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 OF 1934
   
þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009
   
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2007
Commission file number 1-2198
The Detroit Edison Company, a Michigan corporation, meets the conditions set forth in General Instruction I (1) (a) and (b) of Form 10-K and is, therefore, filing this form with the reduced disclosure format.
THE DETROIT EDISON COMPANY
(Exact name of registrant as specified in its charter)
   
Michigan38-0478650

(State or other jurisdiction of incorporation or
(I.R.S. Employer

organization)
 38-0478650
(I.R.S. Employer
Identification No.)
   
2000 2nd Avenue,One Energy Plaza, Detroit, Michigan48226-1279

(Address of principal executive offices)
 48226-1279
(Zip Code)
313-235-4000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
None
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.Yeso Noþ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.Yeso Noþ
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.Yesþ Noo
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yeso Noo
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.oþ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated fileroAccelerated fileroNon-accelerated filerþSmaller reporting companyo
 (Do not check if a smaller reporting company) 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yeso Noþ
All of the registrant’s 138,632,324 outstanding shares of common stock, par value $10 per share, are owned by DTE Energy Company.
DOCUMENTS INCORPORATED BY REFERENCE
None
 
 


 

The Detroit Edison Company
Annual Report on Form 10-K
Year Ended December 31, 20072009
Table of Contents
   
  Page
 1
   
 2
   
2
  
Part I
 4
   
 12
   
Item 3.10
Item 4. 1113
   
  
Part II
 1113
   
 13
   
Item 6.11
Item 7. 1214
   
 1516
   
 17
   
 6165
   
 65
   
 6165
   
  
Item 9B.61
Part III
Item 10. 6165
   
 65
   
Item 11.61
Item 12. 6165
   
 6165
   
 6165
   
  
Part IV
 6266
   
 74
EX-4.267
EX-4.268
EX-12.36
EX-23.22
EX-23.23
EX-31.53
EX-31.54
EX-32.53
EX-32.54


Definitions
   
SignaturesASCAccounting Standards Codification
   
ASU 72Accounting Standards Update
Computation of Ratio of Earnings to Fixed Charges
Consent of Deloitte & Touche LLP
Chief Executive Officer Section 302
Chief Financial Officer Section 302
Chief Executive Officer Section 906
Chief Financial Officer Section 906


Definitions
   
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.
   
Detroit Edison The Detroit Edison Company (a direct wholly owned subsidiary of DTE Energy Company) and subsidiary companies
   
DTE Energy DTE Energy Company, the parent of Detroit Edison and directly or indirectly the parent company of numerous utility and non-utility subsidiaries
   
EPA United States Environmental Protection Agency
   
FASBFinancial Accounting Standards Board
FERC Federal Energy Regulatory Commission
   
ITCFSP International Transmission Company (until February 28, 2003, a wholly owned subsidiary of DTE Energy Company)FASB Staff Position
FTRsFinancial transmission rights
   
MDEQ Michigan Department of Environmental Quality
   
MISO Midwest Independent System Operator, ais an Independent System Operator and the Regional
Transmission Organization serving the Midwest United States and Manitoba, Canada.
   
MPSC Michigan Public Service Commission
   
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.costs.
   
Securitization Detroit Edison financed specific stranded costs at lower interest rates through the sale of rate reduction bonds by a wholly ownedwholly-owned special purpose entity, theThe Detroit Edison Securitization Funding LLC.
   
SFAS Statement of Financial Accounting Standards
   
Stranded Costs
Units of Measurement
 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.
   
UnitsGWhGigawatthour of Measurementelectricity
   
kWh Kilowatthour of electricity
   
MW Megawatt of electricity
   
MWh Megawatthour of electricity

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Forward-Looking Statements
Certain information presented herein includes forward-looking statements“forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995.1995 with respect to the financial condition, results of operations and business of Detroit Edison. Forward-looking statements involve certainare subject to numerous assumptions, risks and uncertainties that may cause actual future results to differbe materially different from those presently contemplated, projected, estimated or budgeted. Many factors may impact forward-looking statements including, but not limited to, the following:
 the effectslength and severity of weatherongoing economic decline resulting in lower demand, customer conservation and other natural phenomena on operations and sales to customers, and purchases from suppliers;increased thefts of electricity;
 
changes in the economic and financial viability of our customers, suppliers, and trading counterparties, and the continued ability of such parties to perform their obligations to the Company;
 economic climate and population growth or decline in the geographic areas where we do business;
 
 environmental issues, laws, regulations, and the costhigh levels of remediation and compliance, including potential new federal and state requirements that could include carbon and more stringent mercury emission controls, a renewable portfolio standard and energy efficiency mandates;uncollectible accounts receivable;
 
nuclear regulations and operations associated with nuclear facilities;
impact of electric utility restructuring in Michigan, including legislative amendments and Customer Choice programs;
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;
 
instability in capital markets which could impact availability of short and long-term financing;
 the timing and extent of changes in interest rates;
 
 the level of borrowings;
 
potential for losses on investments, including nuclear decommissioning and benefit plan assets and the related increases in future expense and contributions;
the potential for increased costs or delays in completion of significant construction projects;
the effects of weather and other natural phenomena on operations and sales to customers, and purchases from suppliers;
environmental issues, laws, regulations, and the increasing costs of remediation and compliance, including actual and potential new federal and state requirements that include or could include carbon and more stringent mercury emission controls, a renewable portfolio standard, energy efficiency mandates, carbon tax or cap and trade structure and ash landfill regulations;
nuclear regulations and operations associated with nuclear facilities;
impact of electric utility restructuring in Michigan, including legislative amendments and Customer Choice programs;
employee relations and the impact of collective bargaining agreements;
unplanned outages;
 changes in the cost and availability of coal and other raw materials and purchased power;
 
 effectscost reduction efforts and the maximization of competition;plant and distribution system performance;
 
the effects of competition;

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 impact of regulation by the FERC, MPSC, NRC and other applicable governmental proceedings and regulations, including any associated impact on rate structures;
 
 changes in and application of federal, state and local tax laws and their interpretations, including the Internal Revenue Code, regulations, rulings, court proceedings and audits;
 
 the ability to recover costs through rate increases;amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals or new legislation;
 
the availability, cost, coverage and terms of insurance;
 the cost of protecting assets against, or damage due to, terrorism;terrorism or cyber attacks;
 
the availability, cost, coverage and terms of insurance and stability of insurance providers;
 changes in and application of accounting standards and financial reporting regulations;

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 changes in federal or state laws and their interpretation with respect to regulation, energy policy and other business issues; and
 
amounts of uncollectible accounts receivable;
 binding arbitration, litigation and related appeals; and
changes in the economic and financial viability of our suppliers, customers and trading counterparties, and the continued ability of such parties to perform their obligations to Detroit Edison; andappeals.
New factors emerge from time to time. We cannot predict what factors may arise or how such factors may cause our results to differ materially from those contained in any forward-looking statement. Any forward-looking statements refer only as of the date on which such statements are made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.

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Part I
Items 1., 1A. & and 2. Business Company Risk Factors and Properties
General
Detroit Edison is a Michigan corporation organized in 1903 and is a wholly ownedwholly-owned subsidiary of DTE Energy. Detroit Edison is a public utility subject to regulation by the MPSC and FERC. Detroit Edison is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.22.1 million customers in a 7,600 square mile area in southeastern Michigan.
References in this report to “we,” “us,” “our” or “Company” are to Detroit Edison.
Our generating 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 several fossil plants, a hydroelectric pumped storage plant and a nuclear plant, and is purchased from electricity generators, suppliers and wholesalers.
The electricity we produce and purchase is sold to fourthree major classes of customers: residential, commercial industrial, and wholesale,industrial, principally throughout southeastern Michigan.
            ��           
Revenue by Service              
(in Millions) 2007 2006 2005  2009 2008 2007 
Residential $1,739 $1,671 $1,517  $1,820 $1,726 $1,739 
Commercial 1,723 1,603 1,331  1,702 1,753 1,723 
Industrial 854 835 697  730 894 854 
Wholesale 125 109 73 
Other 259 350 464  299 289 384 
              
Subtotal 4,700 4,568 4,082  4,551 4,662 4,700 
Interconnection sales (1) 200 169 380  163 212 200 
              
Total Revenue $4,900 $4,737 $4,462  $4,714 $4,874 $4,900 
              
 
(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.
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 can negatively impact earnings.
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

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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 fournine long-term and eightnine short-term contracts for a total purchase of approximately 25.728 million tons of low-sulfur western coal to be delivered from 20082010 through 2010.2012. We also have 12nine long-term and two short-term contracts for the purchase of approximately 10.39 million tons of Appalachian coal to be delivered from 20082010 through 2010.2012. All of these contracts have fixed prices. We have approximately 90%87% of our 20082010 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 that 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, 20072009 are as follows:
                          
 Location by Summer Net   Location by Summer Net  
 Michigan Rated Capability (1) (2)   Michigan Rated Capability (1)  
Plant Name County (MW) (%) Year in Service County (MW) (%) Year in Service
Fossil-fueled Steam-Electric                  
Belle River (3)(2) St. Clair 1,026 9.3 1984 and 1985 St. Clair  1,034   9.3  1984 and 1985
Conners Creek Wayne 230 2.1 1951 Wayne  230   2.1  1951
Greenwood St. Clair 785 7.1 1979 St. Clair  785   7.1  1979
Harbor Beach Huron 103 0.9 1968 Huron  103   0.9  1968
Monroe (4) Monroe 3,115 28.3 1971, 1973 and 1974
Marysville St. Clair  84   0.8  1943 and 1947
Monroe (3) Monroe  3,090   27.9  1971, 1973 and 1974
River Rouge Wayne 523 4.8 1957 and 1958 Wayne  523   4.7  1957 and 1958
St. Clair St. Clair 1,368 12.4 1953, 1954, 1959, 1961 and 1969
St. Clair (4) St. Clair  1,365   12.3  1953, 1954, 1959, 1961 and 1969
Trenton Channel Wayne 730 6.6 1949 and 1968 Wayne  730   6.6  1949 and 1968
                    
   7,880 71.5        7,944   71.7   
Oil or Gas-fueled Peaking Units Various 1,101 10.0 1966-1971, 1981 and 1999 Various  1,101   10.0  1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric Fermi 2 (5) Monroe 1,122 10.2 1988 Monroe  1,102   10.0  1988
Hydroelectric Pumped Storage Ludington (6) Mason 917 8.3 1973
Hydroelectric Pumped Storage Ludington(6) Mason  917   8.3  1973
                    
   11,020 100.0        11,064   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), and one coal-fired unit, Marysville (84 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 67 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
 
(4)(3) The Monroe Power Plantpower plant provided 39%38% of Detroit Edison’s total 20072009 power plant generation.
(4)Excludes one oil-fueled unit (250 MW) in cold standby status.
 
(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 67 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
Detroit Edison owns and operates 678677 distribution substations with a capacity of approximately 33,376,00033,347,000 kilovolt-amperes (kVA) and approximately 427,100423,600 line transformers with a capacity of approximately 26,280,00021,883,000 kVA.

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Circuit miles of electric distribution lines owned and in service as of December 31, 2007 are as follows:2009:
                
Electric Distribution Circuit Miles
 Circuit Miles 
Operating Voltage-Kilovolts (kV) Overhead Underground Overhead Underground 
4.8 kV to 13.2 kV 28,202 13,985  28,243 13,884 
24 kV 99 690  177 681 
40 kV 2,324 335  2,317 363 
120 kV 72 13  54 13 
          
 30,697 15,023  30,791 14,941 
          
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.
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.
See Note 4, 8, 10 and 16 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
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 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.
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” in Item 1A1A. of this Report. We expect to minimize the impacts of declines in average customer usage through regulatory mechanisms which will partially decouple our revenue levels from sales volumes.
The electric Customer Choice program in Michigan allows all of our electric customers to purchase their electricity from alternative electric suppliers of generation services.services, subject to limits. Customers choosing to purchase power from

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alternative electric suppliers represented approximately 4%3% of retail sales in 2007, 6% in 20062009 and 12%2008, and 4% of such sales in 2005.2007. 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 electMPSC rate orders and

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recent energy legislation enacted by the State of Michigan are phasing out the pricing disparity over five years and have placed a 10% cap on the total potential Customer Choice related migration, mitigating some of the unfavorable effects of electric Customer Choice on our financial performance. We expect that in 2010 customers choosing to purchase their electricitypower from alternative electric suppliers by participating in the electric Customer Choice program have an unfavorable effect on our financial performance.will represent approximately 10% of retail sales. When market conditions are favorable, we sell power into the wholesale market, in order to lower costs to full-service customers.
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.
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. Actual costs to comply could vary substantially. We expect to continue recovering environmental costs through rates charged to our customers. The following table summarizes our estimated significant future environmental expenditures based upon current regulations:
        
(in Millions)  
Air $2,441  $2,200 
Water 55  55 
Other clean up sites 11 
MGP sites 4  5 
Other sites 21 
      
Estimated total future expenditures through 2018 $2,511 
Estimated total future expenditures through 2019 $2,281 
      
Estimated 2008 expenditures $288 
Estimated 2010 expenditures $82 
   
Estimated 2011 expenditures $253 
   
Air- Detroit Edison is subject to the EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. In MarchSince 2005, EPA and the State of Michigan have 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 costFurther, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants (HAPs). It is not possible to address environmental air issues is estimated through 2018.quantify the impact of those expected rulemakings at this time.
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 completed studies to be conducted over the next several years,and expected future studies, 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 recentJanuary 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation, resulting in a delay in complying with the regulation. In 2008, the U.S. Supreme Court agreed to review the remanded cost-benefit analysis provision of the rule and in April 2009 upheld EPA’s use of this provision in determining best available technology for reducing environmental impacts. Concurrently, the EPA continues to develop a revised rule, a draft of which is expected to be published by summer 2010. The EPA has also proposed an information collection request to begin a review of steam electric effluent guidelines. It is not possible at this time to quantify the impacts of these developing requirements.
Manufactured Gas Plant (MGP) and Other 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. Detroit Edison conducted remedial investigations at contaminated sites, includingowns, or previously owned, three former MGP sites. In addition to the MGP sites, we are also in the area surroundingprocess of cleaning up other sites where contamination is present as a result of historical and ongoing utility operations. These other sites include an engineered ash landfillstorage facility, electrical distribution substations and several underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediateCleanup activities associated with these sites is expected towill be incurredconducted over the next several years. In addition,

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Landfill Detroit Edison will be making capital improvementsowns and operates a permitted engineered ash storage facility at the Monroe Power Plant to dispose of fly ash from the coal fired power plant. Detroit Edison performed an engineering analysis in 2009 and identified the need for embankment side slope repairs and reconstruction.
The EPA has expressed its intentions to develop new federal regulations for coal ash landfill in 2008.
Global Climate Change —Proposals for voluntary initiativesunder the authority of the Resources Conservation and mandatory controls are being discussedRecovery Act (RCRA). A proposed regulation is expected in the United States to reduce greenhouse gases such as carbon dioxide,first quarter of 2010. Among the options EPA is currently considering, is a by-product of burning fossil fuels. There may be legislative action to address the issue of changes in climateruling that may result fromdesignate coal ash as a “Hazardous Waste” as defined by RCRA. However, agencies and legislatures have urged EPA to regulate coal ash as a non-hazardous waste. If EPA were to designate coal ash as a hazardous waste, the build upagency could apply some, or all, of greenhouse gases, including carbon dioxide, in the atmosphere. We cannot predictdisposal and reuse standards that have been applied to other existing hazardous wastes. Some of the impact any legislative or regulatory action mayactions currently being contemplated could have a material adverse impact on our operations and financial position.position and the rates we charge our customers.
Greater detailsGlobal Climate Change— Climate regulation and/or legislation is being proposed and discussed within the U.S. Congress and the EPA. On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act (ACESA). The ACESA includes a cap and trade program that would start in 2012 and provides for costs to emit greenhouse gases. Despite action by the Senate Environmental and Public Works Committee to pass a similar but more stringent bill in October 2009, full Senate action on a climate bill is not expected before the spring of 2010. Meanwhile, the EPA is beginning to implement regulatory actions under the Clean Air Act to address emission of greenhouse gases. Pending or future legislation or other regulatory actions could have a material impact on our operations and financial position and the rates we charge our customers. Impacts include expenditures for environmental issues are provided inequipment beyond what is currently planned, financing costs related to additional capital expenditures and the purchase of emission allowances from market sources. We would seek to recover these incremental costs through increased rates charged to our utility customers. Increased costs for energy produced from traditional sources could also increase the economic viability of energy produced from renewable and/or nuclear sources and energy efficiency initiatives and the development of market-based trading of carbon offsets providing business opportunities for our utility and non-utility segments. It is not possible to quantify these impacts on Detroit Edison or its customers at this time.
See Notes 410 and 1317 of the Notes to Consolidated Financial Statements in Item 8 of this Report:Report.
EMPLOYEES
We had 4,864 employees as of December 31, 2009, of which 2,782 were represented by unions. The majority of our union employees are under contracts that expire in June 2010 and August 2012.

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EMPLOYEES
We had 4,674 employees as of December 31, 2007, of which 2,847 were represented by unions. In December 2007, a new three-year agreement was ratified by our represented employees.
Item 1A. Company Risk Factors
There are various risks associated with the operations of Detroit Edison. To provide a framework to understand ourthe operating environment, we are providing a brief explanation of the more significant risks associated with our business. 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.
Regional and national economic conditions can have an unfavorable impact on us.Our business follows the economic cycles of the customers we serve. We provide services to the domestic automotive and steel industries which have undergone considerable financial distress, exacerbating the decline in regional economic conditions. Should national or regional economic conditions further decline, reduced volumes of electricity and collections of accounts receivable will result in decreased earnings and cash flow.
Adverse changes in our credit ratings may negatively affect us.Regional and national economic conditions, 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 below investment grade could restrict or discontinue our ability to access capital markets and could result in an increase in our borrowing costs, a reduced level of capital expenditures and could impact future earnings and cash flows. In addition, a reduction in credit rating may require us to post collateral related to various physical or financially settled contracts for the purchase of energy-related commodities, products and services, which could impact our liquidity.
Our ability to access capital markets is important.Our ability to access capital markets is important to operate our businesses. In the past, turmoil in credit markets has constrained, and may again in the future constrain, our ability as well as the ability of our subsidiaries to issue new debt, including commercial paper, and refinance existing debt at reasonable interest rates. In addition, the level of borrowing by other energy companies and the market as a whole could limit our access to capital markets. We have a five-year credit facility that expires in 2010. We intend to seek to renew the facility on or before the expiration date. However, we cannot predict the outcome of these efforts, which could result in a decrease in amounts available and/or an increase in our borrowing costs and negatively impact our financial performance.
Poor investment performance of pension and other postretirement benefit plan holdings and other factors impacting benefit plan costs could unfavorably impact our liquidity and results of operations.Detroit Edison participates in various plans that provide pension and other postretirement benefits for DTE Energy and its affiliates.Our costs of providing non-contributory defined benefit pension plans and other postretirement benefit plans are dependent upon a number of factors, such as the rates of return on plan assets, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation, and our required or voluntary contributions made to the plans. The performance of the debt and equity markets affects the value of assets that are held in trust to satisfy future obligations under our plans. We have significant benefit obligations and hold significant assets in trust to satisfy these obligations. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the pension and postretirement benefit plan assets will increase the funding requirements under our pension and postretirement benefit plans if the actual asset returns do not recover these declines in the foreseeable future. Additionally, our pension and postretirement benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit expense and funding requirements. Also, if future increases in pension and postretirement benefit costs as a result of reduced plan assets are not recoverable from Detroit Edison customers, the results of operations and financial position of our company could be negatively affected. Without sustained growth in the plan investments over time to increase the value of our plan assets, we could be required to fund our plans with significant amounts of cash. Such cash funding obligations could have a material impact on our cash flows, financial position, or results of operations.
We are exposed to credit risk of counterparties with whom we do business.Adverse economic conditions affecting, or financial difficulties of, counterparties with whom we do business could impair the ability of these counterparties to pay for our services or fulfill their contractual obligations, or cause them to delay such payments or obligations. We depend on these counterparties to remit payments on a timely basis. Any delay or default in payment could adversely affect our cash flows, financial position, or results of operations.

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We are subject to rate regulation. Electric and gasOur electric rates for our utilities are set by the MPSC and the FERC and cannot be increased without regulatory authorization. We may be negatively impacted by new regulations or interpretations by the MPSC, the FERC or other regulatory bodies. Our ability to recover costs may be impacted by the time lag between the incurrence of costs and the recovery of the costs in customers’ rates. Our regulators also may decide to disallow recovery of certain costs in customers’ rates if they determine that those costs do not meet the standards for recovery under our governing laws and regulations. The State of Michigan will elect a new governor and legislature in 2010 and we cannot predict the outcome of that election. We cannot predict whether election results or changes in political conditions will affect the regulations or interpretations affecting Detroit Edison. 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.
We may be required to refund amounts we collect under self-implemented rates.Michigan law allows our utilities to self-implement rate changes six months after a rate filing, subject to certain limitations. However, if the final rate case order provides for lower rates than we have self-implemented, we must refund the difference, with interest. We have self-implemented rates in the past and have been ordered to make refunds to customers. Our financial performance may be negatively affected if the MPSC sets lower rates in future rate cases than those we have self-implemented, thereby requiring us to issue refunds. We cannot predict what rates an MPSC order will adopt in future rate cases.
Michigan’s electric Customer Choice program could negatively impact our financial performanceperformance.. 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 someand recent energy legislation enacted by the State of Michigan are phasing out the pricing disparity. Recent higher wholesale electric pricesdisparity over five years and have also resulted in some former electricplaced a cap on the total potential Customer Choice customers migrating back to Detroit Edison for electric generation service. Evenrelated migration. However, even with the electric Customer Choice-related rate relief received in recent Detroit Edison’s 2004Edison rate orders and 2005 orders,the legislated 10 percent cap on participation in the electric Customer Choice program, 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 uncertainty 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. Ice storms, tornadoes, or high winds can damage the electric distribution system infrastructure and require us to perform emergency repairs and incur material unplanned expenses. The expenses of storm restoration efforts may not be fully recoverable through the regulatory process.
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.
Construction and capital improvements to our power facilities subject us to risk.We are managing ongoing and planning future significant construction and capital improvement projects at multiple power generation and distribution facilities. Many factors that could cause delay or increased prices for these complex projects are beyond our control, including the cost of materials and labor, subcontractor performance, timing and issuance of necessary permits, construction disputes and weather conditions. Failure to complete these projects on schedule and on budget for any reason could adversely affect our financial performance and operations at the affected facilities.
The supply andand/or price of fuel and otherenergy commodities and/or related service may impact our financial results.We are dependent on coal for much of our electrical generating capacity. Price fluctuations, and fuel supply disruptions and increases in transportation costs could have a negative impact on the amounts we charge our ability to profitably generate customers for

10


electricity. We have hedging strategies and regulatory recovery mechanisms 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.

8

The supply and/or price other industrial raw and finished inputs and/or related services may impact our financial results.We are dependent on supplies of certain commodities, such as copper and limestone, among others, and industrial materials and services in order to maintain day-to-day operations and maintenance of our facilities. Price fluctuations or supply interruptions for these commodities and other items could have a negative impact on the amounts we charge our customers for our products.


