To limit our exposure to the other commodities we use forward energy, capacity and futures contracts.
Our Unconventional Gas Production business segment has exposure to natural gas and, to a lesser extent, crude oil price fluctuations. These commodity price fluctuations can impact both current year earnings and reserve valuations. To manage this exposure we use forward energy and futures contracts.
Our Energy Trading business segment has exposure to electricity, natural gas and crude oil price fluctuations. These risks are managed through its energy marketing and trading operations through the use of forward energy, capacity, storage and futures contracts, within pre-determined risk parameters.
Our Coal and Gas Midstream business segment has exposure to natural gas and coal price fluctuations. These coal price risks are managed primarily through its coal transportation and marketing operations through the use of forward coal and futures contracts. The Gas Midstream business unit manages its exposure through the sale of long-term storage and transportation contracts.
Credit Risk
Bankruptcies
We purchase and sell electricity, gas, coal, coke and other energy products from and to numerous companies operating in the steel, automotive, energy, retail and other industries. Certain of our customers have filed for bankruptcy protection under Chapter 11 of the U. S. Bankruptcy Code. We regularly review contingent matters relating to these customers and our purchase and sale contracts and we record provisions for amounts considered at risk of probable loss. We believe our previously accrued amounts are adequate for probable loss. The final resolution of these matters is not expected to have a material effect on our financial statements.

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Other
We engage in business with customers that are non-investment grade. We closely monitor the credit ratings of these customers and, when deemed necessary, we request collateral or guarantees from such customers to secure their obligations.
Energy Trading
We are exposed to credit risk through trading activities. Credit risk is the potential loss that may result if our trading counterparties fail to meet their contractual obligations. We utilize both external and internally generated credit assessments when determining the credit quality of our trading counterparties. The following table displays the credit quality of our trading counterparties as of December 31, 2006:
                         
    Credit Exposure              
    before Cash     Cash     Net Credit  
(in Millions)   Collateral     Collateral     Exposure  
Investment Grade (1)
                       
A- and Greater
  $ 526     $ (126 )   $ 400  
BBB+ and BBB
    111             111  
BBB-
    107             107  
 
                 
Total Investment Grade
    744       (126 )     618  
Non-investment grade (2)
    68             68  
Internally Rated — investment grade (3)
    104             104  
Internally Rated — non-investment grade (4)
    9       (4 )     5  
 
                 
Total
  $ 925     $ (130 )   $ 795  
 
                 
 
(1)   This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s Investors Service (Moody’s) and BBB- assigned by Standard & Poor’s Rating Group, a division of the McGraw-Hill Companies, Inc. (Standard & Poor’s). The five largest counterparty exposures combined for this category represented 27% 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 7% 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.
Interest Rate Risk
DTE Energy is subject to interest rate risk in connection with the issuance of debt and preferred securities. In order to manage interest costs, we may use treasury locks and interest rate swap agreements. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). As of December 31, 2006, the Company has a floating rate debt to total debt ratio of approximately 18% (excluding securitized debt).
Foreign Currency Risk
DTE Energy has foreign currency exchange risk arising from market price fluctuations associated with fixed priced contracts. These contracts are denominated in Canadian dollars and are primarily for the purchase and sale of power as well as for long-term transportation capacity. To limit our exposure to foreign currency fluctuations, we have entered into a series of currency forward contracts through January 2011. Additionally, we may enter into fair value currency hedges to mitigate changes in the value of contracts or loans.

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Summary of Sensitivity Analysis
We performed a sensitivity analysis to calculate the fair values of our commodity contracts, long-term debt instruments and foreign currency forward contracts. The sensitivity analysis involved increasing and decreasing forward rates at December 31, 2006 by a hypothetical 10% and calculating the resulting change in the fair values.
The results of the sensitivity analysis calculations follow:
                         
(in Millions)   Assuming a 10%   Assuming a 10%    
Activity   increase in rates   decrease in rates   Change in the fair value of
Gas Contracts
  $ (10 )   $ 11     Commodity contracts
Power Contracts
  $ (17 )   $ 17     Commodity contracts
Oil Contracts
  $ 78     $ (62 )   Commodity options
Interest Rate Risk
  $ (314 )   $ 339     Long-term debt
Foreign Currency Risk
  $ 2     $ (2 )   Forward contracts

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Item 8. Financial Statements and Supplementary Data
The following consolidated financial statements and schedules are included herein.
             
        Page
Controls and Procedures     72  
Reports of Independent Registered Public Accounting Firm     74  
Consolidated Statement of Operations     76  
Consolidated Statement of Financial Position     77  
Consolidated Statement of Cash Flows     79  
Consolidated Statement of Changes in Shareholders’ Equity and Comprehensive Income     80  
Notes to Consolidated Financial Statements        
  Significant Accounting Policies     81  
  Synfuel Operations     88  
  New Accounting Pronouncements     90  
  Discontinued Operations     92  
  Other Impairments and Restructuring     93  
  Regulatory Matters     95  
  Nuclear Operations     104  
  Jointly Owned Utility Plant     106  
  Income Taxes     107  
  Common Stock and Earnings Per Share     109  
  Long-Term Debt and Preferred Securities     110  
  Short-Term Credit Arrangements and Borrowings     113  
  Capital and Operating Leases     114  
  Financial and Other Derivative Instruments     115  
  Commitments and Contingencies     117  
  Retirement Benefits and Trusteed Assets     121  
  Stock-based Compensation     129  
  Segment and Related Information     134  
  Supplementary Quarterly Financial Information (unaudited)     137  
 
 
  Schedule II – Valuation and Qualifying Accounts     144  

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Controls and Procedures
(a) Evaluation of disclosure controls and procedures
Management of the Company carried out an evaluation, under the supervision and with the participation of DTE Energy’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2006, which is the end of the period covered by this report. Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that such controls and procedures are effective in ensuring that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.
(b) Management’s report on internal control over financial reporting
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control system was designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of the effectiveness to future periods are subject to the risks that control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework. Based on our assessment, management believes that, as of December 31, 2006, the Company’s internal control over financial reporting was effective based on those criteria.
Our management’s assessment of the effectiveness of the Company’s internal control over financial reporting has been audited by the Company’s independent auditors, as stated in their report which is included herein.
(c) Changes in internal control over financial reporting
The Company has established a formal assessment process and related procedures to evaluate the effectiveness of internal control over financial reporting using criteria specified by COSO. The assessment process is comprehensive in scope, utilizes internal and external resources and involves many individuals at various levels of the Company in the design, testing and evaluation of internal control.
As part of the evaluation and assessment process, the Company has been improving the design and operating effectiveness of many entity-level and process-level controls. Control testing and remediation activities provide reasonable, but not absolute, assurance that a material weakness in internal control over financial reporting will be avoided. The inherent limitations of our current internal controls, a portion of which are manual by their nature, contribute to the potential for control deficiencies. Management does not believe any areas requiring further improvement constitute a material weakness in internal control over financial reporting as of December 31, 2006.

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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of DTE Energy Company:
We have audited management’s assessment, included in the accompanying Management’s report on internal control over financial reporting, that DTE Energy Company and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of December 31, 2006 and for the year then ended, and the financial statement schedule; and our report dated March 1, 2007 expressed an unqualified opinion on those consolidated financial statements and financial statement schedule and included an explanatory paragraph regarding the Company’s adoption of new accounting principles related to accounting for defined benefit pension and other postretirement plans and share based payments.
/S/ DELOITTE & TOUCHE LLP
Detroit, Michigan
March 1, 2007

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of DTE Energy Company:
We have audited the consolidated statement of financial position of DTE Energy Company and subsidiaries (the “Company”) as of December 31, 2006 and 2005, 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, 2006. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of DTE Energy Company and subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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 3 to the consolidated financial statements, in connection with the required adoption of new accounting principles, in 2006 the Company changed its method of accounting for defined benefit pension and other postretirement plans and share based payments. As discussed in Note 1 to the consolidated financial statements, in connection with the required adoption of a new accounting principle, in 2005 the Company changed its method of accounting for asset retirement obligations.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/S/ DELOITTE & TOUCHE LLP
Detroit, Michigan
March 1, 2007

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DTE Energy Company
Consolidated Statement of Operations
                         
    Year Ended December 31  
(in Millions, Except per Share Amounts)   2006     2005     2004  
Operating Revenues
  $ 9,022     $ 9,021     $ 7,069  
 
                 
 
                       
Operating Expenses
                       
Fuel, purchased power and gas
    3,056       3,530       2,007  
Operation and maintenance
    3,696       3,792       3,355  
Depreciation, depletion and amortization
    1,014       868       739  
Taxes other than income
    321       274       312  
Asset (gains) and losses, reserves and impairments, net
    107       (390 )     (219 )
 