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.
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.
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 and could 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.
Poor investment performance of pension plan holdings and other factors impacting pension plan costs could unfavorably impact our liquidity and results of operations.Our costs of providing non-contributory defined benefit pension plans are dependent upon a number of factors, such as the rates of return on plan assets, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation, and our required or voluntary contributions made to the plans. The performance of the capital markets affects the value of assets that are held in trust to satisfy future obligations under our pension plans. If conditions within the overall credit market continue to deteriorate, the fair value of these plans’ assets may be negatively affected. Additionally, while we complied with the minimum funding requirements as of December 31, 2007, we have certain qualified pension plans with obligations that exceeded the value of plan assets. Without sustained growth in the pension investments over time to increase the value of our plan assets, we could be required to fund our plans with significant amounts of cash. Such cash funding obligations could have a material impact on our cash flows, financial position, or results of operations.
We are exposed to credit risk of counterparties with whom we do business.Adverse economic conditions affecting, or financial difficulties of, counterparties with whom we do business could impair the ability of these counterparties to pay for our services or fulfill their contractual obligations, or cause them to delay such payments or obligations. We depend on these counterparties to remit payments on a timely basis. Any delay or default in payment could adversely affect our cash flows, financial position, or results of operations.
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 could be required to install expensive pollution control measures or limit or cease activities based on these regulations. Additionally, we may become a responsible party for environmental clean upcleanup 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.
We may also incur liabilities as a result of potential future requirements to address climate change issues. Proposals for voluntary initiatives and mandatory controls are being discussed both in the United States and worldwide to reduce greenhouse gases such as carbon dioxide, a by-product of burning fossil fuels. If

9


increased regulation of greenhouse gas emissions are implemented, the operations of our fossil-fuel generation assets may be significantly impacted.
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.
Renewable portfolio standards and energy efficiency programs may affect our business.We are subject to Michigan and potential future federal legislation and regulation requiring us to secure sources of renewable energy. Under the current Michigan legislation we will be required in the future to provide a specified percentage of our power from Michigan renewable energy sources. We are developing a strategy for complying with the existing state legislation, but we do not know what requirements may be added by federal legislation. We are actively engaged in developing renewable energy projects and identifying third party projects in which we can invest. We cannot predict the financial impact or costs associated with these future projects.
We are also required by Michigan legislation to implement energy efficiency measures and provide energy efficiency customer awareness and education programs. These requirements necessitate expenditures and implementation of these programs creates the risk of reducing our revenues as customers decrease their energy usage. We do not know how these programs will impact our business and future operating results.
Threats of terrorism or cyber attacks could affect our business.We may be threatened by problems such as computer viruses or terrorism that may disrupt our operations and could harm our operating results. Our industry requires the continued operation of sophisticated information technology systems and network infrastructure. Despite our implementation of security measures, all of our technology systems are vulnerable to disability or failures due to hacking, viruses, acts of war or terrorism and other causes. If our information technology systems were to fail and we were unable to recover in a timely way, we might be unable to fulfill critical business functions, which could have a material adverse effect on our business, operating results, and financial condition.
In addition, our generation plants and electrical distribution facilities in particular may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products. We have

11


increased security as a result of past events and we may be required by our regulators or by the future terrorist threat environment to make investments in security that we cannot currently predict.
We may not be fully covered by insurance.While weWe have a comprehensive insurance program in place to provide coverage for various types of risks, including catastrophic damage as a result of acts of God, terrorism war or a combination of other significant unforeseen events that could impact our operations and economicoperations. Economic losses might not be covered in full by insurance.insurance or our insurers may be unable to meet contractual obligations.
TerrorismFailure to maintain the security of personally identifiable information could adversely affect us. In connection with our business. Damage to downstream infrastructure we collect and retain personally identifiable information of our customers and employees. Our customers and employees expect that we will adequately protect their personal information, and the United States regulatory environment surrounding information security and privacy is increasingly demanding. A significant theft, loss or our own assetsfraudulent use of customer, employee or Detroit Edison data by terrorism wouldcybercrime or otherwise could adversely impact our operations. We have increased security as areputation and could result of past eventsin significant costs, fines and further security increases are possible.litigation.
Benefits of the Performance Excellence Process to uscontinuous improvement initiatives could be less than we expect. We have projected.In 2005, we initiated a company-wide review of our operations called the Performance Excellence Process, with the overarching goalcontinuous improvement program that is expected to become more competitive by reducing costs, eliminating waste and optimizing business processes while improving customer service.result in significant cost savings. Actual results achieved through this processprogram could be less than our expectations.
A work interruption may adversely affect us.Unions represent a majorityapproximately 2,800 of our employees. A union choosing to strike would have an impact on our business. A contract with our largest union expires in June 2010. In addition, our contracts with unions representing two small groups of employees expired on December 31, 2009 and another union is currently negotiating its first contract. We cannot predict the outcome of any of these contract negotiations, some of which have not yet commenced. We are unable to predict the effect a work stoppage would have on our costs of operation and financial performance.
Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse effect on our operations.Our business is dependent on our ability to recruit, retain, and motivate employees. Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect our business and future operating results.
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.
We are awareIn July 2009, DTE Energy received a Notice of attempts by an environmental organization known asViolation/Finding of Violation (NOV/FOV) from the Waterkeeper Alliance to initiate a criminal action in Canada against the Company for alleged violationsEPA alleging, among other things, that five Detroit Edison power plants violated New Source Performance standards, Prevention of the Canadian Fisheries Act. FinesSignificant Deterioration requirements, and Title V operating permit requirements under the relevant Canadian statute could be significant. To date,Clean Air Act. We believe that the Company has not been served process in this matter and is not able to predict or assessplants identified by the EPA have complied with applicable regulations. Depending upon the outcome of our discussions with the EPA regarding the NOV/FOV, the EPA could bring legal action against Detroit Edison. We could also be required to install additional pollution control equipment at some or all of the power plants in question, engage in Supplemental Environmental Programs, and/or pay fines. We cannot predict the financial impact or outcome of this action at this time.matter, or the timing of its resolution.

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For additional discussion on legal matters, see the following Notes to Consolidated Financial Statements:
    
Note Title
 
 4
10 Regulatory Matters
 5Nuclear Operations
1316 Commitments and Contingencies

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Item 4. Submission of Matters to a Vote of Security Holders
Omitted per General Instruction I (2) (c) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
All of the 138,632,324 issued and outstanding shares of common stock of Detroit Edison, par value $10 per share, are owned by DTE Energy, and constitute 100% of the voting securities of Detroit Edison. Therefore, no market exists for our common stock.
We paid cash dividends on our common stock of $305 million in 2007, 2006,2009, 2008, and 2005.2007.
Item 6. Selected Financial Data
Omitted per General Instruction I (2) (a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

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Item 7. Management’s Narrative Analysis of Results of Operations
Item 7.Management’s Narrative Analysis of Results of Operations
The Management’s Narrative Analysis of Results of Operations discussion for Detroit Edison is presented in accordance with General Instruction I (2) (a) of Form 10-K for wholly ownedwholly-owned subsidiaries (reduced disclosure format).
Factors impacting income:Our net income decreased $4 million to $317 million in 2007 from $321 million in 2006. The 2007 decrease reflects higher operation and maintenance expenses, partially offset by higher gross margins and lower depreciation and amortization expenses. The 2006 increase primarily reflects higher gross margins, partially offset by increased depreciation and amortization expenses.
        
Increase (Decrease) in Income Statement Components Compared to Prior Year
(in Millions)
 2009 2008 
          
Increase (Decrease) in Income Statement Components Compared to Prior Year 2007 2006 
(in Millions) 
Operating revenues $163 $275  $(160) $(26)
Fuel and purchased power 120  (24)  (287) 92 
          
Gross margin 43 299  127  (118)
Operation and maintenance 85 29   (45)  (100)
Depreciation and amortization  (48) 172  101  (21)
Taxes other than income 25 11   (27)  (45)
Gains on sales of assets 14 20 
Asset (gains) losses and reserves, net  (1)  (9)
          
Operating income  (33) 67  99 57 
Other (income) and deductions  (17) 11  12 6 
Income tax provision  (13) 13  42 37 
          
Net income before accounting change  (3) 43 
Cumulative effect of accounting change  (1) 4 
     
Net Income $(4) $47  $45 $14 
          
Gross marginincreased $43$127 million and decreased $118 million during 20072009 and $299 million in 2006. The increase in 2007 was attributed to higher margins due to returning sales from electric Customer Choice, the favorable impact of a May 2007 MPSC order related to the 2005 PSCR reconciliation, and weather related impacts, partially offset by lower rates resulting primarily from the August 2006 settlement in the MPSC show cause proceeding and the unfavorable impact of a September 2006 MPSC order related to the 2004 PSCR reconciliation. 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. Revenues include a component for the cost of power sold that is recoverable through the PSCR mechanism.
2008, respectively. 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 2007  2006 
(in Millions)        
Weather-related margin impacts $31  $(81)
Removal of residential rate caps effective January 1, 2006     186 
Return of customers from electric Customer Choice  43   156 
Service territory economic performance  28   (16)
Impact of 2006 MPSC show cause order  (64)   
Impact of 2005 MPSC PSCR reconciliation order  38    
Impact of 2004 MPSC PSCR reconciliation order  (39)  26 
Other, net  6   28 
       
Increase in gross margin $43  $299 
       

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Power Generated and Purchased         
(in Thousands of MWh) 2007     2006     2005    
Power Plant Generation                        
Fossil  42,359   72%  39,686   70%  40,756   73%
Nuclear  8,314   14   7,477   13   8,754   16 
                   
   50,673   86   47,163   83   49,510   89 
Purchased Power  8,422   14   9,861   17   6,378   11 
                   
System Output  59,095   100%  57,024   100%  55,888   100%
Less Line Loss and Internal Use  (3,391)      (3,603)      (3,205)    
                      
Net System Output  55,704       53,421       52,683     
                      
Average Unit Cost ($/MWh)
                        
Generation (1) $15.83      $15.61      $15.47     
                      
Purchased Power (2) $62.40      $53.71      $89.37     
                      
Overall Average Unit Cost $22.47      $22.20      $23.90     
                      
         
Increase (Decrease) in Gross Margin Components Compared to Prior Year
(in Millions)
 2009 2008
December 2008 rate order $80  $
Securitization bond and tax surcharge rate increase  62    
July 2009 rate self-implementation  93    
Energy Optimization and Renewable Energy surcharge  54    
April 2008 expiration of show cause rate decrease  25   46 
Weather  (66)  (37)
Reduction in customer demand and other  (121)  (127)
       
Increase (decrease) in gross margin $127  $(118)
       
(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) 2007 2006 2005 2009 2008 2007 
       
Electric Sales
  
Residential 16,147 15,769 16,812  14,625 15,492 16,147 
Commercial 19,332 17,948 15,618  18,200 18,920 19,332 
Industrial 13,338 13,235 12,317  9,922 13,086 13,338 
Wholesale 2,902 2,826 2,329 
Other 398 402 390  3,229 3,218 3,300 
              
 52,117 50,180 47,466  45,976 50,716 52,117 
Interconnection sales (1) 3,587 3,241 5,217  5,156 3,583 3,587 
              
Total Electric Sales 55,704 53,421 52,683  51,132 54,299 55,704 
              
  
Electric Deliveries
  
Retail and Wholesale 52,117 50,180 47,466  45,976 50,716 52,117 
Electric Customer Choice 1,690 2,694 6,760 
Electric Customer Choice-Self Generators (2) 549 909 518 
Electric Customer Choice, including self generators (2) 1,477 1,457 2,239 
              
Total Electric Sales and Deliveries 54,356 53,783 54,744  47,453 52,173 54,356 
              
 
(1) Represents power that is not distributed by Detroit Edison.
Edison
 
(2) RepresentsIncludes deliveries for self generators who have purchased power from alternative energy suppliers to supplement their power requirements.requirements

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Power Generated and Purchased                     
(in Thousands of MWh) 2009     2008     2007    
Power Plant Generation                     
Fossil  40,595  74%  41,254  71%  42,359  72%
Nuclear  7,406  14   9,613  17   8,314  14 
                
   48,001  88   50,867  88   50,673  86 
Purchased Power  6,495  12   6,877  12   8,422  14 
                
System Output  54,496  100%  57,744  100%  59,095  100%
Less Line Loss and Internal Use  (3,364)     (3,445)     (3,391)   
                   
Net System Output  51,132      54,299      55,704    
                   
Average Unit Cost ($/MWh)
                     
Generation (1) $18.20     $17.93     $15.83    
                   
Purchased Power $37.74     $69.50     $62.40    
                   
Overall Average Unit Cost $20.53     $24.07     $22.47    
                   
(1)Represents fuel costs associated with power plants.
Operation and maintenanceexpense increased $85decreased $45 million in 20072009 and $29decreased $100 million in 2006.2008. The increasedecrease in 2007 is primarily due to EBS implementation costs of $30 million, higher storm expenses of $22 million, increased uncollectible expense of $22 million and higher corporate support expenses of $20 million. The 2006 increase2009 was primarily due to increased distribution system$71 million from continuous improvement initiatives and other cost reductions resulting in lower contract labor and outside services expense, information technology and other staff expenses, $14 million of lower employee benefit-related expenses, lower storm expenses of $12 million, $9 million of reduced uncollectible expenses and $6 million of reduced maintenance of $35 million and increased plant outages of $33 million that wasactivities, partially offset by $36higher pension and health care costs of $54 million and $14 million of energy optimization and renewable energy expenses. The decrease in 2008 was due primarily to lower storm expenses.information systems implementation costs of $60 million, lower employee benefit-related expenses of $45 million and $29 million from continuous improvement initiatives resulting in lower contract labor and outside services expense, information technology and other staff expenses, partially offset by higher uncollectible expenses of $22 million.
Depreciation and amortizationexpense decreased $48increased $101 million in 2007 and increased $172 million in 2006. The 2007 decrease was2009 due primarily to a 2006 net stranded cost write-off of $112 million related to the September 2006 MPSC order regarding stranded costshigher depreciable base and a $13 million decrease in our asset retirement obligation at our Fermi 1 nuclear facility, partially offset by $58 million of increased amortization of regulatory assets and $13decreased $21 million in 2008 due primarily to decreased amortization of higher depreciationregulatory assets.
Taxes other than incomewere lower by $27 million due primarily to a $30 million reduction in property tax expense due to increased levelsrefunds received in settlement of depreciable plant assets. Amortizationappeals of assessments for prior year deferred CTA costs amounted to $10years. Taxes decreased $45 million in 2007. The 2006 increase was2008 due to a $112 million net stranded cost write-off related to the September 2006Michigan Single Business Tax (SBT) expense in 2007, which was replaced with the Michigan Business Tax (MBT) in 2008. The MBT is accounted for in the Income Tax provision.
Outlook— Unfavorable national and regional economic trends have resulted in reduced demand for electricity in our service territory and continued high levels in our uncollectible accounts receivable. The magnitude of these trends will be driven by the impacts of the challenges in the domestic automotive industry and the timing and level of recovery in the national and regional economies. The January 2010 MPSC rate order, regarding stranded costsprovided for an uncollectible expense tracking mechanism and a $19 million increaserevenue decoupling mechanism will assist in our asset retirement obligation at our Fermi 1 nuclear facility. In 2006,mitigating these impacts.
To address the challenges of the national and regional economies, we also had increased amortization of regulatory assets of $19 million relatedcontinue to electric Customer Choice and $8 million related to our securitized assets.

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Asset (gains) and losses, netgain decreased $14 million in 2007 due to a $13 million reserve for a loan guaranty related to Detroit Edison’s former ownership of a steam heating business now owned by Thermal Ventures II, LP (Thermal). The 2006 decrease resulted primarily from our 2005 sale of land near our headquarters in Detroit, Michigan.
Other (income) and deductionsexpense decreased $17 million in 2007 and increased $11 million in 2006. The 2007 decrease is attributable to a $10 million contribution to the DTE Energy Foundation in 2006 that did not re-occur in 2007, $3 million of higher interest income and $17 million of increased miscellaneous utility related services, partially offset by $16 million of higher interest expense. The 2006 increase is primarily attributable to higher interest expense due to increased long-term debt.
Outlook- We will move forward in our efforts to continue to improve the operating performance.performance and cash flow of Detroit Edison. We continue to favorably resolve outstanding regulatory issues, many of which were addressed by Michigan legislation. We expect that our planned significant environmental and continue to pursue additional regulatory and/or legislative solutions for structural problems within the Michigan electric market structure, primarily electric Customer Choice and the need to adjust rates for each customer class to reflect the full cost of service. We are also seeking regulatory reform to insure more timely cost recovery and resolution of rate cases.renewable expenditures will result in earnings growth. Looking forward, we face additional issues, such as rising prices for coal, health care and higher levels of capital spending, will resultvolatility in us taking meaningful actionprices for coal and other commodities, investment returns and changes in discount rate assumptions in benefit plans and health care costs, and uncertainty of legislative or regulatory actions regarding climate change. We expect to addresscontinue an intense focus on our costs while continuing to provide quality customer service. We will utilize the DTE Energy Operating System and the Performance Excellence Process to seek opportunitiescontinuous improvement efforts 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. We intend to seek recovery of these investments in future rate cases.
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 over 20 years. Should our regulatory environment be conducive to such a significant capital expenditure, we may build, upgrade or co-invest in a base-load coal facility or a new nuclear plant. While we have not decided on construction of a new base-load nuclear plant, 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 and distribution system 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;
levels of customer participation in the electric Customer Choice program; and
potential new federal and state environmental, renewable energy and energy efficiency requirements.
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

1415


believe are recoverable under Michigan legislation and MPSC orders. We cannot predict the outcome of these matters. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
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 renewable resources and cleanest generating technology, with significant energy savings achieved by increased energy efficiency. The plan also recommends:
Item 7A. 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 needQuantitative 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.Qualitative Disclosures about Market Risk
In December 2007, a package of bills to reform Michigan’s electric market was introduced in the Michigan legislature. Key elements of the package would modify Michigan’s electric Customer Choice program, begin the process of “de-skewing” regulated electric rates, provide for the creation of economic development rates, establish a process for authorizing the construction of new baseload power plants, provide for regulatory reform to insure more timely cost recovery and resolution of rate cases, establish renewable energy standards and create an energy efficiency program.
We continue to review the energy plan and monitor legislative action on some of its components. Without knowing how or if the plan will be fully implemented, we are unable to predict the impact on the Company of the implementation of the plan.
CUMULATIVE EFFECT OF ACCOUNTING CHANGES
Effective January 1, 2007, we adopted FASB Interpretation No. (FIN 48),Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109. The cumulative effect of the adoption of FIN 48 represented a $0.7 million increase to the January 1, 2007 balance of retained earnings.
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 FIN No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS No. 143that required additional new accounting rules for asset retirement obligations. The cumulative effect of adopting these new accounting rules reduced 2005 earnings by $3 million.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
We have commodity price risk arising from market price fluctuations. We have risks in conjunction with the anticipated purchases of coal, natural gas, uranium, electricity, and electricitybase metals to meet our service obligations. Further,However, the Company does not bear significant exposure to earnings risk as such changes are included in the pricePSCR regulatory rate-recovery mechanism. The Company has tracking mechanisms to mitigate a portion of electricity can impact the level of exposurelosses related to uncollectible accounts receivable. The Company is exposed to short-term cash flow or liquidity risk as a result of the electric Customer Choice programtime differential between actual cash settlements and uncollectible expenses.
To limit our exposure to commodity price fluctuations, we have applied various approaches including forward energy, capacity, storage and futures contracts, as well as regulatory rate-recovery mechanisms. Regulatory rate-

15


recovery occurs in the form of the PSCR mechanism (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.rate recovery.
Credit Risk
Bankruptcies
We purchase and sell electricity 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 tomay have a material effect on our financial statements.
We provide services to the domestic automotive industry, including GM, Ford Motor Company (Ford) and Chrysler and many of their vendors and suppliers. Chrysler filed for bankruptcy protection on April 30, 2009. We have reserved approximately $7 million of pre-petition accounts receivable related to Chrysler as of December 31, 2009. GM filed for bankruptcy protection on June 1, 2009. We have not reserved or written off any pre-petition accounts or notes receivable related to GM as of December 31, 2009. Closing of GM or Chrysler plants or other facilities that operate within Detroit Edison’s service territory will also negatively impact the Company’s operating revenues in future periods. In 2009, GM and Chrysler each represented two percent of our annual electric sales volumes, respectively.
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.
Interest Rate Risk
Detroit Edison is subject to interest rate risk in connection with the issuance of debt securities. 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). We estimate that if interest rates were 10% higher or lower, the fair value of long-term debt at December 31, 20072009 would decrease $178$171 million and increase $194$186 million, respectively.

16


Item 8. Financial Statements and Supplementary Data
Item 8.Financial Statements and Supplementary Data
   
  Page
 18
 18
Consolidated Financial Statements
 
   
 2019
   
 21
   
 22
   
 24
   
 25
   
 26
  
Financial Statement Schedule
   
 7173

17


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 the Company’sDetroit Edison’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, 2007,2009, which is the end of the period covered by this report. Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that such controls and procedures are effective in ensuringproviding reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensureprovide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.
(b) Management’s report on internal control over financial reporting
The managementManagement of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internalreporting as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Internal control system wasover financial reporting is a process designed by, or under the supervision of, our CEO and CFO, to provide reasonable assurance to the Company’s management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of published financial statements.statements for external purposes in accordance with generally accepted accounting principles.
AllBecause of its inherent limitations, 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 toover financial statement preparation and presentation. Projectionsreporting may not prevent or detect misstatements. Also, projections of any evaluation of the effectiveness to future periods are subject to the risksrisk that controlcontrols may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Company’s managementManagement of the Company has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007.2009. In making this assessment, itmanagement used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control—Integrated Framework.Based on ourthis assessment, management believesconcluded that, as of December 31, 2007,2009, the Company’s internal control over financial reporting was effective based on those criteria.
This annual report does not include an audit report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to audit by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.
(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, 2007.
In April 2007, we began implementing the second phase of our Enterprise Business Systems (EBS) project. EBS is 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. Changes have been made to many aspects of our internal control over financial reporting to adapt to EBS. Management continues to support, sustain and monitor our ongoing continuous improvement efforts in connection with the transition to EBS to ensure that the transition to EBS does not have a material negative impact on our internal control over financial reporting.