                 
 
    8,194       8,074       6,194  
 
                 
 
                       
Operating Income
    828       947       875  
 
                 
 
                       
Other (Income) and Deductions
                       
Interest expense
    526       519       516  
Interest income
    (47 )     (57 )     (55 )
Other income
    (61 )     (68 )     (81 )
Other expenses
    86       55       67  
 
                 
 
    504       449       447  
 
                 
 
                       
Income Before Income Taxes and Minority Interest
    324       498       428  
 
                       
Income Tax Provision (Note 9)
    137       202       176  
 
                       
Minority Interest
    (250 )     (281 )     (212 )
 
                 
 
                       
Income from Continuing Operations
    437       577       464  
 
                       
Loss from Discontinued Operations, net of tax (Note 4)
    (5 )     (37 )     (33 )
 
                       
Cumulative Effect of Accounting Changes, net of tax (Notes 1, 3 and 17)
    1       (3 )      
 
                 
 
                       
Net Income
  $ 433     $ 537     $ 431  
 
                 
 
                       
Basic Earnings per Common Share (Note 10)
                       
Income from continuing operations
  $ 2.46     $ 3.30     $ 2.69  
Discontinued operations
    (.03 )     (.21 )     (.19 )
Cumulative effect of accounting changes
    .01       (.02 )      
 
                 
Total
  $ 2.44     $ 3.07     $ 2.50  
 
                 
 
                       
Diluted Earnings per Common Share (Note 10)
                       
Income from continuing operations
  $ 2.45     $ 3.28     $ 2.68  
Discontinued operations
    (.03 )     (.21 )     (.19 )
Cumulative effect of accounting changes
    .01       (.02 )      
 
                 
Total
  $ 2.43     $ 3.05     $ 2.49  
 
                 
 
                       
Average Common Shares
                       
Basic
    177       175       173  
Diluted
    178       176       173  
 
                       
Dividends Declared per Common Share
  $ 2.075     $ 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)   2006     2005  
ASSETS
               
Current Assets
               
Cash and cash equivalents
  $ 147     $ 88  
Restricted cash (Note 1)
    146       122  
Accounts receivable (less allowance for doubtful accounts of $170 and $136, respectively)
               
Customer
    1,427       1,746  
Collateral held by others
    68       286  
Other
    442       363  
Accrued power and gas supply cost recovery revenue
    117       186  
Inventories
               
Fuel and gas
    562       522  
Materials and supplies
    153       146  
Deferred income taxes
    245       257  
Assets from risk management and trading activities
    461       806  
Other
    193       160  
 
           
 
    3,961       4,682  
 
           
 
               
Investments
               
Nuclear decommissioning trust funds
    740       646  
Other
    505       530  
 
           
 
    1,245       1,176  
 
           
 
               
Property
               
Property, plant and equipment
    19,224       18,660  
Less accumulated depreciation and depletion (Note 1)
    (7,773 )     (7,830 )
 
           
 
    11,451       10,830  
 
           
 
               
Other Assets
               
Goodwill
    2,057       2,057  
Regulatory assets (Note 6)
    3,226       2,074  
Securitized regulatory assets (Note 6)
    1,235       1,340  
Intangible assets
    72       99  
Notes receivable
    164       409  
Assets from risk management and trading activities
    164       316  
Prepaid pension assets
    71       186  
Other
    139       166  
 
           
 
    7,128       6,647  
 
           
 
               
Total Assets
  $ 23,785     $ 23,335  
 
           
See Notes to Consolidated Financial Statements

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DTE Energy Company
Consolidated Statement of Financial Position
                 
    December 31  
(in Millions, Except Shares)   2006     2005  
LIABILITIES AND SHAREHOLDERS’ EQUITY
               
Current Liabilities
               
Accounts payable
  $ 1,145     $ 1,187  
Accrued interest
    115       115  
Dividends payable
    94       92  
Short-term borrowings
    1,131       943  
Current portion long-term debt, including capital leases
    354       691  
Liabilities from risk management and trading activities
    437       1,089  
Other
    888       803  
 
           
 
    4,164       4,920  
 
           
 
               
Other Liabilities
               
Deferred income taxes
    1,465       1,396  
Regulatory liabilities (Notes 1 and 6)
    765       715  
Asset retirement obligations (Notes 1 and 7)
    1,221       1,091  
Unamortized investment tax credit
    120       131  
Liabilities from risk management and trading activities
    259       527  
Liabilities from transportation and storage contracts
    157       317  
Accrued pension liability
    388       284  
Accrued postretirement liability
    1,414       406  
Deferred gains from asset sales
    36       188  
Minority interest
    42       92  
Nuclear decommissioning (Note 7)
    119       85  
Other
    312       334  
 
           
 
    6,298       5,566  
 
           
 
               
Long-Term Debt (net of current portion) (Notes 11 and 13)
               
Mortgage bonds, notes and other
    5,918       5,234  
Securitization bonds
    1,185       1,295  
Equity-linked securities
          175  
Trust preferred-linked securities
    289       289  
Capital lease obligations
    82       87  
 
           
 
    7,474       7,080  
 
           
 
               
Commitments and Contingencies (Notes 2, 6, 7 and 15)
               
 
               
Shareholders’ Equity
               
Common stock, without par value, 400,000,000 shares authorized, 177,138,060 and 177,814,429 shares issued and outstanding, respectively
    3,467       3,483  
Retained earnings
    2,593       2,557  
Accumulated other comprehensive loss
    (211 )     (271 )
 
           
 
    5,849       5,769  
 
           
 
               
Total Liabilities and Shareholders’ Equity
  $ 23,785     $ 23,335  
 
           
See Notes to Consolidated Financial Statements

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DTE Energy Company
Consolidated Statement of Cash Flows
                         
    Year Ended December 31  
(in Millions)   2006     2005     2004  
Operating Activities
                       
Net income
  $ 433     $ 537     $ 431  
Adjustments to reconcile net income to net cash from operating activities:
                       
Depreciation, depletion and amortization
    1,014       872       744  
Deferred income taxes
    28       147       129  
Gain on sale of assets, net
    (11 )     (38 )     (17 )
Gain on sale of interests in synfuel projects
    (38 )     (367 )     (219 )
Impairment of synfuel projects
    77              
Partners’ share of synfuel project losses
    (251 )     (318 )     (223 )
Contributions from synfuel partners
    197       243       141  
Cumulative effect of accounting changes
    (1 )     3        
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)
    8       (78 )     9  
 
                 
Net cash from operating activities
    1,456       1,001       995  
 
                 
 
                       
Investing Activities
                       
Plant and equipment expenditures – utility
    (1,126 )     (850 )     (815 )
Plant and equipment expenditures – non-utility
    (277 )     (215 )     (89 )
Acquisitions, net of cash acquired
    (42 )     (50 )      
Proceeds from sale of interests in synfuel projects
    246       349       221  
Proceeds from sale of assets, net
    67       60       104  
Restricted cash for debt redemptions
    (21 )     4       5  
Proceeds from sale of nuclear decommissioning trust fund assets
    253       201       254  
Investment in nuclear decommissioning trust funds
    (284 )     (235 )     (287 )
Other investments
    (10 )     (66 )     (74 )
 
                 
Net cash used for investing activities
    (1,194 )     (802 )     (681 )
 
                 
 
                       
Financing Activities
                       
Issuance of long-term debt
    612       869       736  
Redemption of long-term debt
    (687 )     (1,266 )     (759 )
Short-term borrowings, net
    291       437       33  
Issuance of common stock
    17       172       41  
Repurchase of common stock
    (61 )     (13 )      
Dividends on common stock
    (365 )     (360 )     (354 )
Other
    (10 )     (6 )     (9 )
 
                 
Net cash used for financing activities
    (203 )     (167 )     (312 )
 
                 
 
                       
Net Increase in Cash and Cash Equivalents
    59       32       2  
Cash and Cash Equivalents at Beginning of Period
    88       56       54  
 
                 
Cash and Cash Equivalents at End of Period
  $ 147     $ 88     $ 56  
 
                 
See Notes to Consolidated Financial Statements

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DTE Energy Company
Consolidated Statement of Changes in Shareholders’ Equity and Comprehensive Income
                                         
                            Accumulated    
                            Other    
    Common Stock   Retained   Comprehensive    
(Dollars in Millions, Shares in Thousands)   Shares   Amount   Earnings   Loss   Total
 
Balance, December 31, 2003
    168,607     $ 3,109     $ 2,308     $ (130 )   $ 5,287  
 
Net income
                431             431  
Issuance of new shares
    5,671       223                   223  
Dividends declared on common stock
                (357 )           (357 )
Repurchase and retirement of common stock
    (69 )     (3 )                 (3 )
Pension obligations (Note 16)
                      7       7  
Net change in unrealized losses on derivatives, net of tax
                      (15 )     (15 )
Net change in unrealized losses on investments, net of tax
                      (20 )     (20 )
Unearned stock compensation and other
          (6 )     1             (5 )
 
Balance, December 31, 2004
    174,209       3,323       2,383       (158 )     5,548  
 
Net income
                537             537  
Issuance of new shares
    3,686       172                   172  
Dividends declared on common stock
                (363 )           (363 )
Repurchase and retirement of common stock
    (288 )     (13 )                 (13 )
Pension obligations (Note 16)
                      4       4  
Net change in unrealized losses on derivatives, net of tax
                      (106 )     (106 )
Net change in unrealized losses on investments, net of tax
                      (11 )     (11 )
Unearned stock compensation and other
    207       1                   1  
 
Balance, December 31, 2005
    177,814       3,483       2,557       (271 )     5,769  
 
Net income
                433             433  
Issuance of new shares
    411       17                   17  
Dividends declared on common stock
                (368 )           (368 )
Repurchase and retirement of common stock
    (1,283 )     (32 )     (29 )           (61 )
Adjustment to initially apply SFAS No. 158 (net of tax) (Note 16)
                      (38 )     (38 )
Pension obligations (Note 16)
                      3     3
Net change in unrealized losses on derivatives, net of tax
                      102       102  
Net change in unrealized losses on investments, net of tax
                      (7 )     (7 )
Unearned stock compensation and other
    196       (1 )                 (1 )
 
Balance, December 31, 2006
    177,138     $ 3,467     $ 2,593     $ (211 )   $ 5,849  
 
The following table displays comprehensive income:
                         
(in Millions)   2006     2005     2004  
Net income
  $ 433     $ 537     $ 431  
 
                 
Other comprehensive income (loss), net of tax:
                       
Pension obligations, net of taxes of $2, $2 and $4 (Notes 6 and 16)
    3     4       7  
 
                 
Net unrealized gains (losses) on derivatives:
                       
Gains (losses) arising during the period, net of taxes of $3, $(78) and $(26)
    6       (145 )     (49 )
Amounts reclassified to income, net of taxes of $52, $21 and $18
    96       39       34  
 
                 
 
    102       (106 )     (15 )
 
                 
 
                       
Net unrealized losses on investments:
                       
Losses arising during the period, net of taxes of $(4), $(3) and $(3)
    (7 )     (6 )     (5 )
Amounts reclassified to income, net of taxes of $-, $(2) and $(8)
          (5 )     (15 )
 
                 
 
    (7 )     (11 )     (20 )
 
                 
Comprehensive income
  $ 531     $ 424     $ 403  
 
                 
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 owns the following businesses:
    The Detroit Edison Company (Detroit Edison), an electric utility engaged in the generation, purchase, distribution and sale of electric energy to approximately 2.2 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 approximately 1.3 million customers throughout Michigan; and
 
    Other non-utility subsidiaries engaged in a variety of energy related businesses such as coal transportation and marketing, and gas storage and transportation, natural gas exploration and production, power and industrial projects, energy marketing and trading and synthetic fuel.
Detroit Edison and MichCon are regulated by the MPSC. The 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 NRC, the EPA and MDEQ.
References in this report to “we,” “us,” “our,” “Company” or “DTE” are to DTE Energy and its subsidiaries, collectively.
Principles of Consolidation
We consolidate all majority owned subsidiaries and investments in entities in which we have controlling influence. Non-majority owned investments are accounted for using the equity method when the company is able to influence the operating policies of the investee. Non-majority owned investments include investments in limited liability companies, partnerships or joint ventures. When we do not influence the operating policies of an investee, the cost method is used. We eliminate all intercompany balances and transactions.
For entities that are considered variable interest entities, we apply the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46-R, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51.
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.
Revenues
Revenues from the sale and delivery of electricity, and the sale, delivery and storage of natural gas are recognized as services are provided. Detroit Edison and MichCon record revenues for electric and gas provided but unbilled at the end of each month.
Detroit Edison’s accrued revenues include a component for the cost of power sold that is recoverable through the PSCR mechanism. MichCon’s accrued revenues include a component for the cost of gas sold

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that is recoverable through the GCR mechanism. Annual PSCR and GCR proceedings before the MPSC permit Detroit Edison and MichCon to recover prudent and reasonable supply costs. Any overcollection or undercollection of costs, including interest, will be reflected in future rates. See Note 6.
Non-utility businesses recognize revenues as services are provided and products are delivered. Our Energy Trading segment records in revenues net unrealized derivative gains and losses on energy trading contracts, including those to be physically settled.
Comprehensive Income
Comprehensive income is 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 at December 31, 2006 include: unrealized gains and losses from derivatives accounted for as cash flow hedges, unrealized gains and losses on available for sale securities, minimum pension liabilities and pension and postretirement costs. As a result of the adoption of SFAS No. 158 effective December 31, 2006, the minimum pension liability is no longer recognized. Pension and postretirement costs consisting of deferred actuarial losses, prior service costs and transition amounts related to the pension and postretirement plans were recorded pursuant to SFAS No. 158.
                                 
    Net     Net         Accumulated  
    Unrealized     Unrealized     Pension and     Other  
    Losses on     Gains on     Postretirement     Comprehensive  
(in Millions)   Derivatives     Investments     Obligations     Loss  
Beginning balances
  $ (206 )   $ 22     $ (87 )   $ (271 )
Current-period change
    102       (7 )     3     98  
Adjustment to initially apply SFAS No. 158 (net of tax)
              (38 )     (38 )
 
                       
Ending balance
  $ (104 )   $ 15     $ (122 )   $ (211 )
 
                       
Cash Equivalents and Restricted Cash
Cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with remaining maturities of three months or less. Restricted cash consists of funds held to satisfy requirements of certain debt and partnership operating agreements. Restricted cash is classified as a current asset as all restricted cash is designated for interest and principal payments due within one year.
Inventories
We value fuel inventory and materials and supplies at average cost.
Gas inventory at MichCon is determined using the last-in, first-out (LIFO) method. At December 31, 2006, the replacement cost of gas remaining in storage exceeded the $77 million LIFO cost by $236 million. During 2006, MichCon liquidated 5.1 billion cubic feet of prior years’ LIFO layers. The liquidation reduced 2006 cost of gas by approximately $1 million, but had no impact on earnings as a result of the GCR mechanism. At December 31, 2005, the replacement cost of gas remaining in storage exceeded the $119 million LIFO cost by $496 million. During 2004, MichCon liquidated 5.7 billion cubic feet of prior years’ LIFO layers. The liquidation reduced 2004 cost of gas by approximately $7 million, but had no impact on earnings as a result of the GCR mechanism.
Our Energy Trading segment uses the average cost method for its gas in inventory.

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Property, Retirement and Maintenance, and Depreciation and Depletion
Summary of property by classification as of December 31:
                 
(in Millions)   2006     2005  
Property, Plant and Equipment
               
Electric Utility
               
Generation
  $ 7,667     $ 7,375  
Distribution
    6,249       6,041  
 
           
Total Electric Utility
    13,916       13,416  
 
           
 
               
Gas Utility
               
Distribution
    2,175       2,098  
Storage
    245       237  
Other
    985       929  
 
           
Total Gas Utility
    3,405       3,264  
 
           
 
               
Non-utility and Other
    1,903       1,980  
 
           
Total Property, Plant and Equipment
    19,224       18,660  
 
           
 
               
Less Accumulated Depreciation and Depletion
               
Electric Utility
               
Generation
    (3,410 )     (3,439 )
Distribution
    (2,170 )     (2,156 )
 
           
Total Electric Utility
    (5,580 )     (5,595 )
 
           
 
               
Gas Utility
               
Distribution
    (926 )     (891 )
Storage
    (108 )     (104 )
Other
    (513 )     (481 )
 
           
Total Gas Utility
    (1,547 )     (1,476 )
 
           
 
               
Non-utility and Other
    (646 )     (759 )
 
           
Total Accumulated Depreciation and Depletion
    (7,773 )     (7,830 )
 
           
Net Property, Plant and Equipment
  $ 11,451     $ 10,830  
 
           
Property is stated at cost and includes construction-related labor, materials, overheads and an allowance for funds used during construction. The cost of properties retired, less salvage value, at Detroit Edison and MichCon is charged to accumulated depreciation.
Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2. Approximately $16 million of expenses related to the anticipated Fermi 2 refueling outage scheduled for 2007 were accrued at December 31, 2006. Amounts are being accrued on a pro-rata basis over an 18-month period that began in May 2006. We have utilized the accrue-in-advance policy for nuclear refueling outage costs since the Fermi 2 plant was placed in service in 1988. This method matches the regulatory recovery of these costs in rates set by the MPSC. See Note 3.
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 3.3% in 2006, 3.4% in 2005 and 2004. The composite depreciation rate for MichCon was 2.8%, 3.2% and 3.6% in 2006, 2005, and 2004, respectively.