18


There have been no other changes in the Company’s internal control over financial reporting during the quarter ended December 31, 20072009 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

1918


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of The Detroit Edison Company
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of The Detroit Edison Company and its subsidiaries at December 31, 2009, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for the year ended December 31, 2009 listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit. We conducted our audit of these statements 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Detroit, Michigan
February 23, 2010

19


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of The Detroit Edison Company
We have audited the consolidated statement of financial position of The Detroit Edison Company
and subsidiaries (the “Company”) as of December 31, 2007 and 20062008 and the related consolidated statements of operations, cash flows, and changes in shareholder’s equity and comprehensive income for each of the three years in the period ended December 31, 2008 and 2007. Our audits also included the 2008 and 2007 information in the financial statement schedules listed in the Index at Item 15.accompanying index. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 The Detroit Edison Company and subsidiaries at December 31, 2007 and 2006,2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 and 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such 2008 and 2007 financial statement schedules, when considered in relation to the basic consolidated financial statements of the Company taken as a whole, present fairly, in all material respects, the information set forth therein.
As discussed in Note 7 to the consolidated financial statements, in connection with the required adoption of a new accounting standard, the Company changed its method of accounting for uncertainty in income taxes on January 1, 2007. As discussed in Notes 2 and 14 to the consolidated financial statements, in connection with the required adoption of new accounting standards, in 2006 the Company changed its method of accounting for share based payments and defined benefit pension and other postretirement plans, respectively. As discussed in Note 1 to the consolidated financial statements, in connection with the required adoption of new accounting standards, in 2005 the Company changed its method of accounting for asset retirement obligations.
/S/ DELOITTEs/ Deloitte & TOUCHETouche LLP
Detroit, Michigan
March 7, 2008February 27, 2009

20


The Detroit Edison Company

Consolidated Statements of Operations
                        
 Year Ended December 31  Year Ended December 31 
(in Millions) 2007 2006 2005  2009 2008 2007 
Operating Revenues
 $4,900 $4,737 $4,462  $4,714 $4,874 $4,900 
              
  
Operating Expenses
  
Fuel and purchased power 1,686 1,566 1,590  1,491 1,778 1,686 
Operation and maintenance 1,422 1,337 1,308  1,277 1,322 1,422 
Depreciation and amortization 764 812 640  844 743 764 
Taxes other than income 277 252 241  205 232 277 
Asset (gains) and reserves, net 8  (6)  (26)
Asset (gains) losses and reserves, net  (2)  (1) 8 
              
 4,157 3,961 3,753  3,815 4,074 4,157 
              
  
Operating Income
 743 776 709  899 800 743 
              
  
Other (Income) and Deductions
  
Interest expense 294 278 267  325 293 294 
Interest income  (7)  (4)  (3)  (2)  (6)  (7)
Other income  (40)  (35)  (27)  (39)  (51)  (40)
Other expenses 30 55 46  11 47 30 
              
 277 294 283  295 283 277 
              
  
Income Before Income Taxes
 466 482 426  604 517 466 
  
Income Tax Provision
 149 162 149  228 186 149 
              
  
Income Before Accounting Change
 317 320 277 
 
Cumulative Effect of Accounting Change, net of tax
  1  (3)
       
 
Net Income
 $317 $321 $274  $376 $331 $317 
              
See Notes to Consolidated Financial Statements

21


The Detroit Edison Company

Consolidated Statements of Financial Position
                
 December 31  December 31 
(in Millions) 2007 2006  2009 2008 
Assets
  
Current Assets
  
Cash and cash equivalents $47 $27  $34 $30 
Restricted cash 135 132  79 84 
Accounts receivable (less allowance for doubtful accounts of $93 and $72, respectively)
Accounts receivable (less allowance for doubtful accounts of $118 and $121, respectively) 
Customer 727 601  696 709 
Collateral held by others 32  
Affiliates 3 19  3 5 
Other 58 51  108 34 
Accrued power supply cost recovery revenue 75 116 
Inventories  
Fuel 150 136  135 170 
Materials and supplies 165 130  173 169 
Notes receivable 
Affiliates 65 41 
Other 3 3 
Other 60 54  79 95 
          
 1,452 1,266  1,375 1,340 
          
  
Investments
  
Nuclear decommissioning trust funds 824 740  817 685 
Other 111 89  104 99 
          
 935 829  921 784 
          
  
Property
  
Property, plant and equipment 14,372 13,916  15,451 14,977 
Less accumulated depreciation  (5,640)  (5,580)
Less accumulated depreciation and amortization  (6,133)  (5,828)
          
 8,732 8,336  9,318 9,149 
          
  
Other Assets
  
Regulatory assets 2,511 2,862  3,333 3,456 
Securitized regulatory assets 1,124 1,235  870 1,001 
Intangible assets 9 9  9 19 
Notes receivable — affiliates 17  
Other 122 74  118 93 
          
 3,766 4,180  4,347 4,569 
          
  
Total Assets
 $14,885 $14,611  $15,961 $15,842 
          
See Notes to Consolidated Financial Statements

22


The Detroit Edison Company
Consolidated Statements of Financial Position
                
 December 31  December 31 
(in Millions, Except Shares) 2007 2006  2009 2008 
Liabilities and Shareholder’s Equity
  
Current Liabilities
  
Accounts payable  
Affiliates $138 $84  $74 $103 
Other 396 327  251 346 
Accrued interest 77 79  83 80 
Dividends payable 76 76 
Accrued vacations 52 77  48 58 
Short-term borrowings   75 
Affiliates 277  
Other 406 277 
Current portion long-term debt, including capital leases 174 142  660 153 
Other 243 288  213 263 
     
      1,329 1,078 
 1,839 1,350      
      
Long-Term Debt (net of current portion)
  
Mortgage bonds, notes and other 3,473 3,515  3,579 4,091 
Securitization bonds 1,065 1,184  793 932 
Capital lease obligations 42 50  25 33 
          
 4,580 4,749  4,397 5,056 
          
  
Other Liabilities
  
Deferred income taxes 1,825 1,928  1,871 1,894 
Regulatory liabilities 583 255  711 593 
Asset retirement obligations 1,160 1,069  1,285 1,205 
Unamortized investment tax credit 95 105  75 85 
Nuclear decommissioning 134 119  136 114 
Accrued pension liability 47 364 
Accrued postretirement liability 816 1,055 
Accrued pension liabilityaffiliates
 987 978 
Accrued postretirement liabilityaffiliates
 1,058 1,075 
Other 503 502  239 208 
          
 5,163 5,397  6,362 6,152 
          
  
Commitments and Contingencies (Notes 4, 5 and 13)
 
Commitments and Contingencies (Notes 10 and 16)
 
  
Shareholder’s Equity
  
Common stock, $10 par value, 400,000,000 shares authorized, and 138,632,324 shares issued and outstanding 2,771 2,596  3,196 2,946 
Retained earnings 528 516  693 622 
Accumulated other comprehensive income 4 3 
Accumulated other comprehensive income (loss)  (16)  (12)
          
 3,303 3,115  3,873 3,556 
          
  
Total Liabilities and Shareholder’s Equity
 $14,885 $14,611  $15,961 $15,842 
          
See Notes to Consolidated Financial Statements

23


The Detroit Edison Company

Consolidated Statements of Cash Flows
                        
 Year Ended December 31  Year Ended December 31 
(in Millions) 2007 2006 2005  2009 2008 2007 
Operating Activities
  
Net income $317 $321 $274  $376 $331 $317 
Adjustments to reconcile net income to net cash from operating activities:  
Depreciation and amortization 764 812 640  844 743 764 
Deferred income taxes  (111) 2 40  15 91  (111)
Asset (gains) and reserves, net 8  (6)  (26)
Cumulative effect of accounting change   (1) 3 
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)  (213)  (213) 98 
Asset (gains) losses and reserves, net  (2)  (2) 8 
Changes in assets and liabilities, exclusive of changes shown separately (Note 18)  (39) 118  (213)
              
Net cash from operating activities 765 915 1,029  1,194 1,281 765 
              
  
Investing Activities
  
Plant and equipment expenditures  (809)  (972)  (722)  (793)  (943)  (809)
Proceeds from sale of assets, net 3 28 30    3 
Restricted cash for debt redemptions  (3)  (48)  (9)
Restricted cash 5 50  (3)
Notes receivable from affiliate   85  (42  (41)  
Proceeds from sale of nuclear decommissioning trust fund assets 286 253 201  295 232 286 
Investment in nuclear decommissioning trust funds  (323)  (284)  (235)  (315)  (255)  (323)
Other investments  (33)  (29)  (71)  (46)  (54)  (33)
              
Net cash used for investing activities  (879)  (1,052)  (721)  (896)  (1,011)  (879)
              
  
Financing Activities
  
Issuance of long-term debt 50 314 857  129 862 50 
Redemption of long-term debt  (185)  (126)  (997)  (278)  (166)  (185)
Repurchase of long-term debt   (238)  
Short-term borrowings, net 129 114 163   (75)  (331) 129 
Short-term borrowings from affiliate 277      (277) 277 
Capital contribution by parent company 175 150   250 175 175 
Dividends on common stock  (305)  (305)  (305)  (305)  (305)  (305)
Other  (7)  (9)  (6)  (15)  (7)  (7)
              
Net cash from (used for) financing activities 134 138  (288)  (294)  (287) 134 
              
  
Net Increase in Cash and Cash Equivalents
 20 1 20 
Net Increase (Decrease) in Cash and Cash Equivalents
 4  (17) 20 
Cash and Cash Equivalents at Beginning of the Period
 27 26 6  30 47 27 
              
Cash and Cash Equivalents at End of the Period
 $47 $27 $26  $34 $30 $47 
              
See Notes to Consolidated Financial Statements

24


The Detroit Edison Company
Consolidated Statements of Changes in Shareholder’s Equity and Comprehensive income
                                                
 Accumulated   Accumulated   
 Additional Other   Additional Other   
 Common Stock Paid in Retained Comprehensive   Common Stock Paid in Retained Comprehensive   
 Shares Amount Capital Earnings Income Total
(Dollars in Millions, 
Shares in Thousands) 
Balance, December 31, 2004 138,632 $1,386 $1,060 $531 $2 $2,979 
Net income    274  274 
Dividends declared on common stock     (305)   (305)
Balance, December 31, 2005 138,632 1,386 1,060 500 2 2,948 
(Dollars in Millions, Shares in Thousands) Shares Amount Capital Earnings Income (Loss) Total 
Balance, December 31, 2006 138,632 $1,386 $1,210 $516 $3 $3,115 
Net income    321  321     317  317 
Dividends declared on common stock     (305)   (305)     (305)   (305)
Net change in unrealized gains on investments, net of tax     1 1      1 1 
Capital contribution by parent company   150   150    175   175 
Balance, December 31, 2006 138,632 1,386 1,210 516 $3 3,115 
Balance, December 31, 2007 138,632 1,386 1,385 528 4 3,303 
Net income    317  317     331  331 
Dividends declared on Common stock     (305)   (305)
Implementation of ASC 715 (SFAS No. 158) measurement date provision, net of tax     (9)   (9)
Dividends declared on common stock     (228)   (228)
Net change in unrealized gains on investments, net of tax     1 1       (2)  (2)
Benefit obligations, net of tax      (14)  (14)
Capital contribution by parent company   175   175    175   175 
Balance, December 31, 2007
 138,632 $1,386 $1,385 $528 $4 $3,303 
Balance, December 31, 2008 138,632 1,386 1,560 622  (12) 3,556 
Net income    376  376 
Dividends declared on common stock     (305)   (305)
Net change in unrealized losses on investments, net of tax      (2)  (2)
Benefit obligations, net of tax      (2)  (2)
Capital contribution by parent company   250   250 
Balance, December 31, 2009
 138,632 $1,386 $1,810 $693 $(16) $3,873 
The following table displays comprehensive income:
                        
(in Millions) 2007 2006 2005  2009 2008 2007 
Net income $317 $321 $274  $376 $331 $317 
              
Other comprehensive income:  
Net change in unrealized gain on investments, net of tax 1 1  
Net change in unrealized gain (losses) on investments, net of tax of $(1), $(1) and $1  (2)  (2) 1 
Benefit obligations, net of tax of $(1), $(7) and $
  (2)  (14)  
              
Comprehensive income $318 $322 $274  $372 $315 $318 
              
See Notes to Consolidated Financial Statements

25


The Detroit Edison Company
Notes to Consolidated Financial Statements
NOTE 1 — SIGNIFICANT ACCOUNTING POLICIESBASIS OF PRESENTATION
Corporate Structure
The Detroit Edison Company (Detroit Edison) is a Michigan public utility engaged in the generation, purchase, distribution and sale of electric energy to approximately 2.22.1 million customers in southeastern Michigan. Detroit Edison is regulated by the MPSC and FERC. 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’ “our” or “Company” are to Detroit Edison and its subsidiaries, collectively.
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 management to use estimates and assumptions that impact reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from the Company’s estimates.
Certain prior year balances were reclassified to match the current year’s financial statement presentation.
Principles of Consolidation
We consolidateThe Company consolidates all majority owned subsidiaries and investments in entities in which we haveit has controlling influence. Non-majority owned investments are accounted for using the equity method when the companyCompany 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 dothe Company does not influence the operating policies of an investee, the cost method is used. These consolidated financial statements also reflect the Company’s proportionate interests in certain jointly owned utility plant. We eliminateThe Company eliminates all inter-companyintercompany balances and transactions.
For entities that are consideredThe Company consolidates variable interest entities (VIEs) for which we applyare the provisionsprimary beneficiary. In general, the Company determines whether it is the primary beneficiary of FASB Interpretation No. (FIN) 46-R,Consolidationa VIE through a qualitative analysis of Variable Interest Entities, an Interpretationrisk which indentifies which variable interest holder absorbs the majority of ARB No. 51.
Basisthe financial risk or rewards and variability of Presentation
The accompanying consolidated financial statements are prepared using accounting principles generally acceptedthe VIE. In performing this analysis, the Company considers all relevant facts and circumstances, including: the design and activities of the VIE, the terms of the contracts the VIE has entered into, the identification of variable interest holders including equity owners, customers, suppliers and debt holders and which parties participated significantly in the United Statesdesign of America. These accounting principles require usthe entity. If the qualitative analysis is inconclusive, a specific quantitative analysis is performed. Refer to use estimatesNote 3 for discussion of changes in consolidation guidance applicable to VIEs and assumptions that impact reported amountsNote 16 for discussion of assets, liabilities, revenues, expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from our estimates.Company’s involvement with VIE’s.
NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES
Revenues
Revenues from the sale and delivery of electricity are recognized as services are provided. We record revenues for electric services 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. Annual PSCR proceedings before the MPSC permit Detroit Edison to recover prudent and reasonable supply costs. Any overcollectionover-collection or undercollectionunder-collection of costs, including interest, will be reflected in future rates. See Note 4.10.
Accounting for ISO Transactions
Detroit Edison participates in the energy market through MISO. MISO requires that we submit hourly day-ahead, real time and FTR bids and offers for energy at locations across the MISO region. Detroit Edison accounts for MISO

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transactions on a net hourly basis in each of the day-ahead, real-time and FTR markets and net transactions across all MISO energy market locations. We record net purchases in a single hour in fuel, purchased power and gas and net sales in a single hour in operating revenues in the Consolidated Statements of Income. We record net sale billing adjustments when we receive invoices. We record expense accruals for future net purchases adjustments base on historical experience, and reconcile accruals to actual expenses when we receive invoices.
Comprehensive Income
Comprehensive income is the change in commonCommon shareholder’s equity during a period from transactions and events from non-owner sources, including net income. As shown in the following table, amounts recorded to otherOther comprehensive income atfor the year ended December 31, 2007 include:2009 include unrealized gains and losses from derivatives accounted for as cash flow hedges, and unrealized gains and losses on available for sale securities.securities, and changes in benefit obligations.
                        
 Net Net Accumulated  Accumulated 
 Unrealized Unrealized Other  Other 
 Gains on Gains on Comprehensive  Benefit Comprehensive 
(in Millions) Derivatives Investments Income  Obligations Other Loss 
Beginning balance $1 $2 $3 
Beginning balances $(14) $2 $(12)
Current period change  1 1   (2)  (2)  (4)
              
Ending balance $1 $3 $4  $(16) $ $(16)
              
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 agreements. Restricted cash designated for interest and principal payments within one year is classified as a current asset.
Receivables
Accounts receivable are primarily composed of trade receivables and unbilled revenue. Our accounts receivable are stated at net realizable value.
The allowance for doubtful accounts is calculated using the aging approach that utilizes rates developed in reserve studies. We establish an allowance for uncollectible accounts based on historical losses and management’s assessment of existing economic conditions, customer trends, and other factors. Customer accounts are generally considered delinquent if the amount billed is not received by the due date, typically 21 days, however, factors such as assistance programs may delay aggressive action. We assess late payment fees on trade receivables based on contractual past-due terms established with customers. Customer accounts are written off when collection efforts have been exhausted, generally one year after service has been terminated.
Unbilled revenues of $269 million and $282 million are included in customer accounts receivable at December 31, 2009 and 2008, respectively.
Inventories
We value fuelThe Company generally values inventory and materials and supplies at average cost.
Property, Retirement and Maintenance, and Depreciation, Depletion and DepletionAmortization
Summary of property by classification as of December 31:
         
(in Millions) 2007  2006 
Property, Plant and Equipment
        
Generation $8,100  $7,667 
Distribution  6,272   6,249 
       
Total  14,372   13,916 
       
         
Less Accumulated Depreciation and Depletion
        
Generation  (3,539)  (3,410)
Distribution  (2,101)  (2,170)
       
Total  (5,640)  (5,580)
       
         
Net Property, Plant and Equipment
 $8,732  $8,336 
       
Property is stated at cost and includes construction-related labor, materials, overheads and an allowance for funds used during construction (AFUDC). AFUDC capitalized during 2007 and 2006 was approximately $24 million and $18 million, respectively. The cost of properties retired, less salvage value is charged to accumulated depreciation.

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Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2.
Approximately $4$13 million and $25 million of expenses related to the anticipated Fermi 2 refueling outage scheduled for 2009outages were accrued at December 31, 2007.2009 and December 31, 2008, respectively. Amounts are being accrued on a pro-rata basis over an 18-month18-

27


month period that began in November 2007.coincides with scheduled refueling outages at Fermi 2. This accrual of outage costs matches the regulatory recovery of these costs in rates set by the MPSC.
We baseThe Company bases depreciation provisions for utility property on straight-line rates approved by the MPSC. The composite depreciation rate for Detroit Edison was 3.3% in 2007 and 2006, and 3.4% in 2005.
The average estimated useful life for our generation and distribution property was 40 years and 37 years, respectively, at December 31, 2007.2009.
We creditThe Company credits depreciation, depletion and amortization expense when we establish regulatory assets for strandedplant-related costs related to the electric Customer Choice program and deferred environmental expenditures. We chargesuch as depreciation or plant-related financing costs. The Company charges depreciation, depletion and amortization expense when we amortize thethese regulatory assets. We creditThe Company credits interest expense to reflect the accretion income on certain regulatory assets.
Intangible assets relating to capitalizedCapitalized software areis classified as Property, plant and equipment and the related amortization is included in Accumulated depreciation on the Consolidated Statements of Financial Position. We capitalizeThe Company capitalizes the costs associated with computer software we developthe Company develops or obtainobtains for use in our business. We amortize intangibleThe Company amortizes Intangible assets on a straight-line basis over the expected period of benefit, ranging from 5 orto 15 years. Intangible assets amortization expense was $31 million in 2007, $28 million in 2006, and $33 million in 2005. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2007 were $376 million and $83 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2006 were $373 million and $52 million, respectively. Amortization expense of intangible assets is estimated to be $36 million annually for 2008 through 2012.
Asset Retirement Obligations
We have recorded asset retirement obligations in accordance with SFAS No. 143,Accounting for Asset Retirement Obligationsand 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. We have conditional retirement obligations for disposal of asbestos at certain of our power plants. To a lesser extent, we have conditional retirement obligations at certain service centers, and disposal costs for PCB contained within transformers and circuit breakers.
Timing differences arise in the expense 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 $13 million with offsetting accumulated depreciation of $10 million, and an asset retirement obligation liability of $32 million. We also recorded a cumulative effect amount as a reduction to a regulatory liability of $24 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 facilities vs. non-lead based paint facilities and no regulations currently exist requiring any type of special disposal of items containing lead-based paint.

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Ludington Hydroelectric Power Plant (a jointly owned 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 liability has been recorded for this asset.
A reconciliation of the asset retirement obligation for 2007 follows:
     
(in Millions)    
Asset retirement obligations at January 1, 2007 $1,069 
Accretion  71 
Liabilities settled  (7)
Revision in estimated cash flows  37 
    
Asset retirement obligations at December 31, 2007  1,170 
Less amount included in current liabilities  (10)
    
  $1,160 
    
Approximately $1.1 billion of the asset retirement obligations represents nuclear decommissioning liabilities that are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear plant.See Note 6.
Long-Lived Assets
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 costcosts to sell.
Intangible Assets
We haveThe Company has certain intangible assets relating to emission allowances. Emission allowances are charged to fuel expense as the allowances are consumed in the operation of the business.
Excise and Sales Taxes
We recordThe Company records 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 Statements 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, the unamortized discount, premium and expense related to debt redeemed with a refinancing are amortized over the life of the replacement issue.
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
WeThe Company generally classifyclassifies investments in debt and equity securities as either trading or available-for-sale and havehas 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 Fermi 2 nuclear decommissioning-relateddecommissioning investments are recorded as adjustments to regulatory

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assets or liabilities, due to a recovery mechanism from customers. OurThe Company’s 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 5.4.

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Consolidated Statement of Cash FlowsStock-Based Compensation
A detailed analysisThe Company received an allocation of the changes in assetscosts from DTE Energy associated with stock-based compensation. Our allocation for 2009, 2008 and liabilities that are reported in the consolidated statement of cash flows follows:
             
(in Millions) 2007  2006  2005 
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
            
Accounts receivable, net $(163) $(36) $(45)
Inventories  (47)  (28)  (21)
Recoverable pension and postretirement costs  594   (925)  61 
Accrued pensions  (330)  125   41 
Accounts payable  73   7   46 
Accrued power supply cost recovery revenue  41   (101)  (127)
Accrued payroll  (50)  47    
Income taxes payable  10   16   (10)
General taxes  4   13   (1)
Risk management and trading activities  (4)      
Postretirement obligation  (239)  803   110 
Other assets  (387)  (114)  (3)
Other liabilities  285   (20)  47 
          
  $(213) $(213) $98 
          
Supplementary cash2007 for stock-based compensation expense was approximately $24 million, $15 million and non-cash information for the years ended December 31 were as follows:
             
(in Millions) 2007 2006 2005
Cash Paid For            
Interest (excluding interest capitalized) $295  $278  $267 
Income taxes  280   141   118 
             
Non-cash Financing Activity            
Sale of assets        13 
$13 million, respectively.
Asset (gains) losses and losses,reserves, net
In 2007, we recorded a $13 million reserve for a loan guaranty related to Detroit Edison’s former ownership of a steam heating business now owned by Thermal Ventures II, LP (Thermal) resulting in a loss which was partially offset by approximately $5 million in gains on land and other sales. In 2006, we sold excess land near one of our power plants for a $6 million pre-tax gain. In 2005, we sold land near our headquarters in Detroit, Michigan for a pre-tax gain of $26 million.
Subsequent Events
The Company has evaluated subsequent events through February 23, 2010, the date that these financial statements were issued.
Other Accounting Policies
See the following notes for other accounting policies impacting our financial statements:
   
Note Title
23 New Accounting Pronouncements
4 Regulatory MattersFair Value
7Income Taxes
125 Financial and Other Derivative Instruments
1410Regulatory Matters
11Income Taxes
17 Retirement Benefits and Trusteed Assets

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NOTE 23 — NEW ACCOUNTING PRONOUNCEMENTS
FASB Accounting Standards Codification (Codification)
On July 1, 2009, the Codification became the single source of authoritative nongovernmental generally accepted accounting principles (GAAP) in the United States of America. The Codification is a reorganization of current GAAP into a topical format that eliminates the current GAAP hierarchy and establishes two levels of guidance — authoritative and non-authoritative. According to the FASB, all “non-grandfathered, non-SEC accounting literature” that is not included in the Codification would be considered non-authoritative. The FASB has indicated that the Codification does not change current GAAP. Instead, the proposed changes aim to (1) reduce the time and effort it takes for users to research accounting questions and (2) improve the usability of current accounting standards. The Codification is effective for interim and annual periods ending after September 15, 2009.
Fair Value Accounting
In September 2006, the FASB issued SFASASC 820 (SFAS No. 157,Fair Value MeasurementsMeasurements). SFAS No. 157The standard defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. It emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Fair value measurement should be determined based on the assumptions that market participants would use in pricing an asset or liability. Effective January 1, 2008, the Company adopted ASC 820 (SFAS No. 157). As permitted by ASC 820-10 (FSP No. 157-2), the Company elected to defer the effective date of the standard as it pertains to measurement and disclosures about the fair value of non-financial assets and liabilities made on a nonrecurring basis. The Company has adopted the recognition provisions for non-financial assets and liabilities as of January 1, 2009. See Note 4.
In April 2009, the FASB issued three FSPs intended to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities. The FSPs are effective for interim and annual periods ending after June 15, 2009.
ASC 825-10 (FSP No. 107-1 and APB No. 28-1),Interim Disclosures about Fair Value of Financial Instruments,expands the fair value disclosures required for all financial instruments within the scope of ASC 825-10 to interim periods.
ASC 820-10 (FSP No. 157-4),Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, which applies to all assets and liabilities, i.e., financial and nonfinancial, reemphasizes that the objective of fair value remains unchanged (i.e., an exit price notion). The FSP provides application guidance on measuring fair value when the volume and level of activity has significantly decreased and identifying transactions that are not orderly. The FSP also emphasizes that an entity cannot presume that an observable transaction price is not orderly even when there has been a significant decline in the volume and level of activity.
ASC 320-10 (FSP No. 115-2 and SFAS No. 157124-2),Recognition and Presentation of Other-Than-Temporary Impairments,is intended to bring greater consistency to the timing of impairment recognition, and provide greater clarity to investors about the credit and noncredit components of impaired debt securities that are not expected to be sold.
The Company adopted these FSPs in the second quarter of 2009. The adoption of these FSPs did not have a significant impact on Detroit Edison’s consolidated financial statements.
Disclosures about Derivative Instruments and Guarantees
In March 2008, the FASB issued ASC 815-10 (SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133). This standard requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. Entities

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are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under ASC 815 (SFAS No. 133) and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows.
The standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2007, and interim2008, with early application encouraged. Comparative disclosures for earlier periods within those fiscal years.at initial adoption are encouraged but not required. The Company adopted SFAS No. 157the standard effective January 1, 2008. The FASB deferred the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009. The adoption of SFAS No. 157 will not have a material impact to the January 1, 2008 balance of retained earnings.See Note 5.
Subsequent Events
In February 2007,May 2009, the FASB issued SFASASC 855 (SFAS No. 159,165,The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115Subsequent Events). This standard permits an entityprovides guidance on management’s assessment of subsequent events. The new standard clarifies that management must evaluate, as of each reporting period, events or transactions that occur after the balance sheet date “through the date that the financial statements are issued or are available to choose to measure manybe issued.” Management must perform its assessment for both interim and annual financial instruments and certain other items at fair value.reporting periods. The fair value option established by SFAS No.159 permits all entities to choose to measure eligible items at fair value at specified election dates. An entity will report in earnings unrealized gains and losses on items,standard does not significantly change the Company’s practice for which the fair value option has been elected, at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions,evaluating 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 No.159events. ASC 855 (SFAS No. 165) is effective prospectively for interim and annual periods ending after June 15, 2009 and requires disclosure of the date subsequent events are evaluated through. The Company adopted the standard during the quarter ended June 30, 2009. See Note 2.
Transfers of Financial Assets
In June 2009, the FASB issued ASU 2009-16 (SFAS No. 166,Accounting for Transfers of Financial Assets — an amendment of FASB No. 140).This standard amends ASC 860, (SFAS No. 140), eliminates the concept of a “qualifying special-purpose entity” (QSPE) and associated guidance and creates more stringent conditions for reporting a transfer of a portion of a financial asset as a sale. ASU 2009-16 (SFAS No. 166) is intended to enhance reporting in the wake of the subprime mortgage crisis and the deterioration in the global credit markets. The standard is effective for financial asset transfers occurring after the beginning of an entity’s first fiscal year that begins after November 15, 2007.2009. Early adoption is prohibited. ASU 2009-16 (SFAS No. 166) must be applied prospectively to transfers of financial assets occurring on or after its effective date. The adoption of SFASASU 2009-16 (SFAS No. 159166) will not have a material impact on Detroit Edison’s consolidated financial statements.
Variable Interest Entities (VIE)
In June 2009, the FASB issued ASU 2009-17 (SFAS No. 167,Amendments to FASB Interpretation 46(R)). This standard amends the consolidation guidance that applies to VIEs and affects the overall consolidation analysis under ASC 810 -10 (Interpretation 46(R)). The amendments to the consolidation guidance affect all entities and enterprises currently within the scope of ASC 810-10, as well as qualifying special purpose entities that are currently outside the scope of ASC 810-10. Accordingly, the Company will need to reconsider its previous ASC 810-10 conclusions, including (1) whether an entity is a VIE, (2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required. ASU 2009-17 (SFAS No. 167) is effective as of the beginning of the first fiscal year that begins after November 15, 2009. Early adoption is prohibited. The Company is currently assessing the impact of ASU 2009-17 (SFAS No. 167), however adoption of the standard is not expected to have a material impact to the Company’sconsolidated financial statements. At January 1, 2008,
Fair Value Measurements and Disclosures
In September and August 2009, respectively, the Company has not elected to useFASB issued ASU 2009-12,Fair Value Measurements and Disclosure,and ASU 2009-05,Measuring Liabilities at Fair Value.ASU 2009-12 provides guidance for the fair value option for financial assetsmeasurement of investments in certain entities that calculate the net asset value per share (or its equivalent) determined as of the reporting entity’s measurement date. Certain attributes of the investment (such as restrictions on redemption) and liabilities held at that date.
Offsetting Amounts Related to Certain Contracts
In April 2007, the FASB issued FSP FIN 39-1,Amendment of FASB Interpretation No. 39. This standardtransaction prices from principal-to-principal or brokered transactions will permit the Company to offsetnot be considered in measuring the fair value of derivative instruments with cash collateral received or paid for those derivative instruments executed with the same counterparty under a master netting arrangement. As a result, the Company will be permitted to record one net asset or liability that represents the total net exposure of all derivative positions under a master netting arrangement.investment. The decision to offset derivative positions under master netting arrangements remains an accounting policy choice. The guidanceamendments in this FSP isstandard are effective for fiscal years beginninginterim and annual periods ending after NovemberDecember 15, 2007, with early application permitted. The FSP is to be applied retrospectively by adjusting the financial statements for all periods presented. The company adopted the FSP as of January 1, 2008.
Business Combinations
In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.”The objective of this Statement is to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish that, this Statement establishes principles and requirements for how the acquirer:2009.

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Recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree;
Recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and
Determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.
ASU 2009-05 provides guidance on measuring the fair value of liabilities under ASC 820. This standard clarifies that in the absence of a quoted price in an active market for an identical liability at the measurement date, companies may apply approaches that use the quoted price of an investment in the identical liability or similar liabilities traded as assets or other valuation techniques consistent with the fair-value measurement principles in ASC 820. The standard permits fair value measurements of liabilities that are based on the price that a company would pay to transfer the liability to a new obligor. It also permits a company to measure the fair value of liabilities using an estimate of the price it would receive to enter into the liability at that date. The new standard is effective for interim and annual periods beginning after August 27, 2009 and applies to all fair-value measurements of liabilities required by GAAP. The adoption of ASU 2009-12 and ASU 2009-05 did not have a material impact on Detroit Edison’s consolidated financial statements.
SFASIn January 2010, the FASB issued ASU 2010-06,Improving Disclosures about Fair Value Measurements. ASU 2010-06 requires the gross presentation of activity within the Level 3 fair value measurement roll forward and details of transfers in and out of Level 1 and 2 fair value measurements. The new disclosures are required of all entities that are required to provide disclosures about recurring and nonrecurring fair value measurements. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for the gross presentation of the Level 3 fair value measurement roll forward which is effective for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years.
Revenue Arrangements
In September 2009, the FASB ratified Issue No. 141(R)08-1,Revenue Arrangements with Multiple Deliverables (not yet codified).Issue 08-1 provides principles and application guidance on whether multiple deliverables exist, how the arrangement should be separated, and the consideration allocated. This standard shall be applied prospectively to business combinations for which the acquisition date is onrevenue arrangements entered into or after the beginning of the first annual reporting periodmaterially modified in fiscal years beginning on or after DecemberJune 15, 2008. Earlier adoption is prohibited.2010, with earlier application permitted. Alternatively, an entity may elect to adopt this standard on a retrospective basis. The Company is currently assessing the effectsimpact of Issue No. 08-1 on Detroit Edison’s consolidated financial statements. Adoption of this statement, and hasstandard is not yet determined itsexpected to have a material impact on itsto the consolidated financial statements.
Noncontrolling Interests in Consolidated Financial Statements
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51.”The standard requires:
The ownership interests in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated statement of financial position within equity, but separate from the parent’s equity;
The amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of income;
Changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for as equity transactions;
When a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary be initially measured at fair value. The gain or loss on the deconsolidation of the subsidiary is measured using the fair value of any noncontrolling equity investment rather than the carrying amount of that retained investment; and
Entities provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.
SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. This Statement shall be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, except for the presentation and disclosure requirements. The presentation and disclosure requirements shall be applied retrospectively for all periods presented. The Company is currently assessing the effects of this statement, and has not yet determined its impact on its consolidated financial statements.
Stock-Based Compensation
Effective January 1, 2006, our parent company, DTE Energy, adopted SFAS No. 123(R),Share-Based Payment,using the modified prospective transition method. We receive an allocation of costs associated with stock compensation and the related impact of cumulative accounting adjustments. Our allocation for 2007 and 2006 for stock-based compensation expense was approximately $13 million and $14 million, respectively. The cumulative effect of the adoption of SFAS 123(R) was a decrease in expense of $1 million in the first quarter of 2006. The cumulative effect adjustment was due to the estimation and subsequent allocation of forfeitures for previously granted stock awards and performance shares. We have not restated any prior periods as a result of the adoption of SFAS 123(R).

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NOTE 34RESTRUCTURINGFAIR VALUE
Performance Excellence Process
In mid-2005,Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants’ use in pricing assets or liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The Company makes certain assumptions it believes that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company initiated a company-wide reviewand its counterparties is incorporated in the valuation of its operations calledassets and liabilities through the Performance Excellence Process.  Specifically,use of credit reserves, the Company began a seriesimpact of focused improvement initiatives within Detroit Edisonwhich is immaterial for the years ended December 31, 2009 and associated corporate support functions.2008. The Company expects this processbelieves it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.
A fair value hierarchy has been established, which prioritizes the inputs to continue into 2008.
valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement in its entirety. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The Company incurred CTA for employee severance and other costs. Other costs include project management and consultant support. Pursuant to MPSC authorization, beginning in the third quarter of 2006, Detroit Edison deferred approximately $102 million of CTA in 2006. Detroit Edison began amortizing deferred 2006 costs in 2007 as the recovery of these costs was provided for by the MPSC. Amortization expense amounted to $10 million in 2007. Detroit Edison deferred $54 million of CTA during 2007. See Note 4.
Amounts expensed are recorded in the Operation and maintenance lineclassifies fair value balances based on the Consolidated Statement of Operations. Deferred amounts are recorded in the Regulatory asset line on the Consolidated Statement of Financial Position.
Costs incurred in 2007 and 2006 arefair value hierarchy defined as follows:
                         
  Employee Severance Costs(1)  Other Costs  Total Cost 
(in Millions) 2007  2006  2007  2006  2007  2006 
Costs incurred: $15  $51  $50  $56  $65  $107 
Less amounts deferred or capitalized:  15   51   50   56   65   107 
                   
Amount expensed $  $  $  $  $  $ 
                   
(1)Includes corporate allocations
A liabilityLevel 1 — Consists of unadjusted quoted prices in active markets for future CTA associated with the Performance Excellence Process has not been recognized becauseidentical assets or liabilities that the Company has not met the recognition criteriaability to access as of SFAS No. 146,Accounting for Costs Associated with Exit or Disposal Activities.the reporting date.
NOTE 4Level 2REGULATORY MATTERSConsists of inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
Regulation
Detroit EdisonLevel 3 — Consists of unobservable inputs for assets or liabilities whose fair value is estimated based on internally developed models or methodologies using inputs that are generally less readily observable and supported by little, if any, market activity at the measurement date. Unobservable inputs are developed based on the best available information and subject to 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.cost-benefit constraints.
Regulatory Assets and Liabilities
Detroit Edison applies the provisions of SFAS No. 71,Accounting for the Effects of Certain Types of Regulation,to its operations. SFAS No. 71 requires the recording of regulatoryThe following table presents assets and liabilities for certain transactions that would have been treatedmeasured and recorded at fair value on a recurring basis as revenue and expense in non-regulated businesses.of December 31, 2009:
                 
              Net Balance at 
(in Millions) Level 1  Level 2  Level 3  December 31, 2009 
Assets:
                
Cash equivalents $15  $  $  $15 
Nuclear decommissioning trusts and other investments  589   325      914 
Derivative assets        2   2 
             
Total $604  $325  $2  $931 
             
Liabilities:
                
Derivative liabilities     (8)     (8)
             
Total $  $(8) $  $(8)
             
                 
Net Assets at December 31, 2009 $604  $317  $2  $923 
             

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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 business 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.
The following are balances and a brief descriptiontable presents the fair value reconciliation of the regulatoryLevel 3 assets and liabilities measured at fair value on a recurring basis for the years ended December 31:31, 2009 and 2008:
         
(in Millions) 2007  2006 
Assets
        
Securitized regulatory assets $1,124  $1,235 
       
Recoverable income taxes related to securitized regulatory assets  616   677 
Recoverable pension and postretirement costs  874   1,469 
Asset retirement obligation  266   236 
Other recoverable income taxes  94   100 
Recoverable costs under PA 141        
Excess capital expenditures  11   22 
Deferred Clean Air Act expenditures  28   67 
Midwest Independent System Operator charges  23   48 
Electric Customer Choice implementation costs  58   78 
Enhanced security costs  10   13 
Unamortized loss on reacquired debt  38   38 
Accrued PSCR revenue  75   116 
Costs to achieve Performance Excellence Process  146   102 
Enterprise Business Systems costs  26   9 
Deferred income taxes – Michigan Business Tax  318    
Other  3   3 
       
   2,586   2,978 
Less amount included in current assets  (75)  (116)
       
  $2,511  $2,862 
       
         
Liabilities
        
Asset removal costs $218  $222 
Accrued pension  43   33 
Fermi 2 refueling outage  4   16 
Deferred income taxes — Michigan Business Tax  318    
Other  5   2 
       
   588   273 
Less amount included in current liabilities  (5)  (18)
       
  $583  $255 
       
         
  Year Ended 
  December 31 
(in Millions) 2009  2008 
Asset balance as of beginning of period $4   4 
Changes in fair value recorded in regulatory assets/liabilities     2 
Purchases, issuances and settlements     (2)
Transfers in/out of Level 3  (2)   
       
Asset balance as of December 31 $2  $4 
       
The amount of total gains (losses) included in regulatory assets and liabilities attributed to the change in unrealized gains (losses) related to regulatory assets and liabilities held at December 31, 2009 and 2008 $2  $ 
       
ASSETSTransfers in/out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level and for which the inputs to the model become unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. Transfers in/out of Level 3 are reflected as if they had occurred at the beginning of the period. Transfers out of Level 3 in 2009 reflect a change in the significance of unobservable inputs and an increased reliance on broker quotes for certain transactions.
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.
Cash Equivalents
Cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value table are comprised of investments in money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized as Level 1 in the fair value hierarchy.
Nuclear Decommissioning Trusts and Other Investments
The nuclear decommissioning trust fund investments have been established to satisfy Detroit Edison’s nuclear decommissioning obligations. The nuclear decommissioning trusts and other fund investments hold debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices on actively traded markets. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued based on the underlying securities, using quoted prices in actively traded markets. Non-exchange-traded fixed income securities are valued based upon quotations available from brokers or pricing services. For non-exchange traded fixed income securities, the trustees receive prices from pricing services. A primary price source is identified by asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustees challenge an assigned price and determine that another price source is considered to be preferable. Detroit Edison has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Detroit Edison selectively corroborates the fair values of securities by comparison of market-based price sources.
Derivative Assets and Liabilities
Derivative assets and liabilities are comprised of physical and financial derivative contracts, including futures, forwards, options and swaps that are both exchange-traded and over-the-counter traded contracts. Various inputs are used to value derivatives depending on the type of contract and availability of market data. Exchange-traded derivative contracts are valued using quoted prices in active markets. The Company considers the following criteria in determining whether a market is considered active: frequency in which pricing information is updated, variability in pricing between sources or over time and the availability of public information. Other derivative contracts are valued based upon a variety of inputs including commodity market prices, broker quotes, interest rates, credit ratings, default rates, market-based seasonality and basis differential factors. The Company monitors the prices that

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are supplied by brokers and pricing services and may use a supplemental price source or change the primary price source of an index if prices become unavailable or another price source is determined to be more representative of fair value. The Company has obtained an understanding of how these prices are derived. Additionally, the Company selectively corroborates the fair value of its transactions by comparison of market-based price sources. Mathematical valuation models are used for derivatives for which external market data is not readily observable, such as contracts which extend beyond the actively traded reporting period.
Fair Value of Financial Instruments
The fair value of long-term debt is determined by using quoted market prices when available and a discounted cash flow analysis based upon estimated current borrowing rates when quoted market prices are not available. The table below shows the fair value relative to the carrying value for long-term debt securities. Certain other financial instruments, such as notes payable, customer deposits and notes receivable are not shown as carrying value approximates fair value. See Note 5 for further fair value information for financial and derivative instruments.
 Asset retirement obligation— Asset retirement obligations were recorded pursuant to adoption of SFAS No. 143 and FIN 47. These obligations are primarily for Fermi 2 decommissioning costs that are recovered in rates.
 
December 31, 2009 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.December 31, 2008
 
Fair Value Excess capital expenditures— PA 141 permits, after MPSC authorization, the recovery of and a return on capital expenditures that exceed a base level of depreciation expense.
Carrying ValueFair ValueCarrying Value 
Long-Term Debt Deferred Clean Air Act expenditures— PA 141 permits, after MPSC authorization, the recovery of and a return on Clean Air Act expenditures.
$5.2 billion 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.
$5.0 billion 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.
$5.0 billion 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.
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.
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 3.
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.
Deferred income taxes — Michigan Business Tax (MBT) –In July 2007, the MBT was enacted by the State of Michigan. State deferred tax liabilities were established and offsetting regulatory assets were recorded as the impacts of the deferred tax liabilities will be reflected in rates.$5.2 billion
LIABILITIESInvestments in Debt and Equity Securities
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.
Fermi 2 refueling outage– Accrued liability for refueling outage at Fermi 2 pursuant to MPSC authorization.
Deferred income taxes — Michigan Business Tax (MBT) –In July 2007, the MBT was enacted by the State of Michigan. State deferred tax assets were established and offsetting regulatory liabilities were recorded as the impacts of the deferred tax assets will be reflected in rates.
MPSC Show-Cause Order
In March 2006, the MPSC issued an order directing Detroit Edison to show cause by June 1, 2006 why its rates should not be reducedThe Company generally classifies investments in 2007. Detroit Edison filed its response explaining why its rates should not be reduceddebt and equity securities as either trading or available-for-sale and has recorded such investments at market value with unrealized gains or losses included in 2007. The MPSC issued an order approving a settlement agreementearnings or 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 April 13, 2008, one year from the

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filing of the general rate case on April 13, 2007, rates were reduced by an additional $26 million, for a total reduction of $79 million annually. 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 provided 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 increasesother comprehensive income or decreases in electric Customer Choice sales. If electric Customer Choice sales exceed 3,600 GWh, Detroit Edison will be able to recover 90 percent 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 percent of the increase in non-fuel revenue to the unrecovered regulatory asset balance. Approximately $28 million was credited to the unrecovered regulatory asset in 2007.
2007 Electric Rate Case Filing
Pursuant to the February 2006 MPSC order in Detroit Edison’s rate restructuring case and the August 2006 MPSC orderloss, respectively. Changes in the settlement of the show cause case, Detroit Edison filed a general rate case on April 13, 2007 based on a 2006 historical test year. The filing with the MPSC requested a $123 million, or 2.9 percent, average increase in Detroit Edison’s annual revenue requirement for 2008.
The requested $123 million increase in revenues is required in order to recover significant environmental compliance costs and inflationary increases, partially offset by net savings associated with the Performance Excellence Process. The filing was based on a return on equity of 11.25 percent on an expected 50 percent equity capital and 50 percent debt capital structure by year-end 2008.
In addition, Detroit Edison’s filing makes, among other requests, the following proposals:
   Make progress toward correcting the existing rate structure to more accurately reflect the actual cost of providing service to customers.
   Equalize distribution rates between Detroit Edison full service and electric Customer Choice customers.
   Re-establish with modification the CIM originally established in the Detroit Edison 2006 show cause filing. The CIM reconciles changes related to customers moving between Detroit Edison full service and electric Customer Choice.
   Terminate the Pension Equalization Mechanism.
   Establish an emission allowance pre-purchase plan to ensure that adequate emission allowances will be available for environmental compliance.
   Establish a methodology for recovery of the costs associated with preparation of an application for a new nuclear generation facility.
Also, in the filing, in conjunction with Michigan’s 21st Century Energy Plan, Detroit Edison has reinstated a long-term integrated resource planning (IRP) process with the purpose of developing the least overall cost plan to serve customers’ generation needs over the next 20 years. Based on the IRP, new base load capacity may be required for Detroit Edison. To protect tax credits available under Federal law,