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The average estimated useful life for each major class of utility property, plant and equipment as of December 31, 2006 follows:
                         
Estimated Useful Lives in Years
Utility   Generation   Distribution   Transmission
Electric
    40       37       N/A  
Gas
    N/A       37       40  
Non-utility property is depreciated over its estimated useful life using straight-line, declining-balance or units-of-production methods. The estimated useful lives for major classes of non-utility assets and facilities ranges from 20 to 40 years.
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. We charge depreciation, depletion and amortization expense when we amortize the regulatory assets. We credit interest expense to reflect the accretion income on certain regulatory assets.
Intangible assets relating to capitalized software are classified as Property, Plant and Equipment and the related amortization is included in Accumulated Depreciation and Depletion on the Consolidated Statement of Financial Position. We capitalize the costs associated with computer software we develop or obtain for use in our business. We amortize intangible assets on a straight-line basis over the expected period of benefit, ranging from 5 to 20 years. Intangible assets amortization expense was $37 million in 2006, $41 million in 2005 and $43 million in 2004. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2006 were $503 million and $108 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2005 were $470 million and $168 million, respectively. Amortization expense of intangible assets is estimated to be $46 million annually for 2007 through 2011.
Asset Retirement Obligations
We have recorded asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and FASB Interpretation FIN No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. We have a legal retirement obligation for the decommissioning costs for our Fermi 1 and Fermi 2 nuclear plants. To a lesser extent, we have legal retirement obligations for the synthetic fuel operations, gas production facilities, gas gathering facilities and various other operations. We have conditional retirement obligations for gas pipeline retirement costs and disposal of asbestos at certain of our power plants. To a lesser extent, we have conditional retirement obligations at certain service centers, compressor and gate stations, and disposal costs for PCB contained within transformers and circuit breakers.
For our regulated operations, the adoptions of SFAS No. 143 and FIN 47 resulted primarily in timing differences in the recognition of legal asset retirement costs that we are currently recovering in rates. We defer such differences under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.
As a result of adopting FIN 47 on December 31, 2005, we recorded a plant asset of $26 million with offsetting accumulated depreciation of $14 million, and an asset retirement obligation liability of $124 million. We also recorded a cumulative effect amount related to utility operations as a reduction to a regulatory liability of $108 million and a cumulative effect charge against earnings of $3 million, after-tax in 2005.
No liability has been recorded with respect to lead-based paint, as the quantities of lead-based paint in our facilities are unknown. In addition, there is no incremental cost to demolitions of lead-based paint

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facilities vs. non-lead based paint facilities and no regulations currently exist requiring any type of special disposal of items containing lead-based paint.
Ludington Hydroelectric Power Plant has an indeterminate life and no legal obligation currently exists to decommission the plant at some future date. Substations, manholes and certain other distribution assets within Detroit Edison have an indeterminate life, therefore, no asset retirement liability has been recorded for these assets.
A reconciliation of the asset retirement obligations for 2006 follows:
         
(in Millions)        
Asset retirement obligations at January 1, 2006
  $ 1,091  
Accretion
    72  
Liabilities incurred
    6  
Liabilities settled
    (7 )
Revision in estimated cash flows
    59  
 
     
Asset retirement obligations at December 31, 2006
  $ 1,221  
 
     
A significant portion of the asset retirement obligations represents nuclear decommissioning liabilities which are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear plant.
Gas Production
We follow the successful efforts method of accounting for investments in gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well are expensed. The costs of development wells are capitalized, whether productive or nonproductive. Geological and geophysical costs on exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. An impairment loss is recorded to the extent that capitalized costs of unproved properties, on a property-by-property basis, are considered not to be realizable. An impairment loss is recorded if the net capitalized costs of proved gas properties exceed the aggregate related undiscounted future net revenues. Depreciation, depletion and amortization of proved gas properties are determined using the units-of-production method.
Long-Lived Assets
Our long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. If the carrying amount of the asset exceeds the expected future cash flows generated by the asset, an impairment loss is recognized resulting in the asset being written down to its estimated fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less cost to sell.
Intangible Assets
We have certain intangible assets relating to non-utility contracts and emission allowances. We amortize intangible assets on a straight-line basis over the expected period of benefit, ranging from 5 to 26 years. Intangible assets amortization expense was $5 million in 2006, $2 million in 2005 and $1 million in 2004. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2006 were $80 million and $8 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2005 were $102 million and $3 million, respectively. Amortization expense of intangible assets is estimated to be $5 million annually for 2007 through 2011.

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Excise and Sales Taxes
We record the billing of excise and sales taxes as a receivable with an offsetting payable to the applicable taxing authority, with no impact on the Consolidated Statement of Operations.
Deferred Debt Costs
The costs related to the issuance of long-term debt are deferred and amortized over the life of each debt issue. In accordance with MPSC regulations applicable to our electric and gas utilities, the unamortized discount, premium and expense related to debt redeemed with a refinancing are amortized over the life of the replacement issue. Discount, premium and expense on early redemptions of debt associated with non-utility operations are charged to earnings.
Insured and Uninsured Risks
Our comprehensive insurance program provides coverage for various types of risks. Our insurance policies cover risk of loss from property damage, general liability, workers’ compensation, auto liability and directors’ and officers’ liability. Under our risk management policy, we self-insure portions of certain risks up to specified limits, depending on the type of exposure. We have an actuarially determined estimate of our incurred but not reported liability prepared annually and adjust our reserves for self-insured risks as appropriate.
Investments in Debt and Equity Securities
We generally classify investments in debt and equity securities as either trading or available-for-sale and have recorded such investments at market value with unrealized gains or losses included in earnings or in other comprehensive income or loss, respectively. Changes in the fair value of nuclear decommissioning-related investments are recorded as adjustments to regulatory assets or liabilities. Our investments are reviewed for impairment each reporting period. If the assessment indicates that the impairment is other than temporary, a loss is recognized resulting in the investment being written down to its estimated fair value. See Note 7.
Investment in Plug Power
We own 8.8 million shares of Plug Power Inc. We account for our investment under the cost method of accounting. We record our investment at market value and account for unrealized gains and losses in other comprehensive income or loss. In December 2005, we contributed 1.8 million shares of Plug Power to the DTE Energy Foundation that resulted in a gain of approximately $1 million due to related tax effects. In May 2004, we sold 3.5 million shares of Plug Power stock and recorded a gain of approximately $14 million (net of taxes).
Consolidated Statement of Cash Flows
A detailed analysis of the changes in assets and liabilities that are reported in the Consolidated Statement of Cash Flows follows:

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(in Millions)   2006     2005     2004  
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
                       
Accounts receivable, net
  $ 441     $ (633 )   $ 11  
Accrued GCR revenue
    120       (16 )     (35 )
Inventories
    (49 )     (6 )     (40 )
Recoverable pension and postretirement costs
    (1,184 )     61       (20 )
Accrued/Prepaid pensions
    218       17       88  
Accounts payable
    (68 )     290       266  
Accrued PSCR refund
    (101 )     (127 )     112  
Exchange gas payable
          5       (43 )
Income taxes payable
    46       (38 )     (170 )
General taxes
    3       (11 )     (14 )
Risk management and trading activities
    (518 )     353       (64 )
Postretirement obligation
    1,008       132       29  
Other assets
    (134 )     (9 )     75  
Other liabilities
    226       (96 )     (186 )
 
                 
 
  $ 8     $ (78 )   $ 9  
 
                 
Supplementary cash and non-cash information for the years ended December 31, were as follows:
                         
(in Millions)   2006   2005   2004
Cash Paid for:
                       
Interest (excluding interest capitalized)
  $ 526     $ 516     $ 517  
Income taxes
  $ 89     $ 80     $ 203  
Noncash Investing and Financing Activities
                       
Notes received from sale of synfuel projects
  $     $ 20     $ 214  
Common stock contribution to pension plan
  $     $     $ 170  
Sale of assets
                       
Note receivable
  $     $ 47     $  
Other assets
  $     $ 45     $  
We entered into a margin loan facility with an affiliate of the clearing agent of a commodity exchange in lieu of posting additional cash collateral (a non-cash transaction). The amount outstanding under the Facility was $103 million as of December 31, 2005. In October 2006, we changed our clearing agent and entered into a new demand financing agreement for up to $150 million. The amount outstanding under this new agreement was $23 million at December 31, 2006. See Note 12.
In October 2006, we purchased the lessor interest in the 66 Bcf Washington 10 gas storage field. Prior to the purchase, we leased the storage rights and lease obligations which were recorded as operating leases. The acquisition resulted in a cash payment of approximately $13 million and the assumption of approximately $133 million of project related debt that was recorded on our Consolidated Statement of Financial Position. See Note 11.

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Asset (gains) and losses, reserves and impairments, net
The following items are included in the Asset (gains) and losses, reserves and impairments, net line in the Consolidated Statement of Operations:
                         
(in Millions)                  
Description   2006     2005     2004  
Synfuel (Gains) Losses, Reserves and Impairments
                       
Gains recognized for fixed payments
  $ (43 )   $ (132 )   $ (95 )
Gains recognized for variable payments
    (14 )     (187 )     (136 )
Reserves for contractual partners’ obligations
    79              
Other reserves and impairments, including partners’ share
    78              
Hedges (mark-to-market)
    (60 )     (48 )     12  
 
                 
Synfuels (net)
    40       (367 )     (219 )
 
                       
Other Non-utility impairments:
                       
Waste coal recovery
    19              
Landfill gas recovery
    14              
Power generation
    42              
 
                 
 
    75              
Electric utility sale of land
    (6 )     (26 )      
Other
    (2 )     3        
 
                 
 
  $ 107     $ (390 )   $ (219 )
 
                 
See the following notes for other accounting policies impacting our financial statements:
         
Note   Title
  3    
New Accounting Pronouncements
  6    
Regulatory Matters
  9    
Income Taxes
  14    
Financial and Other Derivative Instruments
  16    
Retirement Benefits and Trusteed Assets
  17    
Stock-based Compensation
NOTE 2 – SYNFUEL OPERATIONS
Synthetic Fuel Operations
We are the operator of nine synthetic fuel production facilities throughout the United States. Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applicable Internal Revenue Service rules. Production tax credits are provided for the production and sale of solid synthetic fuels produced from coal. To qualify for the production tax credits, the synthetic fuel must meet three primary conditions: (1) there must be a significant chemical change in the coal feedstock, (2) the product must be sold to an unaffiliated entity, and (3) the production facility must have been placed in service before July 1, 1998. Through December 31, 2006, we have generated and recorded approximately $580 million in production tax credits.
To reduce U.S. dependence on imported oil, the Internal Revenue Code provides production tax credits as an incentive for taxpayers to produce fuels from alternative sources. This incentive is not deemed necessary if the price of oil increases and provides significant market incentives for the production of these fuels. As such, the tax credit in a given year is reduced if the Reference Price of oil within that year exceeds a threshold price. The Reference Price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil. We project the yearly average wellhead price per barrel

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of oil for the year to be approximately $6 lower than the New York Mercantile Exchange (NYMEX) price for light, sweet crude oil. The threshold price at which the credit begins to be reduced was set in 1980 and is adjusted annually for inflation. For 2006, we estimate the threshold price at which the tax credit would begin to be reduced is $55 per barrel and would be completely phased out if the Reference Price reached $69 per barrel. As of December 31, 2006, the realized NYMEX daily closing price of a barrel of oil was approximately $66 for 2006, equating to an estimated Reference Price of $60, which we estimate to be within the phase-out range.
To mitigate the effect of a potential phase-out and minimize operating losses we idled production at all nine of the synthetic fuel facilities that we operate on May 12, 2006. The decision to idle synfuel production was driven by the level and volatility of oil prices at that time. During the idle period, we took various steps to reduce our oil price exposure, including, renegotiation of a significant number of commercial agreements. Beginning September 5, 2006 through October 4, 2006, we resumed production at each of the nine synfuel facilities due to these amended commercial agreements and declines in the level of oil prices.
Gains (Losses) from Sale of Interests in Synthetic Fuel Facilities
Through December 2006, we have sold interests in all of the synthetic fuel production plants, representing approximately 91% of our total production capacity. Proceeds from the sales are contingent upon production levels, the production qualifying for production tax credits, and the value of such credits. Production tax credits are subject to phase-out if domestic crude oil prices reach certain levels. We recognize gains from the sale of interests in the synfuel facilities as synfuel is produced and sold, and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectibility is reasonably assured. Until the gain recognition criteria are met, gains from selling interests in synfuel facilities are deferred. It is possible that gains will be deferred in the first, second and/or third quarters of each year until there is persuasive evidence that no tax credit phase-out will occur for the applicable calendar year. This could result in shifting earnings from earlier quarters to later quarters of a calendar year. We have recorded a pre-tax loss of $40 million in 2006 and pre-tax gains of $367 million and $219 million in 2005 and 2004, respectively, from the sale of interests in synthetic fuel facilities, net of reserves and impairments.
The gain from the sale of synfuel facilities is comprised of fixed and variable components. The fixed component represents note payments, is not subject to refund, and is recognized as a gain when earned and collectibility is assured. The variable component is based on an estimate of tax credits allocated to our partners and is subject to refund based on the annual oil price phase-out. The variable component is recognized as a gain only when the probability of refund is considered remote and collectibility is assured. Additionally, our partners reimburse us (through the project entity) for the operating losses of the synfuel facilities, referred to as capital contributions. In the event that the tax credit is phased out, we are contractually obligated to refund an amount equal to all or a portion of the operating losses funded by our partners. To assess the probability and estimate the amount of refund, we use valuation and analysis models that calculate the probability of the Reference Price of oil for the year being within or exceeding the phase-out range. We recorded reserves for contractual partners’ obligations of $79 million in 2006.
Derivative Instruments - Commodity Price Risk
To manage our exposure to the risk of an increase in oil prices that could substantially reduce or eliminate synfuel sales proceeds, we entered into a series of derivative contracts covering a specified number of barrels of oil. The derivative contracts involve purchased and written call options that provide for net cash settlement at expiration based on the full years’ average NYMEX trading prices for light, sweet crude oil in relation to the strike prices of each option. These contracts are based on various terms to take advantage of favorable oil price movements. The agreements do not qualify for hedge accounting, therefore, the changes in the fair value of the options are recorded currently in earnings. The fair value changes shown below are recorded as adjustments to the gain from selling interests in synfuel facilities and are included in the Asset gains and losses, reserves and impairments, net line item in the Consolidated Statement of Operations.
                         
(in Millions)   2006     2005     2004  
Hedge (gains) losses (mark-to-market)
                       
Hedges for 2005 exposure
  $     $ (2 )   $ 12  
Hedges for 2006 exposure
    (66 )     (40 )      
Hedges for 2007 exposure
    6       (6 )      
 
                 
 
  $ (60 )   $ (48 )   $ 12  
 
                 

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Impairments and Reserves
In 2006, we determined that certain assets related to our synfuel operations were impaired. The decision to record an impairment was based on the level and volatility of oil prices and the ability of the synfuel operations to generate production tax credits. In 2006, we recorded a pre-tax loss of $157 million within the Asset (gains) and losses, reserves and impairments, net, line item in the Consolidated Statement of Operations. The loss consists of two components; $78 million for synfuel related fixed asset impairment and inventory write-down and $79 million for a reserve for capital contributions related to operating losses. We based the impairment decision on an analysis of the undiscounted cash flows from the use and eventual disposition of the assets and determined that the carrying amount of the assets exceeded their expected fair value. The income impact of the fixed asset impairment and inventory write-down was partially offset by $70 million, representing our partners’ share of the asset write down, included in the Minority Interest line in the Consolidated Statement of Operations.
Guarantees
We have provided certain guarantees and indemnities in conjunction with the sales of interests in our synfuel facilities. The guarantees cover potential commercial, environmental, oil price and tax-related obligations and will survive until 90 days after expiration of all applicable statute of limitations. We estimate that our maximum potential liability under these guarantees at December 31, 2006 is $2.4 billion. At December 31, 2006, we have reserved $181 million of our maximum potential liability primarily representing the possible refund of certain payments made by our synfuel partners.
NOTE 3 – NEW ACCOUNTING PRONOUNCEMENTS
Accounting for Uncertainty in Income Taxes
In July 2006, the FASB issued Financial Interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109 – Accounting for Income Taxes. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109. Additionally, it prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in the tax return. FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition and is effective for fiscal years beginning after December 15, 2006. We plan to adopt FIN 48 effective January 1, 2007. We do not expect the adoption to have a material impact to the January 1, 2007 balance of retained earnings.