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Detroit Edison determined it would be prudent to initiate the application process for a new nuclear unit. Detroit Edison has not made a final decision to build a new nuclear unit. Detroit Edison is preserving its option to build at some point in the future by beginning the complex nuclear licensing process in 2007. Also, beginning the licensing process at the present time positions Detroit Edison, potentially, to take advantage of tax incentives of up to $320 million derived from provisions in the 2005 Federal Energy Policy Act that will benefit customers. To qualify for these substantial tax credits, a combined operating license application for construction and operation of an advanced nuclear generating plant must be docketed by the Nuclear Regulatory Commission no later than December 31, 2008. Preparation and approval of a combined operating license can take up to 4 years and is estimated to cost at least $60 million. At December 31, 2007, costs related to preparing the combined licensing application totaling $10 million have been deferred and included in Other assets.
On August 31, 2007, Detroit Edison filed a supplement to its April 2007 rate case filing. A July 2007 decision by the Court of Appeals of the State of Michigan remanded back to the MPSC the November 2004 order in a prior Detroit Edison rate case that denied recovery of merger control premium costs. The supplemental filing addressed recovery of approximately $61 million related to the merger control premium. The filing also included the impact of the July 2007 enactment of the MBT, and other adjustments. The net impact of the supplemental changes results in an additional revenue requirement of approximately $76 million average increase in Detroit Edison’s annual revenue requirement for 2008.
On February 20, 2008, Detroit Edison filed an update to its April 2007 rate case filing. The update reflects the use of 2009 as the projected test year and includes a revised 2009 load forecast, and 2009 estimates on environmental and advanced metering infrastructure capital expenditures, and adjustments to the calculation of the MBT. In addition the update also includes the August 2007 supplemental filing adjustments for the merger control premium, the new MBT, and environmental operating and maintenance adjustments. The net impact of the updated filing results in an additional revenue requirement of approximately $85 million average increase in Detroit Edison’s annual revenue requirement for 2009. The total filing requests a $284 million increase in Detroit Edison’s annual revenue for 2009. An MPSC order related to this filing is expected in 2009.
Regulatory Accounting Treatment for Performance Excellence Process
In May 2006, Detroit Edison filed an application 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. Detroit Edison 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 anticipates the Performance Excellence Process to continue into 2008. In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison commencing in 2006, to defer the incremental CTA. Further, the order provides for Detroit Edison to amortize the CTA deferrals over a ten-year period beginning with the year subsequent to the year the CTA was deferred. At year-end 2006, Detroit Edison recorded deferred CTA costs of $102 million as a regulatory asset and began amortizing deferred 2006 costs in 2007, as the recovery of these costs was provided for by the MPSC in its order approving the settlement of the show cause proceeding. During 2007, Detroit Edison deferred CTA costs of $54 million. Amortization of prior year deferred CTA costs amounted to $10 million during 2007.
Accounting for Costs Related to Enterprise Business Systems (EBS)
In July 2004, Detroit Edison filed an accounting application with the MPSC requesting authority to capitalize and amortize costs related to EBS, consisting of computer equipment, software and development costs, as well as related training, maintenance and overhead costs. In April 2005, the MPSC

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approved a settlement agreement providing for the deferral of up to $60 million of certain EBS costs, which would otherwise be expensed, as a regulatory asset for future rate recovery starting January 1, 2006. At December 31, 2007, approximately $26 million of EBS costs have been deferred as a regulatory asset. In addition, EBS costs recorded as plant assets will be amortized over a 15-year period, pursuant to MPSC authorization.
Fermi 2 Enhanced Security Costs Settlement
The Customer Choice and Electricity Reliability Act, as amended in 2003, allows for the recovery of reasonable and prudent costs of new and enhanced security measures required by state or federal law, including providing for reasonable security from an act of terrorism. In December 2006, Detroit Edison filed an application with the MPSC for recovery of $11.4 millionfair value of Fermi 2 Enhanced Security Costs (ESC), discounted backnuclear decommissioning investments are recorded as adjustments to September 11, 2001 plus carrying costs from that date. In April 2007, the MPSC approved a settlement agreement that authorizes Detroit Edison to recover Fermi 2 ESC incurred during the period of September 11, 2001 through December 31, 2005. The settlement defined Detroit Edison’s ESC, discounted back to September 11, 2001, as $9.1 million, plus carrying charges. A total of $13 million, including carrying charges, has been deferred as a regulatory asset. Detroit Edison is authorized to incorporate into its rates an enhanced security factor over a period not to exceed five years. Amortization of this regulatory asset was approximately $3 million in 2007.
Reconciliation of Regulatory Asset Recovery Surcharge
In December 2006, Detroit Edison filed a reconciliation of costs underlying its existing Regulatory Asset Recovery Surcharge (“RARS”). This true-up filing was made to maximize the remaining time for recovery of significant cost increases prior to expiration of the RARS five-year recovery limit under PA 141. Detroit Edison requested a reconciliation of the regulatory asset surcharge to ensure proper recovery by the end of the five year period of: (1) Clean Air Act Expenditures, (2) Capital in Excess of Base Depreciation, (3) MISO Costs and (4) the regulatory liability for the 1997 Storm Charge. In July 2007, the MPSC approved a negotiated RARS deficiency settlement that resulted in a $10 million write down of RARS-related costs in 2007. As previously, discussed above, the CIM in the MPSC Show-Cause Order will reduce the regulatory asset. Approximately $28 million was credited to the unrecovered regulatory asset in 2007assets or liabilities, due to the CIM.
Power Supply Costs Recovery Proceedings
2005 Plan Year– In March 2006, Detroit Edison filed its 2005 PSCR reconciliation that sought approval fora recovery of an under-recovery of approximately $144 million at December 31, 2005mechanism from its commercial and industrial customers. The filing included a motion for entry of an order to implement immediately a reconciliation surcharge of 4.96 mills per kWh on the bills of its commercial and industrial customers. The under-collected PSCR expense allocated to residential customers could not be recovered due to the PA 141 rate cap for residential customers, which expired January 1, 2006. In addition to the 2005 PSCR plan year reconciliation, the filing included a reconciliation for the Pension Equalization Mechanism (PEM) for the periods from November 24, 2004 through December 31, 2004 and from January 1, 2005 through December 31, 2005. The PEM reconciliation seeks to allocate and refund approximately $12 million to customers based upon their contributions to pension expense during the subject periods. In September 2006, the MPSC ordered the Company to roll the entire 2004 PSCR over-collection amount to the Company’s 2005 PSCR Reconciliation. An order was issued on May 22, 2007 approving a 2005 PSCR undercollection amount of $94 million and the recovery of this amount through a surcharge for 12 months beginning in June 2007. In addition, the order approved Detroit Edison’s proposed PEM reconciliation that was refunded to customers on a bills-rendered basis during June 2007.

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2006 Plan Year —In September 2005, Detroit Edison filed its 2006 PSCR plan case seeking approval of a levelized PSCR factor of 4.99 mills per kWh above the amount included in base rates for residential customers and 8.29 mills per kWh above the amount included in base rates for commercial and industrial customers. Included in the factor for all customers are fuel and power supply costs, including transmission expenses, Midwest Independent Transmission System Operator (MISO) market participation costs, and NOx emission allowance costs. The Company’s PSCR Plan included a matrix which provided for different maximum PSCR factors contingent on varying electric Customer Choice sales levels. The plan also included $97 million for recovery of its projected 2005 PSCR under-collection associated with commercial and industrial customers. Additionally, the PSCR plan requested MPSC approval of expense associated with sulfur dioxide emission allowances, mercury emission allowances, and a fuel additive. In conjunction with DTE Energy’s sale of its transmission assets to ITC Transmission in February 2003, the FERC froze ITC Transmission’s rates through December 2004. In approving the sale, FERC authorized ITC Transmission’s recovery of the difference between the revenue it would have collected and the actual revenue collected during the rate freeze period. This amount is estimated to be $66 million which is to be included in ITC Transmission’s rates over a five-year period beginning June 1, 2006. This increased Detroit Edison’s transmission expense in 2006 by approximately $7 million. The MPSC authorized Detroit Edison in 2004 to recover transmission expenses through the PSCR mechanism.
In December 2005, the MPSC issued a temporary order authorizing the Company to begin implementation of maximum quarterly PSCR factors on January 1, 2006. The quarterly factors reflect a downward adjustment in the Company’s total power supply costs of approximately 2 percent to reflect the potential variability in cost projections. The quarterly factors allowed the Company to more closely track the costs of providing electric service to our customers and, because the non-summer factors are well below those ordered for the summer months, effectively delay the higher power supply costs to the summer months at which time our customers will not be experiencing large expenditures for home heating. The MPSC did not adopt the Company’s request to recover its projected 2005 PSCR under-collection associated with commercial and industrial customers nor did it adopt the Company’s request to implement contingency factors based upon the Company’s increased costs associated with providing electric service to returning electric Customer Choice customers. The MPSC deferred both of those Company proposals to the final order on the Company’s entire 2006 PSCR plan. In September 2006, the MPSC issued an order in this case that approved the inclusion of sulfur dioxide emission allowance expense in the PSCR, determined that fuel additive expense should not be included in the PSCR based upon its impact on maintenance expense, found the Company’s determination of third party sales revenues to be correct, and allowed the Company to increase its PSCR factor for the balance of the year in an effort to reverse the effects of the previously ordered temporary reduction. The MPSC declined to rule on the Company’s requests to include mercury emission allowance expense in the PSCR or its request to include prior PSCR over/(under) recoveries in future year PSCR plans. The Company filed its 2006 PSCR reconciliation case in March 2007. The $51 million PSCR under-collection amount reflected in that filing is being collected in the 2007 PSCR plan. Included in the 2006 PSCR reconciliation filing was the Company’s 2006 PEM reconciliation that reflects a $21 million ovecollection which is subject to refund to customers. An MPSC order in this case is expected in 2008.
2007 Plan Year —In September 2006, Detroit Edison filed its 2007 PSCR plan case seeking approval of a levelized PSCR factor of 6.98 mills per kWh above the amount included in base rates for all PSCR customers. The Company’s PSCR plan filing included $130 millioninvestments are reviewed for impairment each reporting period. If the recovery of its projected 2006 PSCR under-collection, bringingassessment indicates that the total requested PSCR factor to 9.73 mills/kWh. The Company’s application includedimpairment is other than temporary, a request for an early hearing and temporary order granting such ratemaking authority. The Company’s 2007 PSCR plan includes fuel and power supply costs, including NOx and SO2 emission allowance costs, transmission costs and MISO costs. The Company filed supplemental testimony and briefs in December 2006 supporting its updated request to include approximately $81 million for the recovery of its projected 2006 PSCR under-collection. The MPSC issued a temporary order in December 2006 approving the Company’s request. In addition, Detroit Edison was granted the

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authority to include all PSCR over/(under) collections in future PSCR plans, thereby reducing the time between refund or recovery of PSCR reconciliation amounts. The Company began to collect its 2007 power supply costs, including the 2006 rollover amount, through a PSCR factor of 8.69 mills/kWh on January 1, 2007. The Company reduced the PSCR factor to 6.69 mills/kWh on July 1, 2007 based on the updated 2007 PSCR plan year projections. In August 2007, the MPSC approved Detroit Edison’s 2007 PSCR case and authorized the Company to charge a maximum power supply cost recovery factor of 8.69 mills/kWh in 2007.
2008 Plan Year —In September 2007, Detroit Edison filed its 2008 PSCR plan case seeking approval of a levelized PSCR factor of 9.23 mills/kWh above the amount included in base rates for all PSCR customers. The Companyloss is supporting a total 2008 power supply expense forecast of $1.3 billion that includes $1 million for the recovery of its projected 2007 PSCR under-collection. The Company’s PSCR Plan will allow the Company to recover its reasonably and prudently incurred power supply expense including; fuel costs, purchased and net interchange power costs, NOx and SO2 emission allowance costs, transmission costs and MISO costs. Also includedrecognized resulting in the filing is a request for approval of the Company’s emission compliance strategy which includes pre-purchases of emission allowances as well as a request for pre-approval of a contract for capacity and energy associated with a renewable (wind energy) project. On January 31, 2008, Detroit Edison filed a revised PSCR plan case seeking approval of a levelized PSCR factor of 11.22 mills/kWh above the amount included in base rates for all PSCR customers. The revised filing supports a 2008 power supply expense forecast of $1.4 billion and includes $43 million for the recovery of a projected 2007 PSCR under-collection. On March 11, 2008, the commission ordered that Detroit Edison shall not self-implement the 11.22 mills/kWh PSCR factor proposed in its January 31, 2008 filing.
Other
On July 3, 2007, the Court of Appeals of the State of Michigan published its decision with respect to an appeal by Detroit Edison and others of certain provisions of a November 23, 2004 MPSC order, including reversing the MPSC’s denial of recovery of merger control premium costs. In its published decision, the Court of Appeals held that Detroit Edison is entitled to recover its allocated share of the merger control premium and remanded this matter to the MPSC for further proceedings to establish the precise amount and timing of this recovery. Detroit Edison filed a supplementinvestment being written down to its April 2007 rate case to address the recovery of the merger control premium costs. Other parties have filed requests for leave to appeal to the Michigan Supreme Court from the Court of Appeals decision. Detroit Edison is unable to predict the financial or other outcome of any legal or regulatory proceeding at this time.
The Company is unable to predict the outcome of the regulatory matters discussed herein. Resolution of these matters is dependent upon future MPSC orders and appeals, which may materially impact the financial position, results of operations and cash flows of the Company.estimated fair value.
NOTE 5 — NUCLEAR OPERATIONS
General
Fermi 2, the Company’s nuclear generating plant, began commercial operation in 1988. Fermi 2 has a design electrical rating (net) of 1,150 MW. This plant represents approximately 10% of Detroit Edison’s summer net rated capability. The net book balance of the Fermi 2 plant was written off at December 31, 1998, and an equivalent regulatory asset was established. In 2001, the Fermi 2 regulatory asset was securitized. Detroit Edison also owns Fermi 1, a nuclear plant that was shut down in 1972 and is currently being decommissioned. The NRC has jurisdiction over the licensing and operation of Fermi 2 and the decommissioning of Fermi 1.

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Property Insurance
Detroit Edison maintains several different types of property insurance policies specifically for the Fermi 2 plant. These policies cover such items as replacement power and property damage. The Nuclear Electric Insurance Limited (NEIL) is the primary supplier of the insurance polices.
Detroit Edison maintains a policy for extra expenses, including replacement power costs necessitated by Fermi 2’s unavailability due to an insured event. This policy has a 12-week waiting period and provides an aggregate $490 million of coverage over a three-year period.
Detroit Edison has $500 million in primary coverage and $2.25 billion of excess coverage for stabilization, decontamination, debris removal, repair and/or replacement of property and decommissioning. The combined coverage limit for total property damage is $2.75 billion.
The Terrorism Risk Insurance Extension Act of 2005 (TRIA) was scheduled to expire on December 15, 2007. Effective December 26, 2007, the Terrorism Risk Insurance Program Reauthorization Act of 2007 extended the TRIA though December 31, 2014. A major change in the extension is the inclusion of “domestic” acts of terrorism in the definition of covered or “certified” acts.
For multiple terrorism losses caused by acts of terrorism not covered under the TRIA occurring within one year after the first loss from terrorism, the NEIL policies would make available to all insured entities up to $3.2 billion, plus any amounts recovered from reinsurance, government indemnity, or other sources to cover losses.
Under the NEIL policies, Detroit Edison could be liable for maximum assessments of up to approximately $31 million per event if the loss associated with any one event at any nuclear plant in the United States should exceed the accumulated funds available to NEIL.
Public Liability Insurance
As required by federal law, Detroit Edison maintains $300 million of public liability insurance for a nuclear incident. For liabilities arising from a terrorist act outside the scope of TRIA, the policy is subject to one industry aggregate limit of $300 million. Further, under the Price-Anderson Amendments Act of 2005, deferred premium charges up to $101 million could be levied against each licensed nuclear facility, but not more than $15 million per year per facility. Thus, deferred premium charges could be levied against all owners of licensed nuclear facilities in the event of a nuclear incident at any of these facilities.
Decommissioning Trust Funds
Detroit Edison has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. This obligation is reflected as an asset retirement obligation on the Consolidated Statements of Financial Position. Based on the actual or anticipated extended life of the nuclear plant, decommissioning expendituresSee Note 8 for Fermi 2 are expected to be incurred primarily during the period of 2025 through 2050. It is estimated that the cost of decommissioning Fermi 2, when its license expires in 2025, will be $1.3 billion in 2007 dollars and $3.4 billion in 2025 dollars, using a 6% inflation rate. In 2001, Detroit Edison began the decommissioning of Fermi 1, with the goal of removing the radioactive material and terminating the Fermi 1 license. The decommissioning of Fermi 1 is expected to be complete by 2010.additional information.

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The NRC has jurisdiction over the decommissioning of nuclear power plants and requires decommissioning funding based upon a formula. The MPSC and FERC regulate the recovery of costs of decommissioning nuclear power plants and both require the use of external trust funds to finance the decommissioning of Fermi 2. Rates approved by the MPSC provide for the recovery of decommissioning costs of Fermi 2 and the disposal of low-level radioactive waste. Detroit Edison is continuing to fund FERC jurisdictional amounts for decommissioning even though explicit provisions are not included in FERC rates. The Company believes the MPSC and FERC collections will be adequate to fund the estimated cost of decommissioning using the NRC formula. The decommissioning assets, anticipated earnings thereon and future revenues from decommissioning collections will be used to decommission the nuclear facilities.Fermi 2. The Company expects the regulatory liabilities to be reduced to zero at the conclusion of the decommissioning activities. If amounts remain in the trust funds for these unitsFermi 2 following the completion of the decommissioning activities, those amounts will be disbursed based on rulings by the MPSC and FERC.
A portion of the funds recovered through the Fermi 2 decommissioning surcharge and deposited in external trust accounts is designated for the removal of non-radioactive assets and the clean-up of the Fermi site. This removal and clean-up is not considered a legal liability. Therefore, it is not included in the asset retirement obligation, but is reflected as the nuclear decommissioning regulatory liability.
The decommissioning of Fermi 1 is funded by Detroit Edison. Contributions to the Fermi 1 trust are discretionary.
The following table summarizes the fair value of the nuclear decommissioning trust fund assets.assets:
                
 As of December 31  December 31 December 31 
(in Millions) 2007 2006  2009 2008 
Fermi 2 $778 $694  $790 $649 
Fermi 1 13 15  3 3 
Low level radioactive waste 33 31  24 33 
          
Total $824 $740  $817 $685 
          

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At December 31, 2007,2009, investments in the external nuclear decommissioning trust funds consisted of approximately 54%51% in publicly traded equity securities, 45%48% in fixed debt instruments and 1% in cash equivalents. At December 31, 2008, investments in the nuclear decommissioning trust funds consisted of approximately 42% in publicly traded equity securities, 57% in fixed debt instruments and 1% in cash equivalents. The debt securities at both December 31, 2009 and December 31, 2008 had an average maturity of approximately 5.3 years.
At December 31, 2006, investments in the external nuclear decommissioning trust funds consisted of approximately 54% in publicly traded equity securities, 43% in fixed debt instruments and 3% in cash equivalents. The debt securities had an average maturity of approximately 5.15 years.
The costs of securities sold are determined on the basis of specific identification. The following table sets forth the gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds:
            
             Year Ended December 31
 Year Ended December 31 2009 2008 2007
(in Millions) 2007 2006 2005(in Millions) 
Realized gains $25 $21 $11  $37 $34 $25 
Realized losses  (17)  (9)  (8) $(55) $(49) $(17)
Proceeds from sales of securities $286 $253 $201  $295 $232 $286 

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Realized gains and losses and proceeds from salesthe sale of securities for the Fermi 2 and the Low Level Radioactive Wastelow level radioactive waste funds are recorded to the asset retirement obligation regulatory asset and nuclear decommissioning regulatory liability, respectively.liability. The following table sets forth the fair value and unrealized gains for the nuclear decommissioning trust funds:
         
      Total 
  Fair  Unrealized 
(in Millions) Value  Gains 
As of December 31, 2007        
Equity Securities $443  $170 
Debt Securities  373   9 
Cash and Cash Equivalents  8    
       
  $824  $179 
       
As of December 31, 2006        
Equity Securities $399  $140 
Debt Securities  316   4 
Cash and Cash Equivalents  25    
       
  $740  $144 
       
         
(in Millions)      
As of December 31, 2009    
Equity securities $420  $135 
Debt securities  388   17 
Cash and cash equivalents  9    
       
  $817  $152 
       
 
As of December 31, 2008    
Equity securities $288  $65 
Debt securities  388   17 
Cash and cash equivalents  9    
       
  $685  $82 
       
Securities held in the nuclear decommissioning trust funds are classified as available-for-sale. As Detroit Edison does not have the ability to hold impaired investments for a period of time sufficient to allow for the anticipated recovery of market value, all unrealized losses are considered to be “otherother than temporary”temporary impairments.
Impairment charges for unrealized losses incurred by the Fermi 2 trust are recognized as a regulatory asset. Detroit Edison recognized $22$48 million and $10$92 million of unrealized losses as regulatory assets for the years endedat December 31, 20072009 and 2006,2008, respectively. Since the decommissioning of Fermi 1 is funded by Detroit Edison rather than through a regulatory recovery mechanism, there is no corresponding regulatory asset treatment. Therefore, impairment charges for unrealized losses incurred by the Fermi 1 trust are recognized in earnings immediately. For the years ended December 31, 2007There were no impairment charges in 2009 and 2006,2008 for Fermi 1. Detroit Edison recognized impairment charges of $0.2 million in each year for unrealized losses incurred by the Fermi 1 trust.
Nuclear Fuel Disposal Costs
In accordance with the Federal Nuclear Waste Policy Act of 1982, Detroit Edison has a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. Detroit Edison is obligated to payyear ended December 31, 2007.
Other Available-For-Sale Securities
The following table summarizes the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold. The fee is a component of nuclear fuel expense. Delays have occurred in the DOE’s program for the acceptance and disposal of spent nuclear fuel at a permanent repository. Detroit Edison is 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. Detroit Edison currently employs a used nuclear fuel storage strategy utilizing a spent fuel pool. In December 2007, Detroit Edison announced plans to move to a dry cask storage method which is expected to provide sufficient storage capability for the lifefair value of the plant.Company’s investment in available-for-sale debt and equity securities, excluding nuclear decommissioning trust fund assets:
                 
  December 31, 2009 December 31, 2008
(in Millions) Fair Value Carrying value Fair Value Carrying Value
Cash equivalents $105  $105  $98  $98 
Equity securities $4  $4  $20  $20 
At December 31, 2009 and 2008, these securities are comprised primarily of money-market and equity securities. Gains (losses) related to trading securities held at December 31, 2009, 2008, and 2007 were $8 million, $(14) million and $3 million respectively.

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NOTE 5 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS
The Company recognizes all derivatives on the Consolidated Statements of Financial Position at their fair value unless they qualify for certain scope exceptions, including the normal purchases and normal sales exception. Further, derivatives that qualify and are designated for hedge accounting are classified as either hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge), or as hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge). For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the value of the underlying exposure is deferred in Accumulated other comprehensive income and later reclassified into earnings when the underlying transaction occurs. For fair value hedges, changes in fair values for the derivative are recognized in earnings each period. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For derivatives that do not qualify or are not designated for hedge accounting, changes in the fair value are recognized in earnings each period.
The Company’s primary market risk exposure is associated with commodity prices, credit and interest rates. The Company has risk management policies to monitor and manage market risks. The Company uses derivative instruments to manage some of the exposure. Contracts the Company typically classifies as derivative instruments include power, certain coal forwards, futures, options and swaps.
Detroit Edison generates, purchases, distributes and sells electricity. Detroit Edison uses forward energy and capacity contracts to manage changes in the price of electricity and fuel. Substantially all of these contracts meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. Other derivative contracts are recoverable through the PSCR mechanism when settled. This results in the deferral of unrealized gains and losses as Regulatory assets or liabilities, until realized.
The following represents the fair value of derivative instruments as of December 31, 2009:
         
  Balance Sheet  Fair 
  Location  Value 
(in Millions)      
FTRs Other current assets $2 
Emissions Other current liabilities  (5)
Emissions Other non-current liabilities  (3)
        
Total derivatives not designated as hedging instrument
     $(6)
        
         
Total derivatives:
        
Current     $(3)
Noncurrent      (3)
        
Total derivatives as reported
     $(6)
        
The effect of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position for the year ended December 31, 2009 is as follows:
         
      Year Ended 
  Location of Gain  Gain (Loss) 
  (Loss) Recognized  Recognized in 
  in Regulatory  Regulatory Assets 
  Assets / Liabilities  / Liabilities on 
  On Derivative  Derivative 
(in Millions)      
FTRs and Emissions Regulatory Asset $(14)
FTRs and Emissions Regulatory Liability  (2)
        
Total
     $(16)
        

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The following represents the cumulative gross volume of derivative contracts outstanding as of December 31, 2009:
CommodityNumber of Units
Emissions (Tons)61,927
FTRs (MW)4,486
NOTE 6 — PROPERTY, PLANT AND EQUIPMENT
Summary of property by classification as of December 31:
         
(in Millions) 2009  2008 
Property, Plant and Equipment
        
Generation $8,833  $8,544 
Distribution  6,618   6,433 
       
Total  15,451   14,977 
       
         
Less Accumulated Depreciation and Amortization
        
Generation  (3,890)  (3,690)
Distribution  (2,243)  (2,138)
       
Total  (6,133)  (5,828)
       
Net Property, Plant and Equipment
 $9,318  $9,149 
       
AFUDC capitalized during 2009 and 2008 was approximately $12 million and $44 million, respectively.
The composite depreciation rate for Detroit Edison was 3.3% in 2009, 2008 and 2007.
The average estimated useful life for our generation and distribution property was 40 years and 37 years, respectively, at December 31, 2009.
Capitalized software costs amortization expense was $55 million in 2009, $45 million in 2008, and $31 million in 2007. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2009 were $488 million and $161 million, respectively. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2008 were $454 million and $126 million, respectively. Amortization expense of capitalized software costs is estimated to be $60 million annually for 2010 through 2014.
Gross property under capital leases was $121 million at December 31, 2009 and December 31, 2008. Accumulated amortization of property under capital leases was $88 million and $80 million at December 31, 2009 and December 31, 2008, respectively.

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NOTE 7 — JOINTLY OWNED UTILITY PLANT
Detroit Edison has joint ownership interest in two power plants, Belle River and Ludington Hydroelectric Pumped Storage. Detroit Edison’s share of direct expenses of the jointly owned plants are included in Fuel, purchased power and gas and Operation and maintenance expenses in the Consolidated Statements of Operations. Ownership information of the two utility plants as of December 31, 20072009 was as follows:
                
 Ludington Ludington
 Hydroelectric Hydroelectric
 Belle River Pumped Storage Belle River Pumped Storage
In-service date 1984-1985 1973  1984-1985 1973 
Total plant capacity 1,026 MW 1,872 MW 1,260 MW 1,872 MW
Ownership interest *  49% *  49%
Investment (in Millions) $1,575 $164  $1,626 $197 
Accumulated depreciation (in Millions) $847 $101  $889 $128 
 
* Detroit Edison’s ownership interest is 63% in Unit No. 1, 81% of the facilities applicable to Belle River used jointly by the Belle River and St. Clair Power Plants and 75% in common facilities used at Unit No. 2.
Belle River
The Michigan Public Power Agency (MPPA) has an ownership interest in Belle River Unit No. 1 and other related facilities. The MPPA is entitled to 19% of the total capacity and energy of the plant and is responsible for the same percentage of the plant’s operation, maintenance and capital improvement costs.
Ludington Hydroelectric Pumped Storage
Consumers Energy Company has an ownership interest in the Ludington Hydroelectric Pumped Storage Plant. Consumers Energy is entitled to 51% of the total capacity and energy of the plant and is responsible for the same percentage of the plant’s operation, maintenance and capital improvement costs.

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NOTE 78 — ASSET RETIREMENT OBLIGATIONS
The Company has a legal retirement obligation for the decommissioning costs for its Fermi 1 and Fermi 2 nuclear plants. The Company has conditional retirement obligations for disposal of asbestos at certain of its power plants. To a lesser extent, the Company has conditional retirement obligations at certain service centers and disposal costs for PCB contained within transformers and circuit breakers. The Company recognizes such obligations as liabilities at fair market value when they are incurred, which generally is at the time the associated assets are placed in service. Fair value is measured using expected future cash outflows discounted at our credit-adjusted risk-free rate. In its regulated operations, the Company defers timing differences that arise in the expense recognition of legal asset retirement costs that are currently recovered in rates.
No liability has been recorded with respect to lead-based paint, as the quantities of lead-based paint in the Company’s facilities are unknown. In addition, there is no incremental cost to demolitions of lead-based paint facilities vs. non-lead-based paint facilities and no regulations currently exist requiring any type of special disposal of items containing lead-based paint.
The Ludington Hydroelectric Power Plant (a jointly owned 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 liability has been recorded for these assets.
A reconciliation of the asset retirement obligations for 2009 follows:
     
(in Millions)    
Asset retirement obligations at January 1, 2009 $1,226 
Accretion  80 
Liabilities settled  (10)
Revision in estimated cash flows  4 
    
Asset retirement obligations at December 31, 2009  1,300 
Less amount included in current liabilities  (15)
    
  $1,285 
    
Detroit Edison has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. This obligation is reflected as an asset retirement obligation on the Consolidated Statements of Financial Position. Based on the actual or anticipated extended life of the nuclear plant, decommissioning expenditures for Fermi 2 are expected to be incurred primarily during the period of 2025 through 2050. It is estimated that the cost of decommissioning Fermi 2, when its license expires in 2025, will be $1.3 billion in 2009 dollars and $3.4 billion in 2025 dollars, using a 6% inflation rate. In 2001, Detroit Edison began the decommissioning of Fermi 1, with the goal of removing the radioactive material and terminating the Fermi 1 license. The decommissioning of Fermi 1 is expected to be completed by 2012. Approximately $1.2 billion of the asset retirement obligations represent nuclear decommissioning liabilities that are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear plant.
The NRC has jurisdiction over the decommissioning of nuclear power plants and requires decommissioning funding based upon a formula. The MPSC and FERC regulate the recovery of costs of decommissioning nuclear power plants and both require the use of external trust funds to finance the decommissioning of Fermi 2. Rates approved by the MPSC provide for the recovery of decommissioning costs of Fermi 2 and the disposal of low-level radioactive waste. Detroit Edison is continuing to fund FERC jurisdictional amounts for decommissioning even though explicit provisions are not included in FERC rates. The Company believes the MPSC and FERC collections will be adequate to fund the estimated cost of decommissioning using the NRC formula. The decommissioning assets, anticipated earnings thereon and future revenues from decommissioning collections will be used to decommission Fermi 2. The Company expects the liabilities to be reduced to zero at the conclusion of the decommissioning activities. If amounts remain in the trust funds for Fermi 2 following the completion of the decommissioning activities, those amounts will be disbursed based on rulings by the MPSC and FERC.
A portion of the funds recovered through the Fermi 2 decommissioning surcharge and deposited in external trust accounts is designated for the removal of non-radioactive assets and the clean-up of the Fermi site. This removal and

40


clean-up is not considered a legal liability. Therefore, it is not included in the asset retirement obligation, but is reflected as the nuclear decommissioning liability.
The decommissioning of Fermi 1 is funded by Detroit Edison. Contributions to the Fermi 1 trust are discretionary. See Note 4 for additional discussion of Nuclear Decommissioning Trust Fund Assets.
NOTE 9 — RESTRUCTURING
Performance Excellence Process
In 2005, the Company initiated a company-wide review of its operations called the Performance Excellence Process. Specifically, the Company began a series of focused improvement initiatives within Detroit Edison and associated corporate support functions. The Company incurred costs to achieve (CTA) restructuring expense for employee severance and other costs. Other costs include project management and consultant support. In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison, commencing in 2006, to defer the incremental CTA. Further, the order provides for Detroit Edison 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 $24 million and $54 million of CTA in 2008 and 2007 as a regulatory asset. The recovery of these costs was provided for by the MPSC in the order approving the settlement in the show cause proceeding and in the December 23, 2008 MPSC rate order. Amortization of prior year deferred CTA costs amounted to $18 million in 2009, $16 million in 2008 and $10 million in 2007.
Amounts expensed are recorded in the Operation and maintenance line on the Consolidated Statements of Operations. Deferred amounts are recorded in Regulatory assets on the Consolidated Statements of Financial Position. Costs incurred in 2008 and 2007 are as follows:
                         
  Employee Severance Costs(1)  Other Costs  Total Cost 
(in Millions) 2008  2007  2008  2007  2008  2007 
Costs incurred: $  $15  $26  $50  $26  $65 
Less amounts deferred or capitalized:     15   26   50   26   65 
                   
Amount expensed $  $  $  $  $  $ 
                   
(1)Includes corporate allocations

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NOTE 10 — REGULATORY MATTERS
Regulation
Detroit Edison is 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. Regulation results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses.
Regulatory Assets and Liabilities
Detroit Edison is required to record regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Continued applicability of regulatory accounting treatment 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 discontinuance of this accounting treatment for regulatory assets and liabilities for some or all of our 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 use of regulatory assets and liabilities and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment.
The following are balances and a brief description of the regulatory assets and liabilities at December 31:
         
(in Millions) 2009  2008 
     
Assets
        
Recoverable pension and postretirement costs:        
Pension $1,261  $1,133 
Postretirement costs  515   609 
Recoverable income taxes related to securitized regulatory assets  476   549 
Asset retirement obligation  415   452 
Deferred income taxes — Michigan Business Tax  343   336 
Costs to achieve Performance Excellence Process  136   154 
Other recoverable income taxes  89   89 
Enterprise Business Systems costs  24   26 
Recoverable costs under PA 141        
Unamortized loss on reacquired debt  38   40 
Electric Customer Choice implementation costs  18   37 
Deferred Clean Air Act expenditures     10 
Accrued PSCR revenue     20 
Other  18   21 
       
   3,333   3,476 
Less amount included in current assets     (20)
       
  $3,333  $3,456 
       
         
Securitized regulatory assets $870  $1,001 
       
         
Liabilities
        
Deferred income taxes — Michigan Business Tax $367  $335 
Asset removal costs  157   182 
Accrued pension  75   72 
Renewable energy program  32    
Refundable costs under PA 141  27   16 
Refundable self implemented rates  27    
Refundable restoration expense  15    
Accrued PSCR refund  14   11 
Fermi 2 refueling outage  13   25 
Other  11   4 
       
   738   645 
Less amount included in current liabilities  (27)  (52)
       
  $711  $593 
       

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As noted below, regulatory assets for which costs have been incurred have been included (or are expected to be included, for costs incurred subsequent to the most recently approved rate case) in Detroit Edison’s rate base, thereby providing a return on invested costs. Certain regulatory assets do not result from cash expenditures and therefore do not represent investments included in rate base or have offsetting liabilities that reduce rate base.
ASSETS
Recoverable pension and postretirement costs— In 2007, the Company adopted ASC 715 (SFAS No. 158) which required, among other things, the recognition in other comprehensive income of the actuarial gains or losses and the prior service costs that arise during the period but that are not immediately recognized as components of net periodic benefit costs. The Company records the charge related to the additional liability as a regulatory asset since the traditional rate setting process allows for the recovery of pension and postretirement costs. The asset will reverse as the deferred items are recognized as benefit expenses in net income. (1)
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.
Asset retirement obligation— This obligation is primarily for Fermi 2 decommissioning costs. The asset captures the timing differences between expense recognition and current recovery in rates and will reverse over the remaining life of the related plant. (1)
Deferred income taxes — Michigan Business Tax (MBT)— In July 2007, the MBT was enacted by the State of Michigan. State deferred tax liabilities were established for the Company’s utilities, and offsetting regulatory assets were recorded as the impacts of the deferred tax liabilities will be reflected in rates as the related taxable temporary differences reverse and flow through current income tax expense. (1)
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. (1)
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. This asset will reverse over the remaining life of the related plant. (1)
Enterprise Business Systems (EBS) costs— The MPSC approved the deferral and amortization over 10 years beginning in January 2009 of EBS costs that would otherwise be expensed. (1)
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. (1)
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.
Deferred Clean Air Act expenditures— PA 141 permits, after MPSC authorization, the recovery of and a return on Clean Air Act expenditures.
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.
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.
(1)Regulatory assets not earning a return.

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LIABILITIES
Deferred income taxes — Michigan Business Tax —In July 2007, the MBT was enacted by the State of Michigan. State deferred tax assets were established for the Company’s utilities, and offsetting regulatory liabilities were recorded as the impacts of the deferred tax assets will be reflected in rates.
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.
Renewable energy —Amounts collected in rates in excess of renewable energy expenditures.
Refundable costs under PA 141 —Detroit Edison’s 2007 Choice Incentive Mechanism (CIM) reconciliation and allocation resulted in the elimination of Regulatory Asset Recovery Surcharge (RARS) balances for commercial and industrial customers. RARS revenues received in 2008 that exceed the regulatory asset balances are required to be refunded to the affected classes.
Refundable self implemented rates —Amounts due customers for self implemented rates in excess of amounts provided for in January 2010 Detroit Edison MPSC order.
Refundable restoration expense —Amounts refundable for the MPSC approved restoration expenses tracking mechanism that tracks the difference between actual restoration expense and the amount provided for in base rates, recognized pursuant to the MPSC authorization.
Accrued PSCR refund— Liability for the temporary over-recovery of and a return on power supply costs and transmission costs incurred by Detroit Edison which are recoverable through the PSCR mechanism.
Fermi 2 refueling outage— Accrued liability for refueling outage at Fermi 2 pursuant to MPSC authorization.
2009 Electric Rate Case Filing
On January 11, 2010, the MPSC issued an order in Detroit Edison’s January 26, 2009 rate case filing. The MPSC approved an annual revenue increase of $217 million or a 4.8% increase in Detroit Edison’s annual revenue requirement for 2010. Included in the approved increase in revenues was a return on equity of 11% on an expected 49% equity and 51% debt capital structure. Since the final rate relief ordered was less than the Company’s self-implemented rate increase of $280 million effective on July 26, 2009, the MPSC ordered refunds for the period the self-implemented rates were in effect. Detroit Edison has recorded a refund liability of $27 million at December 31, 2009 representing the 2009 portion of the estimated refund due customers, including interest. The MPSC ordered Detroit Edison to file a refund plan by April 1, 2010.
Other key aspects of the MPSC order include the following:
Continued progress toward correcting the existing rate structure to more accurately reflect the actual cost of providing service to business customers;
Continued application of an adjustment mechanism for Electric Choice sales that reconciles actual customer choice sales with a base customer choice sales level of 1,586 GWh;
Continued application of adjustment mechanisms to track expenses associated with restoration costs (storm and non-storm related expenses) and line clearance expenses. Annual reconciliations will be required using a base expense level of $117 million and $47 million, respectively. The change in base expense level was applied effective as of the July 26, 2009 self-implementation date;

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Implementation of a pilot Revenue Decoupling Mechanism, that will compare actual non-weather normalized sales per customer with the base sales per customer level established in this case for the period February 1, 2010 to January 31, 2011; and
Implementation of an Uncollectible Expense Tracking Mechanism, based on a $66 million expense level, with an 80/20 percent sharing of the expenses above or below the base amount. The Uncollectible Expenses Tracking Mechanism was applied effective as of the July 26, 2009 self-implementation date.
Renewable Energy Plan
In March 2009, Detroit Edison filed its Renewable Energy Plan with the MPSC as required under 2008 PA 295. The Renewable Energy Plan application requests authority to recover approximately $35 million of additional revenue in 2009. The proposed revenue increase is necessary in order to properly implement Detroit Edison’s 20-year renewable energy plan to address the provisions of 2008 PA 295, to deliver cleaner, renewable electric generation to its customers, to further diversify Detroit Edison’s and the State of Michigan’s sources of electric supply, and to address the state and national goals of increasing energy independence. An MPSC order was issued June 2, 2009 approving the renewable energy plan and customer surcharges. The Renewable Energy Plan surcharges became effective in September 2009.
Energy Optimization Plans
In March 2009, Detroit Edison filed an Energy Optimization Plan with the MPSC as required under 2008 PA 295. The Energy Optimization Plan application is designed to help each customer class reduce their electric usage by: (1) building customer awareness of energy efficiency options and (2) offering a diverse set of programs and participation options that result in energy savings for each customer class. Detroit Edison’s Energy Optimization Plan application proposed energy optimization expenditures for the period 2009-2011 of $134 million and further requests approval of surcharges that are designed to recover these costs. An MPSC order was issued June 2, 2009 approving the Energy Optimization Plans of $117 million for Detroit Edison. The surcharges to recover these costs were implemented effective June 3, 2009. An MPSC order was issued September 29, 2009 approving incentive mechanisms for the utility. The mechanism allows a maximum payout of 15% of program expenditures when the utility meets or exceeds the savings target by 15%.
2009 Detroit Edison Depreciation Filing
In 2007, the MPSC ordered Michigan utilities to file depreciation studies using the current method, an approach that considers the time value of money and an inflation adjusted method proposed by the Company that removes excess escalation. In compliance with the MPSC order, Detroit Edison filed its ordered depreciation studies in November 2009. The various required depreciation studies indicate composite depreciation rates from 3.05% to 3.54%. The Company has proposed no change to its current composite depreciation rate of 3.33%. The Company expects an order in this proceeding in the fourth quarter of 2010.
Power Supply Cost Recovery Proceedings
The PSCR process is designed to allow us to recover all of our power supply costs if incurred under reasonable and prudent policies and practices. Our power supply costs include fuel costs, purchased and net interchange power costs, nitrogen oxide and sulfur dioxide emission allowances costs, transmission costs and MISO costs. The MPSC reviews these costs, policies and practices for prudence in annual plan and reconciliation filings.
2007 Plan Year— An MPSC order was issued on January 25, 2010 approving a 2007 PSCR under collection amount of $38 million inclusive of a $2.7 million outage disallowance and the recovery of this amount as part of the 2008 PSCR reconciliation. In addition, the order approved Detroit Edison’s Pension Equalization Mechanism reconciliation and authorized the Company to refund the $21 million over recovery, including interest, to customers in February 2010.

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The following table summarizes Detroit Edison’s PSCR reconciliation filing currently pending with the MPSC:
Net OverPSCR Cost of PowerDescription of Net
PSCR YearDate Filed(Under)-recoverySoldUnder-recovery
2008March 2009($15.6) million$1.3 billionThe total amount reflects an under-recovery of $14.8 million, plus $0.8 million in accrued interest due from customers
2009 Plan Year— In September 2008, Detroit Edison submitted its 2009 PSCR plan filing to the MPSC. The plan includes the recovery of its 2008 PSCR under-collection from all customers and the refund of its 2005 PSCR reconciliation surcharge over-collection to commercial and industrial customers only. On June 29, 2009, the parties to this proceeding submitted a Settlement Agreement in this matter agreeing to maximum PSCR factors of 1.67 mills/kWh for residential customers and 1.35 mills/kWh for commercial and industrial customers and otherwise resolving this 2009 PSCR Plan case. An MPSC order was issued on January 25, 2010 approving the settlement.
2010 Plan Year— In September 2009, Detroit Edison submitted its 2010 PSCR plan case seeking approval of a levelized PSCR factor of 5.64 mills/kWh below the amount included in base rates for all PSCR customers. The filing supports a 2010 power supply expense forecast of $1.2 billion. Also included in the filing is a request for approval of the Company’s expense associated with the use of urea in the selective catalytic reduction units at Monroe power plant as well as a request for approval of a contract for capacity and energy associated with a wind energy project. The Company has also requested authority to recover transfer prices for renewable energy, coke oven gas expense and other potential expenses.
Merger Control Premium Costs
In July 2007, the State of Michigan Court of Appeals published its decision with respect to an appeal by Detroit Edison and others of certain provisions of a November 2004 MPSC order, including reversing the MPSC’s denial of recovery of merger control premium costs. In its published decision, the Court of Appeals held that Detroit Edison is entitled to recover its allocated share of the merger control premium and remanded this matter to the MPSC for further proceedings to establish the precise amount and timing of this recovery. Other parties filed requests for leave to appeal to the Michigan Supreme Court from the Court of Appeals decision and in September 2008, the Michigan Supreme Court granted the requests to address the merger control premium as well as the recovery of transmission costs through the PSCR. On May 1, 2009, the Michigan Supreme Court issued an order reversing the Court of Appeals decision with respect to recovery of the merger control premium, and reinstated the MPSC’s decision excluding the control premium costs from Detroit Edison’s general rates. The Court affirmed the lower court’s decision upholding the right of Detroit Edison to recover electric transmission costs through the Company’s PSCR clause. The Company requested rehearing of the Supreme Court order on the merger premium and the Michigan Attorney General requested rehearing of the transmission portion of the order. On June 26, 2009, the Michigan Supreme Court denied request for a rehearing. The above actions did not have an impact on the Company’s consolidated financial statements.
Other
The Company is unable to predict the outcome of the unresolved regulatory matters discussed herein. Resolution of these matters is dependent upon future MPSC orders and appeals, which may materially impact the financial position, results of operations and cash flows of the Company.