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Fair Value Accounting
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. It emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Fair value measurement should be determined based on the assumptions that market participants would use in pricing an asset or liability. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We plan to adopt SFAS 157 on January 1, 2008. We are currently assessing the effects of this statement, and have not yet determined the impact on the consolidated financial statements.
In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115. This standard permits an entity to choose to measure many financial instruments and certain other items at fair- value. The fair value option established by SFAS 159 permits all entities to choose to measure eligible items at fair value at specified election dates. An entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to entire instruments and not to portions of instruments. SFAS 159 is effective as of the beginning of an entity's first fiscal year that begins after November 15, 2007. We are currently assessing the effects of this statement, and have not yet determined the impact on the consolidated financial statements.
Accounting for Defined Benefit Pension and Other Postretirement Plans
In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an Amendment of FASB Statements No. 87, 88, 106, and 132(R). SFAS 158 requires companies to (1) recognize the overfunded or underfunded status of defined benefit pension and defined benefit other postretirement plans in its financial statements, (2) recognize as a component of other comprehensive income, net of tax, the actuarial gains or losses and the prior service costs or credits that arise during the period but are not immediately recognized as components of net periodic benefit cost, (3) recognize adjustments to other comprehensive income when the actuarial gains or losses, prior service costs or credits, and transition assets or obligations are recognized as components of net periodic benefit cost, (4) measure postretirement benefit plan assets and plan obligations as of the date of the employer’s statement of financial position, and (5) disclose additional information in the notes to financial statements about certain effects on net periodic benefit cost in the upcoming fiscal year that arise from delayed recognition of the actuarial gains and losses and the prior service cost and credits.
The requirement to recognize the funded status of a defined benefit pension or defined benefit other postretirement plan and the related disclosure requirements was effective for fiscal years ending after December 15, 2006, and we adopted this portion of the standard on December 31, 2006. We requested and received agreement from the MPSC to record the additional liability amounts for Detroit Edison and MichCon on the balance sheet as a regulatory asset.
The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. The Statement provides two options for the transition to a fiscal year end measurement date. We currently use a November 30 measurement date. We have not yet determined which of the available transition measurement options we will use.
See Note 16.
Accounting for Planned Major Maintenance
In September 2006, the FASB issued its Staff Position (FSP), AUG AIR-1, Accounting for Planned Major Maintenance Activities. This FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. We have historically charged expenditures for maintenance and repairs to expense as they were incurred, with the exception of Fermi 2, where we have utilized the accrue-in-advance policy for nuclear refueling outage costs since the plant was placed in service in 1988. We adopted this FSP on December 31, 2006. Although this FSP prohibits use of the accrue-in-advance method, we will continue to use it to account for the cost of Fermi 2 refueling outages because it matches the regulatory recovery of these costs in rates set by the MPSC and, therefore is in compliance with the requirements of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. The adoption of FSP AUG AIR-1 had no income impact on our financial statements. See Note 6.

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Quantifying Misstatements
In September 2006, the SEC staff issued Staff Accounting Bulletin (SAB) Topic 1N, Financial Statements — Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements (SAB 108). SAB 108 addresses how a registrant should quantify the effect of an error on the financial statements. The SEC staff concluded in SAB 108 that a dual approach should be used to compute the amount of a misstatement. Specifically, the amount should be computed using both the “rollover” (current year income statement perspective) and “iron curtain” (year-end balance sheet perspective) methods. We adopted this SAB effective December 31, 2006. Based on our assessment we identified no errors that would require an adjustment to current or prior financial statements; therefore, the adoption of SAB 108 had no financial statement impact.
Stock Based Compensation
We adopted SFAS No. 123(R), Share Based Payments effective January 1, 2006. Previously we had been following the recognition and measurement principles of Accounting Principles Board (APB) No. 25, Accounting for Stock Issued to Employees, and followed the nominal vesting period approach for awards with retirement eligibility provisions. See Note 17 for the effects of the adoption of SFAS No. 123(R).
NOTE 4 – DISCONTINUED OPERATIONS
DTE Georgetown (Georgetown)
We own Georgetown, an 80 MW natural gas-fired peaking electric generating plant. In the fourth quarter of 2006, management approved the marketing of Georgetown for sale. In December 2006, Georgetown met the SFAS No. 144 criteria of an asset “held for sale” and we reported its operating results as a discontinued operation. We did not recognize an impairment loss since the net book value of Georgetown’s assets, less costs to sell approximated its fair value. As of December 31, 2006, Georgetown’s assets are $23 million and its liabilities are $1 million. In February 2007, we entered into an agreement to sell our Georgetown peaking electric generating facility. The sale is subject to receipt of regulatory approval and is expected to close in the second half of 2007.
As shown in the following table, we have reported the business activity of Georgetown as a discontinued operation. The amounts exclude general corporate overhead costs:
                         
    Year Ended December 31  
(in Millions)   2006     2005     2004  
Revenues (1)
  $ 1     $ 1     $ 2  
Expenses
    3       2       7  
 
                 
Loss before income taxes
    (2 )     (1 )     (5 )
Income tax benefit
                (2 )
 
                 
Loss from discontinued operations
  $ (2 )   $ (1 )   $ (3 )
 
                 
 
(1)   Includes intercompany revenues of $1 million for 2006, 2005 and 2004.
DTE Energy Technologies (Dtech)
We own Dtech, which assembled, marketed, distributed and serviced distributed generation products, provided application engineering, and monitored and managed on-site generation system operations. In July 2005, management approved the restructuring of this business resulting in the identification of certain assets and liabilities to be sold or abandoned, primarily associated with standby and continuous

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duty generation sales and service. The systems monitoring business is planned to be retained by the Company.
During the third quarter of 2005, the restructuring plan met criteria to classify the assets as “held for sale.” Accordingly, we recognized a net of tax restructuring loss of $23 million during the third quarter of 2005 primarily representing the write down to fair value of the assets of Dtech, less costs to sell, and the write-off of goodwill of $16 million. At December 31, 2006, Dtech had liabilities of $3 million.
As shown in the following table, we have reported the business activity of Dtech as a discontinued operation. The amounts exclude general corporate overhead costs and operations that are to be retained. We expect continued legal and warranty expenses in 2007 related to Dtech’s operations prior to July 2005.
                         
    Year Ended December 31  
(in Millions)   2006     2005     2004  
Revenues (1)
  $ 1     $ 18     $ 43  
Expenses
    6       67       70  
 
                 
Loss before income taxes
    (5 )     (49 )     (27 )
Income tax benefit
    (2 )     (14 )     (9 )
 
                 
Loss from discontinued operations
  $ (3 )   $ (35 )   $ (18 )
 
                 
 
(1)   Includes intercompany revenues of $6 million for 2005 and $5 million for 2004.
Southern Missouri Gas Company
We owned Southern Missouri Gas Company (SMGC), a public utility engaged in the distribution, transmission and sale of natural gas in southern Missouri. In the first quarter of 2004, management approved the marketing of SMGC for sale. As of March 31, 2004, SMGC met the SFAS No. 144 criteria of an asset “held for sale” and we reported its operating results as a discontinued operation. We recognized a net of tax impairment loss in 2004 of approximately $7 million, representing the write-down to fair value of the assets of SMGC, less costs to sell, and the write-off of allocated goodwill. In November 2004, we entered into a definitive agreement providing for the sale of SMGC. Regulatory approval was received in April 2005 and the sale was closed in May 2005. During the second quarter of 2005, we recognized a net of tax gain of $2 million.
NOTE 5 – OTHER IMPAIRMENTS AND RESTRUCTURING
Other Impairments
Waste Coal Recovery
In 2006, our Power and Industrial Projects segment impaired its investment in proprietary technology used to refine waste coal. The fixed assets at our development operation were impaired due to continued operating losses and negative cash flow. In addition, we impaired all our patents related to waste coal technology. We calculated the expected undiscounted cash flows from the use and eventual disposition of the assets, which indicated that the carrying amount of the assets was not recoverable. We determined the fair value of the assets utilizing a discounted cash flow technique. Through December 31, 2006, we have recorded a pre-tax impairment loss of $19 million within the Asset (gains) and losses, reserves and impairments, net line in the Consolidated Statement of Operations.

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Landfill Gas Recovery
In 2006, our Power and Industrial Projects segment recorded a pre-tax impairment loss of $14 million at our landfill gas recovery unit relating to the write-down of assets at several landfill sites. The fixed assets were impaired due to continued operating losses and the oil price-related phase-out of production tax credits. The impairment was recorded within the Asset (gains) and losses, reserves and impairments, net line in the Consolidated Statement of Operations. We calculated the expected undiscounted cash flows from the use and eventual disposition of the assets, which indicated that the carrying amount of certain assets was not recoverable. We determined the fair value of the assets utilizing a discounted cash flow technique.
Non-Utility Power Generation
In 2006, our Power and Industrial Projects segment recorded a pre-tax impairment loss totaling $74 million for its investments in two natural gas-fired electric generating plants.
A loss of $42 million related to a 100% owned plant is recorded within the Asset (gains) and losses, reserves and impairments, net line in the Consolidated Statement of Operations. The generating plant was impaired due to continued operating losses and the September 2006 delisting by MISO, resulting in the plant no longer providing capacity for the power grid. We calculated the expected undiscounted cash flows from the use and eventual disposition of the plant, which indicated that the carrying amount of the plant was not recoverable. We determined the fair value of the plant utilizing a discounted cash flow technique.
A loss of $32 million related to a 50% equity interest in a peaking, gas-fired electric generating plant is recorded within the Other (income) and deductions, other expenses line in the Consolidated Statement of Operations. The investment was impaired due to continued operating losses and the expected sale of the investment. We determined the fair value of the plant utilizing a discounted cash flow technique, which indicated that the carrying amount of the investment exceeded its fair value.
Restructuring – Performance Excellence Process
In mid-2005, we initiated a company-wide review of our operations called the Performance Excellence Process. Specifically, we began a series of focused improvement initiatives within our Electric and Gas Utilities, and associated corporate support functions. We expect this process will be carried out over a two to three year period beginning in 2005.
We have incurred CTA for employee severance and other costs. Other costs include project management and consultant support. Pursuant to MPSC authorization, in 2006, Detroit Edison deferred approximately $102 million of CTA. Detroit Edison will begin amortizing deferred 2006 costs in 2007 as the recovery of these costs was provided for by the MPSC. MichCon cannot defer CTA costs at this time because a recovery mechanism has not been established. See Note 6.

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Amounts expensed are recorded in the Operation and maintenance line on the Consolidated Statement of Operations. Deferred amounts are recorded in the Regulatory asset line on the Consolidated Statement of Financial Position. Expenses incurred in 2006 are as follows:
                         
(in Millions)   Employee              
Business Segment   Severance Costs     Other Costs     Total Costs  
Costs incurred:
                       
Electric Utility
  $ 51     $ 56     $ 107  
Gas Utility
    17       7       24  
Other
    2       1       3  
 
                 
Total costs
    70       64       134  
 
Less amounts deferred or capitalized:
                       
Electric Utility
    51       56       107  
 
                 
Amounts expensed
  $ 19     $ 8     $ 27  
 
                 
A liability for future CTA associated with the Performance Excellence Process has not been recognized because we have not met the recognition criteria of SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities.
NOTE 6 – REGULATORY MATTERS
Regulation
Detroit Edison and MichCon are subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to rates, recovery of certain costs, including the costs of generating facilities and regulatory assets, conditions of service, accounting and operating-related matters. Detroit Edison is also regulated by the FERC with respect to financing authorization and wholesale electric activities.
As subsequently discussed in the “Electric Industry Restructuring” section, Detroit Edison’s rates were frozen through 2003 and capped for small business customers through 2004 and for residential customers through 2005 as a result of Public Act (PA) 141. However, Detroit Edison was allowed to defer certain costs to be recovered once rates could be increased, including costs incurred as a result of changes in taxes, laws and other governmental actions.
Regulatory Assets and Liabilities
Detroit Edison and MichCon apply the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, to their regulated operations. SFAS No. 71 requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as revenue and expense in non-regulated businesses. Continued applicability of SFAS No. 71 requires that rates be designed to recover specific costs of providing regulated services and be charged to and collected from customers. Future regulatory changes or changes in the competitive environment could result in the Company discontinuing the application of SFAS No. 71 for some or all of its utility businesses and may require the write-off of the portion of any regulatory asset or liability that was no longer probable of recovery through regulated rates. Management believes that currently available facts support the continued application of SFAS No. 71 to Detroit Edison and MichCon.

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The following are balances and a brief description of the regulatory assets and liabilities at December 31:
                 
(in Millions)   2006     2005  
Assets
               
Securitized regulatory assets
  $ 1,235     $ 1,340  
 
           
 
               
Recoverable income taxes related to securitized regulatory assets
  $ 677     $ 734  
Recoverable pension and postretirement costs
    1,728       544  
Asset retirement obligation
    236       196  
Other recoverable income taxes
    100       104  
Recoverable costs under PA 141
               
Net stranded costs
          112  
Excess capital expenditures
    22       22  
Deferred Clean Air Act expenditures
    67       82  
Midwest Independent System Operator charges
    48       56  
Electric Customer Choice implementation costs
    78       98  
Enhanced security costs
    13       13  
Unamortized loss on reacquired debt
    69       73  
Deferred environmental costs
    40       34  
Accrued PSCR/GCR revenue
    117       186  
Recoverable uncollectibles expense
    45       11  
Cost to achieve Performance Excellence Process
    102        
Enterprise Business Systems costs
    9        
Other
    3       6  
 
           
 
    3,354       2,271  
Less amount included in current assets
    (128 )     (197 )
 
           
 
  $ 3,226     $ 2,074  
 
           
 
               
Liabilities
               
Asset removal costs
  $ 576     $ 567  
Accrued pension
    72       23  
Safety and training cost refund
    3        
Accrued PSCR/GCR refund
    81       129  
Refundable income taxes
    114       125  
Fermi 2 refueling outage
    16       25  
Other
    2       2  
 
           
 
    864       871  
Less amount included in current liabilities
    (99 )     (156 )
 
           
 
  $ 765     $ 715  
 
           
ASSETS
  Securitized regulatory assets — The net book balance of the Fermi 2 nuclear plant was written off in 1998 and an equivalent regulatory asset was established. In 2001, the Fermi 2 regulatory asset and certain other regulatory assets were securitized pursuant to PA 142 and an MPSC order. A non-bypassable securitization bond surcharge recovers the securitized regulatory asset over a fourteen-year period ending in 2015.
 
  Recoverable income taxes related to securitized regulatory assets — Receivable for the recovery of income taxes to be paid on the non-bypassable securitization bond surcharge. A non-bypassable securitization tax surcharge recovers the income tax over a fourteen-year period ending 2015.
 
  Recoverable pension and postretirement costs — The traditional rate setting process allows for the recovery of pension and postretirement costs as measured by generally accepted accounting principles. In 2006, we adopted SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. See Note 16.
 
  Asset retirement obligation — Asset retirement obligations were recorded pursuant to adoption of SFAS No. 143 in 2003 and FIN 47 in 2005. These obligations are primarily for Fermi 2 decommissioning costs that are recovered in rates.

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  Other recoverable income taxes — Income taxes receivable from Detroit Edison’s customers representing the difference in property-related deferred income taxes receivable and amounts previously reflected in Detroit Edison’s rates.
 
  Net stranded costs — PA 141 permits, after MPSC authorization, the recovery of and a return on fixed cost deficiency associated with the electric Customer Choice program. Net stranded costs occurred when fixed cost related revenues did not cover the fixed cost revenue requirements.
 
  Excess capital expenditures — Starting in 2004, PA 141 permits, after MPSC authorization, the recovery of and a return on capital expenditures that exceed a base level of depreciation expense.
 
  Deferred Clean Air Act expenditures — PA 141 permits, after MPSC authorization, the recovery of and a return on Clean Air Act expenditures.
 
  Midwest Independent System Operator charges — PA 141 permits, after MPSC authorization, the recovery of and a return on charges from a regional transmission operator such as the Midwest Independent System Operator.
 
  Electric Customer Choice implementation costs — PA 141 permits, after MPSC authorization, the recovery of and a return on costs incurred associated with the implementation of the electric Customer Choice program.
 
  Enhanced security costs — PA 609 of 2002 permits, after MPSC authorization, the recovery of enhanced security costs for an electric generating facility.
 
  Unamortized loss on reacquired debt — The unamortized discount, premium and expense related to debt redeemed with a refinancing are deferred, amortized and recovered over the life of the replacement issue.
 
  Deferred environmental costs — The MPSC approved the deferral and recovery of investigation and remediation costs associated with Gas Utility’s former MGP sites.
 
  Accrued GCR revenue — Receivable for the temporary under-recovery of and a return on gas costs incurred by MichCon which are recoverable through the GCR mechanism.
 
  Accrued PSCR revenue — Receivable for the temporary under-recovery of and a return on fuel and purchased power costs incurred by Detroit Edison which are recoverable through the PSCR mechanism.
 
  Recoverable uncollectibles expense — MichCon receivable for the MPSC approved uncollectible expense true-up mechanism that tracks the difference in the fluctuation in uncollectible accounts and amounts recognized pursuant to the MPSC authorization. Of the total amount deferred, $11 million represents 2005 expenses and is expected to be recovered during 2007. The remainder relates to 2006 expense, the recovery period of which will be determined upon receipt of an MPSC order.
 
  Cost to achieve Performance Excellence Process (PEP) – The MPSC authorized the deferral of costs to implement the PEP. These costs consist of employee severance, project management and consultant support. These costs will be amortized over a ten-year period beginning with the year subsequent to the year the costs were deferred. See Note 5.
 