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NOTE 11 — INCOME TAXES
Income Tax Summary
We are part of the consolidated federal income tax return of DTE Energy. The federal income tax expense for Detroit Edison is determined on an individual company basis with no allocation of tax benefits or expenses from other affiliates of DTE Energy. We havehad an income tax receivablepayable of $34$75 million at December 31, 20072009 and $16an income tax payable of $33 million at December 31, 20062008 due fromto DTE Energy.
Total income tax expense varied from the statutory federal income tax rate for the following reasons:
                        
(Dollars in Millions) 2007 2006 2005  2009 2008 2007 
Income tax expense at 35% statutory rate $163 $169 $149  $211 $181 $163 
  
Investment tax credits  (7)  (7)  (7)  (6)  (6)  (7)
Depreciation 3 3 3  3 3 3 
Employee Stock Ownership Plan dividends  (4)  (4)  (4)  (4)  (2)  (4)
Medicare Part D subsidy  (4)  (5)  (6)  (5)  (4)  (4)
Adjustment to deferred tax accounts   14 
Domestic production activities deduction  (5)  (2)  (2)
State and other income taxes, net of federal benefit 36 19 1 
Other, net  (2) 6    (2)  (3)  (1)
              
Total $149 $162 $149  $228 $186 $149 
              
  
Effective federal income tax rate  32.0%  33.6%  35.0%
Effective income tax rate  37.7%  36.0%  32.0%
              

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Components of income tax expense (benefits) were as follows:
                        
(in Millions) 2007 2006 2005  2009 2008 2007 
Current federal and other income tax expense (benefit) $260 $160 $110 
Deferred federal and other income tax expense  (111) 2 39 
Current income taxes Federal $168 $66 $257 
State and other income tax expense 45 30 3 
       
Total current income taxes 213 96 260 
       
Deferred income taxes Federal 4 91  (109)
State and other income tax expense 11  (1)  (2)
       
Total deferred income taxes 15 90  (111)
              
Total $149 $162 $149  $228 $186 $149 
              
Investment tax credits are deferred and amortized to income over the average life of the related property.
Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in the financial statements. Deferred tax assets and liabilities are classified as current or noncurrent according to the classification of the related assets or liabilities. Deferred tax assets and liabilities not related to assets or liabilities are classified according to the expected reversal date of the temporary differences. Consistent with rate making treatment, deferred taxes are offset in the table below for temporary differences which have related regulatory assets and liabilities.
Deferred income tax assets (liabilities) were comprised of the following at December 31:
                
(in Millions) 2007 2006  2009 2008 
Property, plant and equipment $(1,156) $(1,209) $(1,409) $(1,297)
Securitized regulatory assets  (621)  (670)  (474)  (545)
Pension and benefits 101 94  103 110 
Other comprehensive income  (2)  (1) 9  (1)
Other, net  (176)  (180)  (76)  (142)
          
 $(1,854) $(1,966) $(1,847) $(1,875)
          
 
Deferred income tax liabilities $(2,662) $(2,478)
Deferred income tax assets 808 512 
     
 $(1,854) $(1,966)
     
 
Current deferred income tax liabilities (included in Current Liabilities – Other) $(29)  (38)
Long term deferred income tax liabilities  (1,825)  (1,928)
     
 $(1,854)  (1,966)
     

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(in Millions) 2009  2008 
Deferred income tax liabilities $(2,832) $(2,777)
Deferred income tax assets  985   902 
       
  $(1,847) $(1,875)
       
         
Current deferred income tax asset (included in Current Assets — Other) $24  $19 
Long term deferred income tax liabilities  (1,871)  (1,894)
       
  $(1,847) $(1,875)
       
The above table excludes deferred tax liabilities associated with unamortized investment tax credits that are shown separately on the Consolidated StatementStatements of Financial Position.
Uncertain Tax Positions
The Company adopted the provisions of FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109 (FIN 48)on January 1, 2007. This interpretation prescribes a more-likely-than-not recognition threshold and a measurement attribute for the financial statement reporting of tax positions taken or expected to be taken on a tax return. As a result of the implementation of FIN 48, the Company recognized a decrease in liabilities that was accounted for as an increase to the January 1, 2007 balance of retained earnings in an immaterial amount. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

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(in Millions)    
Balance at January 1, 2007 $12 
Additions for tax positions of prior years  2 
Settlements  (7)
    
Balance at December 31, 2007 $7 
    
             
(in Millions) 2009  2008  2007 
Balance at January 1 $70  $7  $12 
Additions for tax positions of current years  10   72   2 
Additions for tax positions of prior years  24   (9)   
Reductions for tax positions of prior years  (8)     (7)
          
Balance at December 31 $96  $70  $7 
          
Unrecognized tax benefits at January 1, 2007 and at December 31, 2007,2009, if recognized, would not favorably impact our effective tax rate. We do not anticipate any significant changes in the unrecognized tax benefits during the next twelve months.rate by $2 million.
The Company recognizes interest and penalties pertaining to income taxes in Interest expense and Other expenses, respectively, on its Consolidated Statements of Operations. Accrued interest pertaining to income taxes totaled $1$6 million and $1 million at January 1, 2007December 31, 2009 and December 31, 2007,2008, respectively. The Company had no accrued penalties pertaining to income taxes. The Company recognized $5 million for interest expense related to income taxes of $1 million during 2007.2009 and an immaterial amount during 2008.
In 2009, DTE Energy and its subsidiaries settled a federal tax audit for the 2004 through 2006 tax years. The resulting change to unrecognized tax benefits was not significant. The Company’s U.S. federal income tax returns for years 20042007 and subsequent years remain subject to examination by the IRSIRS. The Company’s Michigan Business Tax for DTE Energy Company and its subsidiaries.the year 2008 is subject to examination by the State of Michigan. The Company also files tax returns in variousnumerous state and local tax jurisdictions with varying statutes of limitation.
Michigan Business Tax
OnIn July 12, 2007, the Michigan Business Tax (MBT) was enacted by the State of Michigan to replace the Michigan Single Business Tax (MSBT) effective January 1, 2008. The MBT is comprised of an apportioned modified gross receipts tax of 0.8 percent and an apportioned business income tax of 4.95 percent. The MBT provides credits for Michigan business investment, compensation, and research and development. The MBT will be accounted for as an income tax.
InLegislation was also enacted, in 2007, a state deferred tax liability of $318 million was recognized by the Company for cumulative differences between book and tax assets and liabilities for the Company. Effective September 30, 2007, legislation was adopted by the State of Michigan creating a deduction for businesses that realize an increase in their deferred tax liability due to the enactment of the MBT. Therefore, aThe MBT is accounted for as an income tax.
The MBT consolidated deferred tax liability balance is $354 million as of December 31, 2009 and is reported net of the related federal tax benefit. The MBT deferred tax asset balance is $367 million as of $318 million was established related to the future deduction. The deduction will be claimed during the period of 2015 through 2029. The recognitionDecember 31, 2009 and is reported net of the enactment of the MBT did not have an impact on our income tax provision for 2007.
The $318 million ofrelated federal deferred tax liabilitiesliability. The regulated asset balance is $343 million and assets recognized by the Company was offset by corresponding regulatory assetsregulated liability balance is $367 million as of December 31, 2009 and liabilitiesis further discussed in accordance with SFAS No. 71,Accounting for the Effects of Certain Types of Regulation,as the impacts of the deferred tax liabilities and assets recognized upon enactment and amendment of the MBT will be reflected in our rates.Note 10.

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NOTE 812 — LONG-TERM DEBT
Our long-term debt outstanding and weighted average interest rates(1) of debt outstanding at December 31 were:
                
(in Millions) 2007 2006  2009 2008 
Detroit Edison Taxable Debt, Principally Secured
  
5.9% due 2010 to 2038 $2,305 $2,267  $2,829 $2,841 
Detroit Edison Tax Exempt Revenue Bonds (2)
 
5.3% due 2008 to 2036 1,213 1,213 
Other Long-Term Debt
  59 
Detroit Edison Tax- Exempt Revenue Bonds (2)
 
5.5% due 2011 to 2038 1,263 1,263 
          
 3,518 3,539  4,092 4,104 
Less amount due within one year  (45)  (24)  (513)  (13)
          
 $3,473 $3,515  $3,579 $4,091 
          
  
Securitization Bonds
  
6.4% due 2008 to 2015 $1,185 $1,295 
6.5% due 2010 to 2015 $933 $1,064 
Less amount due within one year  (120)  (111)  (140)  (132)
          
 $1,065 $1,184  $793 $932 
          
 
(1) Weighted average interest rates as of December 31, 20072009 are shown below the description of each category of debt.
 
(2) Detroit Edison Tax ExemptTax-Exempt Revenue Bonds are issued by a public body that loans the proceeds to Detroit Edison on terms substantially mirroring the Revenue Bonds.
Debt Issuances
In 2007,2009, we issued the following long-term debt:
                 
Month             (in Millions)
Issued Type Interest Rate Maturity   Amount
 
December Senior Notes (1)  6.47% March 2038 $50 
               
(in Millions)           
Month Issued Type Interest Rate  Maturity  Amount 
 
April Tax-Exempt Revenue Bonds (1)  6.00%  2036   69 
June Tax-Exempt Revenue Bonds (2)  5.625%  2020   32 
June Tax-Exempt Revenue Bonds (3)  5.25%  2029   60 
June Tax-Exempt Revenue Bonds (4)  5.50%  2029   59 
November Tax-Exempt Revenue Bonds (5)  3.05%  2024   65 
              
            $285 
              
 
(1) The proceeds from the issuanceProceeds were used to refinance other long-term debtrefund existing Tax-Exempt Revenue Bonds.
(2)These Tax-Exempt Revenue Bonds were converted from a variable rate mode and for general corporate purposes.remarketed in a fixed rate mode to maturity.
(3)These Tax-Exempt Revenue Bonds were converted from a variable rate mode and remarketed in a fixed rate mode with a five-year mandatory put.
(4)These Tax-Exempt Revenue Bonds were converted from a variable rate mode and remarketed in a fixed rate mode with a seven-year mandatory put.
(5)These Tax-Exempt Revenue Bonds were issued in a fixed rate mode with a three-year mandatory put. Proceeds were used to refund existing Tax-Exempt Revenue Bonds.

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Debt Retirements and Redemptions
The following debt was retired, through optional redemption or payment at maturity, during 2007.2009.
                 
Month             (in Millions)
Retired Type Interest Rate Maturity   Amount
 
December Other long term debt  7.61% June 2011 $47 
               
(in Millions)           
Month Retired Type Interest Rate  Maturity  Amount 
 
April Tax-Exempt Revenue Bonds (1) Variable  2036  $69 
December Tax-Exempt Revenue Bonds (1)  6.40%  2024   65 
              
            $134 
              
(1)These Tax-Exempt Revenue Bonds were redeemed with the proceeds from the issuance of new Detroit Edison Tax-Exempt Revenue Bonds.
The following table shows the scheduled debt maturities, excluding any unamortized discount or premium on debt:
                                                        
 2013 &   2015 &   
(in Millions) 2008 2009 2010 2011 2012 thereafter Total 2010 2011 2012 2013 2014 thereafter Total 
  
Amount to mature $165 $145 $652 $303 $402 $3,041 $4,708  $513 $152 $303 $313 $341 $2,475 $4,097 

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Cross Default Provisions
Substantially all of the net properties of Detroit Edison are subject to the lien of its mortgage. Should Detroit Edison fail to timely pay its indebtedness under this mortgage, such failure may create cross defaults in the indebtedness of DTE Energy.
Other
As of December 31, 2007, the Company had $238 million of variable auction rate tax exempt bonds outstanding. These bonds, which are subject to rate reset every 7 days, are insured by bond insurers. Overall credit market conditions have resulted in credit rating downgrades and may result in future credit rating downgrades for the bond insurers. This has caused a loss in liquidity in the auction rate markets for their insured bonds. These conditions have negatively impacted interest rates, including default rates in the case of failed auctions. The Company does not expect its interest rate exposure regarding these bonds to be material.
NOTE 913 — PREFERRED AND PREFERENCE SECURITIES
At December 31, 2007,2009, Detroit Edison had approximately 6.75 million shares of preferred stock with a par value of $100 per share and 30 million shares of preference stock with a par value of $1 per share authorized, with no shares issued.
NOTE 1014 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS
In October 2005, Detroit Edison entered intohas a $69 million, five-year unsecured revolving credit agreement and simultaneously amended its existing $206 million, five-year credit facility entered intoexpiring in October 2004. Our aggregate availability under the combined facilities is $275 million.2010 and a $212 million, two-year unsecured revolving credit agreement expiring in April 2011. The five-year and two-year credit facilities are with a syndicate of 22 banks and may be utilizedused for general corporate borrowings, but are intended to provide liquidity support for our commercial paper program. No one bank provides more than 8.5% of the commitment in any facility. Borrowings under the facilities are available at prevailing short-term interest rates. The above agreements require usthe Company to maintain a total funded debt to capitalization ratio, as defined in the agreements, of no more than 0.65 to 1. At December 31, 2009, the debt to total capitalization ratio of no more than 0.65for Detroit Edison is 0.52 to 1. Should we have delinquent obligations of at least $50 million to any creditor,creditor; such delinquency will be considered a default under our credit agreements.
Detroit Edison is currently in compliance with its covenants.
We had no outstanding commercial paper of $181 millionas of December 31, 2009 and $177 millionDecember 31, 2008.
Detroit Edison had no short-term borrowings at December 31, 20072009 and 2006, respectively.
$75 million outstanding at December 31, 2008. The weighted average interest rate for short-term borrowings were 5.4%was 1.3% at December 31, 2007 and 2006.
Detroit Edison has a $200 million short-term financing agreement secured by customer accounts receivable. This agreement contains certain covenants related to the delinquency of accounts receivable.2008.

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Detroit Edison is currently in compliance with these covenants. We had an outstanding balance of $125 million and $100 million at December 31, 2007 and December 31, 2006, respectively.
Detroit Edison initiated a $100 million short-term unsecured bank loan in the fourth quarter of 2007. The purpose of these loans was to enhance liquidity and reduce reliance on the commercial paper market. The loans have covenants identical to those specified under our back-up credit facilities. Detroit Edison was in compliance with those covenants at December 31, 2007. Detroit Edison had $100 million outstanding under these loans at December 31, 2007.
NOTE 1115 — CAPITAL AND OPERATING LEASES
Lessee– We lease— The Company leases various assets under capital and operating leases, including coal cars, computers, vehicles and other equipment. The lease arrangements expire at various dates through 2023.
Future minimum lease payments under non-cancelable leases at December 31, 20072009 were:
                
 Capital Operating  Capital Operating 
(in Millions) Leases Leases  Leases Leases 
2008 $11 $37 
2009 11 30 
2010 9 23  $9 $23 
2011 7 18  7 22 
2012 5 17  5 22 
2013 5 19 
2014 4 14 
Thereafter 17 69  7 77 
          
Total minimum lease payments 60 $194  37 $177 
      
Less imputed interest  (10)  5 
        
Present value of net minimum lease payments 50  32 
Less current portion  (8)  7 
      
Non-current portion $42  $25 
      
Rental expense for operating leases was $48 million in 2007, $442009, $39 million in 2006,2008, and $28$48 million in 2005.2007.
NOTE 12 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS
We comply with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. Under SFAS No. 133, all derivatives are recognized on the Consolidated Statements of Financial Position at their fair value unless they qualify for certain scope exceptions, including normal purchases and normal sales exception. Further, derivatives that qualify and are designated for hedge accounting are classified as either hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge), or as hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge). For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the value of the underlying exposure is deferred in Accumulated other comprehensive income and later reclassified into earnings when the underlying transaction occurs. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For derivatives that do not qualify or are not designated for hedge accounting, changes in the fair value are recognized in earnings each period.

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Our primary market risk exposure is associated with commodity prices and credit. We have risk management policies to monitor and decrease market risks. We use derivative instruments to manage some of the exposure. We do not hold or issue derivative instruments for trading purposes.
Commodity Price Risk
Detroit Edison uses forward energy and capacity contracts to manage changes in the price of electricity and fuel. Substantially all of these derivatives meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. Other derivative contracts are recoverable through the PSCR mechanism when realized. This results in the deferral of unrealized gains and losses or regulatory assets or liabilities until realized.
Credit Risk
We are exposed to credit risk if customers or counterparties do not comply with their contractual obligations. We maintain credit policies that significantly minimize overall credit risk. These policies include an evaluation of potential customers’ and counterparties’ financial condition, credit rating, collateral requirements or other credit enhancements such as letters of credit or guarantees. We generally use standardized agreements that allow the netting of positive and negative transactions associated with a single counterparty.
The Company maintains a provision for credit losses based on factors surrounding the credit risk of its customers, historical trends, and other information. Based on the Company’s credit policies and its December 31, 2007 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to result in material effects on the Company’s financial statements.
Fair Value of Other Financial Instruments
The fair value of financial instruments is determined by using various market data and other valuation techniques. The table below shows the fair value relative to the carrying value for long-term debt securities. The carrying value of certain other financial instruments, such as notes payable, customer deposits and notes receivable approximate fair value and are not shown. As of December 31, 2007, the Company had approximately $1 billion of tax exempt securities insured by insurers. Since December 31, 2007, overall credit market conditions have resulted in credit rating downgrades and may result in future credit rating downgrades for these insurers. The Company does not expect the impact on interest rates or fair value to be material.
                 
  2007 2006
  Fair Value Carrying Value Fair Value Carrying Value
Long-Term Debt $4.8 billion $4.7 billion $5.0 billion $4.8 billion
NOTE 1316 — COMMITMENTS AND CONTINGENCIES
Environmental
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 MarchSince 2005, EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, Detroit Edison has spent approximately $1.1$1.5 billion through 2007.2009. The Company estimates Detroit Edison will make future undiscounted capital expenditures atof up to $282$73 million in 20082010 and up to $2.4$2.2 billion of additional capital expenditures through 20182019 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants (HAPs). It is not possible to satisfy bothquantify the existingimpact of those expected rulemakings at this time.
In July 2009, DTE Energy received a Notice of Violation/Finding of Violation (NOV/FOV) from the EPA alleging, among other things, that five Detroit Edison power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and proposed newTitle V operating permit requirements under the Clean Air Act. We believe that the plants identified by the EPA have complied with applicable regulations. Depending upon the outcome of our discussions with the EPA regarding the NOV/FOV, the EPA could bring legal action against Detroit Edison. We could also be required to install additional pollution control requirements.equipment at some or all of the power plants in question, engage in Supplemental Environmental Programs, and/or pay fines. We cannot predict the financial impact or outcome of this matter, or the timing of its resolution.

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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 thecompleted studies to be conducted over the next several years,and expected future studies, Detroit Edison may be required to install additional control technologies to reduce the impacts of the water intakes. Initially, it was estimated that Detroit Edison could incur up to approximately $55 million over the four to six years subsequent to 20072008 in additional capital expenditures to comply with these requirements. However, a recentJanuary 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation that may result in a delay in compliance dates. The decision also raised the possibility that Detroit Edison may have to install cooling towers at some facilities at a cost substantially greater than was initially estimated for other mitigative technologies. In 2008, the Supreme Court agreed to review the remanded cost-benefit analysis provision of the rule and in April 2009 upheld EPA’s use of this provision in determining best technology available for reducing environmental impacts. Concurrently, the EPA continues to

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develop a revised rule, a draft of which is expected to be published by summer 2010. The EPA has also proposed an information collection request to begin a review of steam electric effluent guidelines. It is not possible at this time to quantify the impacts of these developing requirements.
Contaminated Sites- Detroit Edison conducted remedial investigations at contaminated sites, including three former manufactured gas plant (MGP) sites. The investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites, including the area surrounding an ash landfill, electrical distribution substations, and several underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is approximately $15 million that was accrued in 2007 and is expected to be incurred over the next several years. In addition,At December 31, 2009 and 2008, the Company had $9 million and $12 million, respectively, accrued for remediation.
Landfill Detroit Edison expectsowns and operates a permitted engineered ash storage facility at the Monroe Power Plant to make approximately $6dispose of fly ash from the coal fired power plant. Detroit Edison performed an engineering analysis in 2009 and identified the need for embankment side slope repairs and reconstruction.
Nuclear Operations
Property Insurance
Detroit Edison maintains several different types of property insurance policies specifically for the Fermi 2 plant. These policies cover such items as replacement power and property damage. The Nuclear Electric Insurance Limited (NEIL) is the primary supplier of the insurance policies.
Detroit Edison maintains a policy for extra expenses, including replacement power costs necessitated by Fermi 2’s unavailability due to an insured event. This policy has a 12-week waiting period and provides an aggregate $490 million of capital improvementscoverage over a three-year period.
Detroit Edison has $500 million in primary coverage and $2.25 billion of excess coverage for stabilization, decontamination, debris removal, repair and/or replacement of property and decommissioning. The combined coverage limit for total property damage is $2.75 billion.
In 2007, the Terrorism Risk Insurance Extension Act of 2005 (TRIA) was extended through December 31, 2014. A major change in the extension is the inclusion of “domestic” acts of terrorism in the definition of covered or “certified” acts. For multiple terrorism losses caused by acts of terrorism not covered under the TRIA occurring within one year after the first loss from terrorism, the NEIL policies would make available to all insured entities up to $3.2 billion, plus any amounts recovered from reinsurance, government indemnity, or other sources to cover losses.
Under the NEIL policies, Detroit Edison could be liable for maximum assessments of up to approximately $28 million per event if the loss associated with any one event at any nuclear plant in the United States should exceed the accumulated funds available to NEIL.
Public Liability Insurance
As of January 1, 2010, as required by federal law, Detroit Edison maintains $375 million of public liability insurance for a nuclear incident. For liabilities arising from a terrorist act outside the scope of TRIA, the policy is subject to one industry aggregate limit of $300 million. Further, under the Price-Anderson Amendments Act of 2005, deferred premium charges up to $117.5 million could be levied against each licensed nuclear facility, but not more than $17.5 million per year per facility. Thus, deferred premium charges could be levied against all owners of licensed nuclear facilities in the event of a nuclear incident at any of these facilities.
Nuclear Fuel Disposal Costs
In accordance with the Federal Nuclear Waste Policy Act of 1982, Detroit Edison has a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. Detroit

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Edison is obligated to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold. The fee is a component of nuclear fuel expense. Delays have occurred in the DOE’s program for the acceptance and disposal of spent nuclear fuel at a permanent repository and the proposed fiscal year 2011 federal budget recommends termination of funding for completion of the government’s long-term storage facility. Detroit Edison is 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. Detroit Edison currently employs a spent nuclear fuel storage strategy utilizing a fuel pool. We have begun work on an on-site dry cask storage facility which is expected to provide sufficient storage capability for the life of the plant as defined by the original operating license. Issues relating to long-term waste disposal policy and to the ash landfilldisposition of funds contributed by Detroit Edison ratepayers to the federal waste fund await future governmental action.
Guarantees
In certain limited circumstances, the Company enters into contractual guarantees. The Company may guarantee another entity’s obligation in 2008.the event it fails to perform. The Company may provide guarantees in certain indemnification agreements. Finally, the Company may provide indirect guarantees for the indebtedness of others.
Detroit Edison has guaranteed a bank term loan of $11 million related to the sale of its steam heating business to Thermal Ventures II, L.P. In conjunction with a refinancing of the steam heating business in 2009, the Company performed a reconsideration analysis and determined the steam heating business entity to be a variable interest entity as a result of insufficient equity at risk. It was determined that the Company is not the primary beneficiary and historical accounting remains unchanged. At December 31, 2009, the Company has reserves for the entire amount of the bank loan guarantee.
Labor Contracts
There are several bargaining units for the Company’s union employees. The majority of our represented employees. In December 2007, a new three-year agreement was ratified by our represented employees.union employees are under contracts that expire in June 2010 and August 2012.
Purchase Commitments
Detroit Edison has an Energy Purchase Agreement to purchase steam and electricity from the Greater Detroit Resource Recovery Authority (GDRRA). Under the Agreement, Detroit Edison will purchase steam through 2008 and electricity through June 2024. In 1996, a charge to income was recorded that included a reserve for steam purchase commitments in excess of replacement costs from 1997 through 2008. The reserve for steam purchase commitments totaling $20 million at December 31, 2007 is being amortized to fuel, purchased power and gas expense with non-cash accretion expense being recorded through 2008. The Company estimates steam and electric purchase commitments from 2008 through 2024 will not exceed $343 million. In January 2003, the Company sold the steam heating business of Detroit Edison to Thermal Ventures II, LP. Under the terms of the sale, Detroit Edison remains contractually obligated to buy steam of $33 million from GDRRA until 2008. Also, the Company guaranteed bank loans of $13 million that Thermal Ventures II, LP may use for capital improvements to the steam heating system. During 2007, the Company recorded reserves of $13 million related to the bank loan guarantee.
As of December 31, 2007,2009, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments and energy trading contracts. The Company estimates that these commitments will be approximately $1.4$1.5 billion from 20082010 through 2024.2025. The Company also estimates that 20082010 capital expenditures will be approximately $1 billion.$940 million. The Company has made certain commitments in connection with expected capital expenditures. Certain of these commitments are with variable interest entities where the Company determined it was not the primary beneficiary as it does not have significant exposure to losses.
Bankruptcies
We purchaseThe Company purchases and sellsells electricity from and to numerous companies operating in the steel, automotive, energy, retail and other industries. Certain of ourits customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. WeThe Company regularly reviewreviews contingent matters relating to these customers and ourits purchase and sale contracts and we recordrecords provisions for amounts considered at risk of

51


probable loss. We believe our previouslyThe Company believes its accrued amounts are adequate for probable losses.loss. The final resolution of these matters is not expected tomay have a material effect on ourits consolidated financial statements.
The Company provides services to the domestic automotive industry, including GM, Ford Motor Company (Ford) and Chrysler and many of their vendors and suppliers. Chrysler filed for bankruptcy protection on April 30, 2009. We have reserved approximately $7 million of pre-petition accounts receivable related to Chrysler as of December 31, 2009. GM filed for bankruptcy protection on June 1, 2009. We have not reserved or written off any pre-petition accounts receivable related to GM as of December 31, 2009. Closing of GM or Chrysler plants or other facilities that operate within Detroit Edison’s service territory will also negatively impact the Company’s operating revenues in future periods. In 2009, GM and Chrysler each represented two percent of its annual electric sales volumes, respectively.