  Enterprise Business Systems (EBS) Costs – Starting in 2006, the MPSC approved the deferral of up to $60 million of certain EBS costs that would otherwise be expensed.
LIABILITIES
  Asset removal costs — The amount collected from customers for the funding of future asset removal activities.
 
  Accrued pension — Pension expense refundable to customers representing the difference created from volatility in the pension obligation and amounts recognized pursuant to MPSC authorization.
 
  Safety and training cost refund – The MPSC ordered the refund of unspent costs which were included in the Company’s rate structure.
 
  Accrued PSCR refund — Payable for the temporary over-recovery of and a return on power supply costs, and beginning with the MPSC’s November 2004 rate order, transmission costs incurred by Detroit Edison which are recoverable through the PSCR mechanism.
 
  Accrued GCR Refund - Liability for the temporary over-recovery of and a return on gas costs incurred by MichCon which are recoverable through the GCR mechanism.

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  Refundable income taxes — Income taxes refundable to MichCon’s customers representing the difference in property-related deferred income taxes payable and amounts recognized pursuant to MPSC authorization.
 
  Fermi 2 refueling outage – Liability for refueling outage at Fermi 2 pursuant to MPSC authorization. See Note 3.
Electric Rate Restructuring Proposal
In February 2005, Detroit Edison filed a rate restructuring proposal with the MPSC to restructure its electric rates and begin phasing out subsidies within the current pricing structure. In December 2005, the MPSC issued an order that did not provide for the comprehensive realignment of the existing rate structure that Detroit Edison requested in its rate restructuring proposal. The MPSC order did take some initial steps to improve the current competitive imbalance in Michigan’s electric Customer Choice program. The December 2005 order established cost-based power supply rates for Detroit Edison’s full service customers. Electric Customer Choice participants will pay cost-based distribution rates, while Detroit Edison’s full service commercial and industrial customers will pay cost-based distribution rates that reflect the cost of the residential rate subsidy. Residential customers continue to pay a subsidized below-cost rate for distribution service. These revenue neutral revised rates were effective February 1, 2006. Detroit Edison was also ordered to file a general rate case by July 1, 2007, based on 2006 actual results.
Other Postretirement Benefits Costs Tracker
In February 2005, Detroit Edison filed an application, pursuant to the MPSC’s November 2004 final rate order, requesting MPSC approval of a proposed tracking mechanism for retiree health care costs. This mechanism would recognize differences between cost levels collected in rates and the actual costs under current accounting rules as regulatory assets or regulatory liabilities with an annual reconciliation proceeding before the MPSC. In February 2006, the MPSC denied Detroit Edison’s request and ordered that this issue be addressed in the next general rate case due to be filed by July 1, 2007.
MPSC Show-Cause Order
In March 2006, the MPSC issued an order directing Detroit Edison to show cause by June 1, 2006 why its retail electric rates should not be reduced in 2007. The MPSC cited certain changes that had occurred since the November 2004 order in Detroit Edison’s last general rate case, or were expected to occur. These changes included: declines in electric Customer Choice program participation, expiration of the residential rate caps, and projected reductions in Detroit Edison operating costs. The show cause filing was to reflect sales, costs and financial conditions that were expected to occur by 2007. On June 1, 2006, Detroit Edison filed its response explaining why its electric rates should not be reduced in 2007. Detroit Edison indicated that it will have a revenue deficiency of approximately $45 million beginning in 2007 due to significant capital investments over the next several years for infrastructure improvements to enhance electric service reliability and for mandated environmental expenditures. The impacts of these investments will be partially offset by efficiency and cost-savings measures that have been initiated. Therefore, Detroit Edison requested that the show cause proceeding allow for rate increase adjustments based on the combined effects of investment expenditures and cost-savings programs. The MPSC denied this request and indicated that a full review of rates will be made in Detroit Edison’s next general rate case, which is due to be filed by July 1, 2007.
The MPSC issued an order approving a settlement agreement in this proceeding on August 31, 2006. The order provided for an annualized rate reduction of $53 million for 2006, effective September 5, 2006. Beginning January 1, 2007, and continuing until the later of March 31, 2008 or 12 months from the filing date of Detroit Edison’s next general rate case, rates will be reduced by an additional $26 million, for a

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total reduction of $79 million. The revenue reduction is net of the recovery of the amortization of the costs associated with the implementation of the Performance Excellence Process. The settlement agreement provides for some level of realignment of the existing rate structure by allocating a larger percentage share of the rate reduction to the commercial and industrial customer classes than to the residential customer classes.
As part of the settlement agreement, a Choice Incentive Mechanism (CIM) was established with a base level of electric choice sales set at 3,400 GWh. The CIM prescribes regulatory treatment of changes in non-fuel revenue attributed to increases or decreases in electric Customer Choice sales. The CIM has a deadband of ±200 GWh. If electric Customer Choice sales exceed 3,600 GWh, Detroit Edison will be able to recover 90% of its reduction in non-fuel revenue from full service customers up to $71 million. If electric Customer Choice sales fall below 3,200 GWh, Detroit Edison will credit 100% of the increase in non-fuel revenue to the unrecovered regulatory asset recovery balances.
Regulatory Accounting Treatment for Performance Excellence Process
In May 2006, Detroit Edison and MichCon filed applications with the MPSC to allow deferral of costs associated with the implementation of the Performance Excellence Process, a company-wide cost-savings and performance improvement program. Implementation costs include project management, consultant support and employee severance expenses. Detroit Edison and MichCon sought MPSC authorization to defer and amortize Performance Excellence Process implementation costs for accounting purposes to match the expected savings from the Performance Excellence Process program with the related CTA. Detroit Edison and MichCon anticipate that the Performance Excellence Process will be carried out over a two to three year period beginning in 2006. Detroit Edison’s CTA is estimated to total between $160 million and $190 million. MichCon’s CTA is estimated to total between $55 million and $60 million. In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison and MichCon, commencing in 2006, to defer the incremental CTA. Further, the order provides for Detroit Edison and MichCon to amortize the CTA deferrals over a ten-year period beginning with the year subsequent to the year the CTA was deferred. Detroit Edison recorded the deferred CTA costs of $102 million as a regulatory asset and will begin amortizing deferred 2006 costs in 2007 as the recovery of these costs was provided for by the MPSC in the order approving the settlement in the show cause proceeding. MichCon cannot defer CTA costs at this time because a recovery mechanism has not been established.
Electric Industry Restructuring
In 2000, the Michigan Legislature enacted PA 141 that reduced electric retail rates by 5%, as a result of savings derived from the issuance of securitization bonds. The legislation also contained provisions freezing rates through 2003 and preventing rate increases (i.e., rate caps) for small business customers through 2004 and for residential customers through 2005. The price freeze period expired on February 20, 2004 pursuant to an MPSC order. In addition, PA 141 codified the MPSC’s existing electric Customer Choice program and provided Detroit Edison with the right to recover net stranded costs associated with electric Customer Choice. Detroit Edison was also allowed to defer certain costs to be recovered once rates could be increased, including costs incurred as a result of changes in taxes, laws and other governmental actions.
As required by PA 141, the MPSC conducted a proceeding to develop a methodology for calculating net stranded costs associated with electric Customer Choice. In a December 2001 order, the MPSC determined that Detroit Edison could recover net stranded costs associated with the fixed cost component of its electric generation operations. Specifically, there would be an annual proceeding or true-up before the MPSC reconciling the receipt of revenues associated with the fixed cost component of its generation services to the revenue requirement for the fixed cost component of those services, inclusive of an allowance for the cost of capital. Any resulting shortfall in recovery, net of mitigation, would be

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considered a net stranded cost. The MPSC authorized Detroit Edison to establish a regulatory asset to defer recovery of its incurred stranded costs, subject to review in a subsequent annual net stranded cost proceeding.
2004 PSCR Reconciliation and 2004 Net Stranded Cost Case
In accordance with the MPSC’s directive in Detroit Edison’s November 2004 rate order, in March 2005, Detroit Edison filed a joint application and testimony in its 2004 PSCR Reconciliation Case and its 2004 Net Stranded Cost Recovery Case. In September 2006, the MPSC issued an order recognizing $19 million of 2004 net stranded costs that required Detroit Edison to write off $112 million of 2004 net stranded costs. The MPSC order resulted in a $39 million reduction in the 2004 PSCR over-collection by allowing Detroit Edison to retain the benefit of third party wholesale sales required to support the electric Customer Choice program and to offset the recognition of the $19 million of 2004 stranded costs. The MPSC order also resulted in reductions to accrued interest on the 2004 and 2005 PSCR amounts of $15 million. The MPSC directed Detroit Edison to include the remaining 2004 PSCR over-collection amount and related interest in the 2005 PSCR Reconciliation which is in an under-collec