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Other
Detroit Edison wasThe Company is involved in a contract dispute with BNSF Railway Company (BNSF) that was referred to arbitration. Under this contract, BNSF transports western coals east for Detroit Edison. The Company filed a breach of contract claim against BNSF for the failure to provide certain services that the Company believed were required by the contract. The Company received an award from the arbitration panel in September 2007 that held that BNSF is required to provide such services under the contract and awarded damages to the Company. We have entered into a settlement agreement with BNSF pursuant to which BNSF will provide the required services.
We are aware of attempts by an environmental organization known as the Waterkeeper Alliance to initiate a criminal action in Canada against the Company for alleged violations of the Canadian Fisheries Act. Fines under the relevant Canadian statute could be significant. To date, the Company has not been served process in this matter and is not able to predict or assess the outcome of this action at this time.
We are involved in certainother legal, regulatory, administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning claims arising in the ordinary course of business. These proceedings include certain contract disputes, additional environmental reviews and investigations, audits, inquiries from various regulators, and pending judicial matters. WeThe Company cannot predict the final disposition of such proceedings. WeThe Company regularly reviewreviews legal matters and recordrecords provisions for claims that are considered probable of loss. The resolution of pending proceedings is not expected to have a material effect on ourthe Company’s operations or financial statements in the periodperiods they are resolved.
See Note 410 for a discussion of contingencies related to Regulatory Matters.
NOTE 1417 — RETIREMENT BENEFITS AND TRUSTEED ASSETS
Adoption of SFAS No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement PlansMeasurement Date
In September 2006,2008, the FASB issued SFAS No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an AmendmentCompany changed the measurement date of FASB Statements No. 87, 88, 106, and 132(R). SFAS No.158 requires companies to (1) recognize the over funded or under funded status of defined benefitits pension and 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 asplans from November 30 to December 31. As a result, the Company recognized an adjustment of the date of the employer’s statement of financial position, and (5) disclose additional information in the notes$15 million ($9 million after-tax) 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 postretirement benefit plan and the related disclosure requirements is effective for fiscal years ending after December 15, 2006. The Company adopted this requirement as of December 31, 2006. 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 Company plans to adopt this requirement as of December 31, 2008. Retrospective application of the changes required by SFAS No. 158 is prohibited; therefore certain disclosures below are not comparable.

52


Detroit Edison received approval from the MPSC to record the charge related to the additional liability as a Regulatory asset since the traditional rate setting process allows for the recoveryretained earnings, which represents approximately one month of pension and other postretirement plan costs.
Measurement Date
benefit costs for the period from December 1, 2007 to December 31, 2008. All amounts and balances reported in the following tables as of December 31, 20072009 and December 31, 20062008 are based on measurement dates of November 30, 2007December 31, 2009 and November 30, 2006,December 31, 2008, respectively.
Qualified and Nonqualified Pension Plan Benefits
We have a definedDetroit Edison participates in various plans that provide pension and other postretirement benefits for DTE Energy and its affiliates. Detroit Edison is allocated net periodic benefit retirement plan. The plan is noncontributory and covers substantially all employees. The plan provides traditional retirement benefits based oncosts for its share of the employees’amounts of the combined plans. In prior years, of benefit service, average final compensation and age at retirement. In addition, certain non-represented employees are covered under cash balance provisions that base benefits on annual employer contributions and interest credits. We operateDetroit Edison served as the plan sponsor of thefor a pension plan which is treated asthat changed in 2008 to be sponsored by DTE Energy Corporate Services, LLC, (LLC) a plan covering employees of various affiliatessubsidiary of DTE Energy fromEnergy. The change in plan sponsorship did not change the affiliates’ perspective. pension cost or contributions allocated to Detroit Edison, or the benefits of plan participants.
The annual expense disclosed below is our portion of the total plan expense. Each affiliate is charged their portion of the expense.
OurCompany’s policy is to fund pension costs by contributing amounts consistent with the Pension Protection Act of 2006 provisions and additional amounts we deem appropriate. In December 2007, we contributed $150 million to the qualified pension plans. We anticipateThe Company anticipates making up to a $150$200 million contribution to our qualifiedthe pension plans in 2008 and a $5 million contribution to our nonqualified pension plans in 2008.
We also maintain supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees. These plans provide for benefits that supplement those provided by Detroit Edison’s other retirement plans.2010.
Net pension cost includes the following components:
                                    
 Qualified Pension Plans Nonqualified Pension Plans  Pension Plans 
(in Millions) 2007 2006 2005 2007 2006 2005  2009 2008 2007 
Service cost $49 $49 $53 $2 $2 $1  $43 $45 $51 
Interest cost 135 133 130 3 3 2  158 148 138 
Expected return on plan assets  (148)  (135)  (135)      (165)  (163)  (148)
Amortization of:  
Net income 44 44 50 2 1 1 
Net actuarial loss 38 27 46 
Prior service cost 6 8 9     7 5 6 
Special termination benefits 8 38        8 
                    
Net pension cost $94 $137 $107 $7 $6 $4  $81 $62 $101 
                    
Special termination benefits in the above tables represent costs associated with our Performance Excellence Process.
         
  Pension Plans 
(in Millions) 2009  2008 
Other changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets
        
Net actuarial loss $177  $665 
Amortization of net actuarial loss  (38)  (27)
Prior service cost     12 
Amortization of prior service cost  (7)  (6)
       
Total recognized in other comprehensive income and regulatory assets $132  $644 

5354


Retrospective application of the changes required by SFAS No. 158 is prohibited; therefore certain disclosures below are not comparable.
                 
  Qualified Pension Plans  Nonqualified Pension Plans 
(in Millions) 2007  2006  2007  2006 
Other changes in plan assets and benefit obligations recognized in regulatory assets
                
Net actuarial (gain)/ loss $(188) $N/A  $1  $N/A 
Amortization of net actuarial (gain)  (44)  N/A   (1)  N/A 
Prior service cost  1   N/A      N/A 
Amortization of prior service (credit)  (6)  N/A   (1)  N/A 
             
Total recognized in regulatory assets $(237) $N/A  $(1) $N/A 
             
                 
Total recognized in net periodic pension cost and regulatory assets $(143) $N/A  $6  $N/A 
             
                 
Estimated amounts to be amortized from regulatory assets into net periodic benefit cost during next fiscal year
                
Net actuarial loss $26  $44  $1  $1 
Prior service cost $6  $6  $  $1 
The above table represents disclosure required of SFAS No. 158 beginning in 2007.
         
  Pension Plans 
(in Millions) 2009  2008 
       
Total recognized in net periodic pension cost and other comprehensive income and regulatory assets $213  $707 
Estimated amounts to be amortized from accumulated other comprehensive income and regulatory assets into net periodic benefit cost during next fiscal year        
Net actuarial loss $70  $37 
Prior service cost  5   7 
The following table reconciles the obligations, assets and funded status of the plan as well as the amount recognized as pension liability in the consolidated statementConsolidated Statements of financial positionFinancial Position at December 31. The resultsDuring 2008, the sponsor of a pension plan changed from Detroit Edison to the LLC. As a result, as of December 31, 2009 and 2008, the tables below include liabilitiesassets and obligations for Detroit Edison only. At the beginning of 2008, as Detroit Edison was the pension plan sponsor, the tables below included assets and obligations for Detroit Edison and all affiliates participating in the combined plan. The prepaid asset contributed to the combined plan by such affiliates is reflected as an amount due to affiliates of $325 million and $295 million at December 31, 2007 and 2006, respectively.
                        
 Qualified Pension Plans Nonqualified Pension Plans  Pension Plans 
 2007 2006 2007 2006 
(in Millions) 2009 2008 
Accumulated benefit obligation, end of year
 $2,519 $2,668 $48 $46  $2,490 $2,206 
              
  
Change in projected benefit obligation
 
Projected benefit obligation, beginning of year $2,872 $2,738 $48 $41 
Change in projected benefit obligation Projected benefit obligation, beginning of year $2,368 $2,754 
Adjustment due to plan sponsorship change   (385)
December 2007 benefit payments   (15)
Service cost 53 55 2 2  43 45 
Interest cost 159 156 3 3  158 149 
Actuarial loss/ (gain)  (189) 66  5 
Actuarial (gain) loss 264  (53)
Benefits paid  (200)  (180)  (3)  (3)  (156)  (156)
Measurement date change  16 
Plan amendments 1  (6)     13 
Special termination benefits 8 43   
              
Projected benefit obligation, end of year $2,704 $2,872 $50 $48  $2,677 $2,368 
              
  
Change in plan assets
  
Plan assets at fair value, beginning of year $2,373 $2,273 $ $  $1,387 $2,599 
Adjustment due to plan sponsorship change   (752)
December 2007 contributions  150 
December 2007 payments   (15)
Actual return on plan assets 246 280    252  (557)
Company contributions 180  3 3  204 104 
Measurement date change  14 
Benefits paid  (200)  (180)  (3)  (3)  (156)  (156)
              
 
Plan assets at fair value, end of year $1,687 $1,387 
     
Funded status, end of year $(990) $(981)
     
 
Amount recorded as: 
Current liabilities $(3) $(3)
Noncurrent liabilities  (987)  (978)
     
 $(990) $(981)
     
 
Amounts recognized in regulatory assets (see Note 10)
 
Net actuarial loss $1,241 $1,106 
Prior service cost 20 27 
     
Regulatory assets $1,261 $1,133 
     

5455


                 
  Qualified Pension Plans  Nonqualified Pension Plans 
  2007  2006  2007  2006 
Plan assets at fair value, end of year $2,599  $2,373  $  $ 
             
Funded status of the plans, November 30 $(105) $(499) $(50) $(48)
December contribution  150   180       
             
Funded status, December 31 $45  $(319) $(50) $(48)
             
Noncurrent assets $372  $  $  $ 
Current liabilities        (3)  (3)
Noncurrent liabilities  (327)  (319)  (47)  (45)
             
  $45  $(319) $(50) $(48)
             
                 
Amounts recognized in regulatory assets
                
Net actuarial loss $436  $706  $18  $18 
Prior service cost $14  $20  $1  $2 
Assumptions used in determining the projected benefit obligation and net pension costs are listed below:
                        
 2007 2006 2005 2009 2008 2007
Projected benefit obligation
  
Discount rate  6.50%  5.70%  5.90%  5.90%  6.90%  6.50%
Rate of compensation increase  4.00%  4.00%  4.00%  4.00%  4.00%  4.00%
  
Net pension costs
  
Discount rate  5.70%  5.90%  6.00%  6.90%  6.50%  5.70%
Rate of compensation increase  4.00%  4.00%  4.00%  4.00%  4.00%  4.00%
Expected long-term rate of return on Plan assets  8.75%  8.75%  9.00%
Expected long-term rate of return on plan assets  8.75%  8.75%  8.75%
At December 31, 2007,2009, the benefits related to ourthe Company’s qualified and nonqualified pension plans expected to be paid in each of the next five years and in the aggregate for the five fiscal years thereafter are as follows:
        
(in Millions) (in Millions) 
2008 $173 
2009 178 
2010 183  $161 
2011 187  165 
2012 195  169 
2013 - 2017 1,086 
2013 175 
2014 180 
2015 - 2019 993 
      
Total $2,002  $1,843 
      
We employThe Company employs a consistent formal process in determining the long-term rate of return for various asset classes. We reviewManagement reviews historic financial market risks and returns and long-term historic relationships between the asset classes of equities, fixed income and other assets, consistent with the widely accepted capital market principle that asset classes with higher volatility generate a greater return over the long-term. Current market factors such as inflation, interest rates, asset class risks and asset class returns are evaluated and considered before long-term capital market assumptions are determined. The long-term portfolio return is also established employing a consistent formal process, with due consideration of diversification, active investment management and rebalancing. Peer data is reviewed to check for reasonableness.

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We employThe Company employs a total return investment approach whereby a mix of equities, fixed income and other investments are used to maximize the long-term return on plan assets consistent with prudent levels of risk.risk, with consideration given to the liquidity needs of the plan. The intent of this strategy is to minimize plan expenses over the long-term. Risk tolerance is established through consideration of future plan cash flows, plan funded status, and corporate financial considerations. The investment portfolio contains a diversified blend of equity, fixed income and other investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, growth and value investment styles, and large and small market capitalizations. Fixed income securities generally include corporate bonds of companies from diversified industries, mortgage-backed securities, and U.S. Treasuries. Other assets such as private equity and absolute returnhedge funds are used judiciously to enhance long termlong-term returns while improving portfolio diversification. Derivatives may be utilized in a risk controlled manner, to potentially increase the portfolio beyond the market value of invested assets and reduce portfolio investment risk. Investment risk is measured and monitored on an ongoing basis through annual liability measurements, periodic asset/liability studies, and quarterly investment portfolio reviews.

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Our plans’ weighted-average asset
Target allocations for plan assets as of December 31, 2009 are listed below:
U.S. Large Cap Equity Securities25%
U.S. Small Cap and Mid Cap Equity Securities6
Non U.S. Equity Securities14
Fixed Income Securities26
Hedge Funds and Similar Investments20
Private Equity and Other6
Short-Term Investments3
100%
The fair values of the Company’s plans assets at December 31, 2009, by asset category at December 31 wereare as follows:
             
  2007 2006 Target
Equity securities  66%  68%  55%
Debt securities  19   23   20 
Other  15   9   25 
             
   100%  100%  100%
             
Fair Value Measurements at
WeDecember 31, 2009
                 
              Balance at 
(in Millions)(a) Level 1  Level 2  Level 3  December 31, 2009 
Asset Category:
                
Short-term investments (b) $  $42  $  $42 
Equity securities                
U.S. Large Cap(c)  436   20      456 
U.S. Small/Mid Cap(d)  101   2      103 
Non U.S(e)  153   79      232 
Fixed income securities(f)  31   397      428 
Other types of investments                
Hedge Funds and Similar Investments(g)        320   320 
Private Equity and Other(h)        106   106 
             
Total $721  $540  $426  $1,687 
             
(a)See Note 4 — Fair Value for a description of levels within the fair value hierarchy.
(b)This category predominantly represents certain short-term fixed income securities and money market investments that are managed in separate accounts or commingled funds. Pricing for investments in this category are obtained from quoted prices in actively traded markets or valuations from brokers or pricing services.
(c)This category comprises both actively and not actively managed portfolios that track the S&P 500 low cost equity index funds. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.
(d)This category represents portfolios of small and medium mid capitalization domestic equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.
(e)This category primarily consists of portfolios of non-U.S. developed and emerging market equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.
(f)This category includes corporate bonds from diversified industries, U.S. Treasuries, and mortgage backed securities. Pricing for investments in this category is obtained from quoted prices in actively traded markets and quotations from broker or pricing services. Non-exchange traded securities and exchange-traded securities held in commingled funds are classified as Level 2 assets.
(g)This category includes a diversified group of funds and strategies that attempt to capture financial market inefficiencies. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available pricing. Valuations for assets in this category may be based on relative publicly-traded securities, derivatives, and privately-traded securities.
(h)This category includes a diversified group of funds and strategies that primarily invests in private equity partnerships. This category also includes investments in timber and private mezzanine debt. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available

57


pricing. Valuations for assets in this category may be based on discounted cash flow analyses, relative publicly-traded comparables and comparable transactions.
The pension trust holds debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices in actively traded markets. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued based on underlying securities, using quoted prices in actively traded markets. Non-exchange traded fixed income securities are valued by the trustee based upon quotations available from brokers or pricing services. A primary price source is identified by asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustees challenge an assigned price and determine that another price source is considered to be preferable. Detroit Edison has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Detroit Edison selectively corroborates the fair values of securities by comparison of market-based price sources.
Fair Value Measurements Using Significant Unobservable Inputs (Level 3):
             
  Hedge Funds       
  and Similar  Private Equity    
(in Millions) Investments  and Other  Total 
Beginning Balance at January 1, 2009 $310  $105  $415 
Total realized/unrealized gains (losses)  20   (7)  13 
Purchases, sales and settlements  (10)  8   (2)
          
Ending Balance at December 31, 2009 $320  $106  $426 
          
             
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period $23  $(7) $16 
          
The Company also sponsorsponsors defined contribution retirement savings plans. Participation in one of these plans is available to substantially all represented and non-represented employees. We matchThe Company matches employee contributions up to certain predefined limits based upon eligible compensation and the employee’s contribution rate. The cost of these plans was $16 million in 2009, $16 million in 2008, and $17 million in 2007, $23 million in 2006, and $23 million in 2005.2007.
Other Postretirement Benefits
WeThe Company participates in plans sponsored by LLC that provide certain postretirement health care and life insurance benefits for employees who are eligible for these benefits. OurThe Company’s policy is to fund certain trusts to meet our postretirement benefit obligations. Separate qualified Voluntary Employees Beneficiary Association (VEBA) trusts exist for represented and non-represented employees. In 2007 and January 2008, we made cash contributions of $76 million and $40 million, respectively, to our postretirement benefit plans. At the discretion of management, wesubject to MPSC requirements, the Company may make up to a $76$90 million contribution to ourthe VEBA trusts in 2008. We recorded $2 million postretirement benefit cost associated with our Performance Excellence Process in 2007.2010.
Net postretirement cost includes the following components:
                        
(in Millions) 2007 2006 2005  2009 2008 2007 
Service cost $48 $45 $44  $45 $48 $48 
Interest cost 90 88 80  102 94 90 
Expected return on plan assets  (54)  (49)  (58)  (42)  (58)  (54)
Amortization of:  
Net loss 51 53 44  53 27 51 
Prior service costs 4 4 3  2 2 4 
Net transition obligation 7 7 7  2 2 7 
Special termination benefits 2 6     2 
              
Net postretirement cost $148 $154 $120  $162 $115 $148 
              

5658


Special termination benefits in the above tables represent costs associated with our Performance
Excellence Process.
Retrospective application of the changes required by SFAS No. 158 is prohibited; therefore certain disclosures below are not comparable.
         
(in Millions) 2009  2008 
Other changes in plan assets and APBO recognized in regulatory assets
        
Net actuarial (gain) loss $(38) $237 
Amortization of net actuarial loss  (52)  (28)
Prior service (credit)     (1)
Amortization of prior service cost  (2)  (2)
Amortization of transition (asset)  (2)  (2)
       
Total recognized in regulatory assets $(94) $204 
       
         
Total recognized in net periodic pension cost and regulatory assets $68  $319 
       
         
(in Millions) 2007  2006 
Other changes in plan assets and APBO recognized in regulatory assets
        
Net actuarial (gain) $(216) $N/A 
Amortization of net actuarial (gain)  (51)  N/A 
Prior service (credit)  (39)  N/A 
Amortization of prior service cost  (4)  N/A 
Amortization of transition (asset)  (7)  N/A 
       
Total recognized in regulatory assets $(317) $N/A 
       
         
Total recognized in net periodic pension cost and regulatory assets $(169) $N/A 
       
         
Estimated amounts to be amortized from regulatory assets into net periodic benefit cost during next fiscal year
        
Net actuarial loss $27  $50 
Prior service cost $2  $4 
Net transition obligation $2  $6 
         
(in Millions)        
Estimated amounts to be amortized from regulatory assets into net periodic benefit cost during next fiscal year
        
Net actuarial loss $38  $49 
Prior service cost  2   2 
Net transition obligation  2   2 

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The above table represents disclosure required of SFAS No. 158 beginning in 2007.
The following table reconciles the obligations, assets and funded status of the plans including amounts recorded as accrued postretirement cost in the consolidated statementConsolidated Statements of financial positionFinancial Position at December 31:
         
(in Millions) 2007  2006 
Change in accumulated post retirement benefit obligation during the year
        
Accumulated postretirement benefit obligation, beginning of year $1,660  $1,525 
Service cost  48   45 
Interest cost  90   88 
Plan amendments  (39)  2 
Actuarial (gain)/ loss  (214)  63 
Benefits paid  (73)  (70)
Special termination benefits  2   6 
Medicare Part D  5   1 
       
Accumulated postretirement benefit obligation , end of year $1,479  $1,660 
       
         
Change in plan assets during the year
        
Plan assets at fair value, beginning of year $636  $581 
Actual return on plan assets  56   70 
Company contributions  36   40 
Benefits paid  (70)  (55)
       
Plan assets at fair value, end of year $658  $636 
       

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(in Millions) 2007 2006  2009 2008 
Funded status of the Plans, as of November 30 $(821) $(1,024)
December adjustment 5  (31)
Change in accumulated post retirement benefit obligation during the year
 
Accumulated postretirement benefit obligation, beginning of year $1,553 $1,479 
December 2007 cash flow   (4)
Service cost 45 48 
Interest cost 102 94 
Plan amendments   (1)
Actuarial (gain)/loss 21  (7)
Measurement date change  11 
Benefits paid  (75)  (72)
Medicare Part D 4 5 
     
Accumulated postretirement benefit obligation , end of year $1,650 $1,553 
     
 
Change in plan assets during the year
 
Plan assets at fair value, beginning of year $478 $658 
December 2007 cash flow  1 
Actual return on plan assets 99  (189)
Measurement date change  5 
Company contributions 90 76 
Benefits paid  (75)  (73)
     
Plan assets at fair value, end of year $592 $478 
     
 
      
Funded status, as of December 31 $(816) $(1,055) $(1,058) $(1,075)
          
 
Non-current liabilities $(816) $(1,055) $(1,058) $(1,075)
Amounts Recognized in Regulatory Assets 
     
 
Amounts recognized in regulatory assets (see Note 10)
 
Net actuarial loss $391 $659  $510 $600 
Prior service cost $3 $24   (2)  
Net transition obligation $11 $40  7 9 
     
 $515 $609 
     
Assumptions used in determining the projected benefit obligation and net benefit costs are listed below:
                        
 2007 2006 2005 2009 2008 2007 
Projected Benefit Obligation
  
Discount rate  6.50%  5.70%  5.90%  5.90%  6.90%  6.50%
  
Net Benefit Costs
  
Discount rate  5.70%  5.90%  6.00%  6.90%  6.50%  5.70%
Expected long-term rate of return on Plan assets  8.75%  8.75%  9.00%  8.75%  8.75%  8.75%
Health care trend rate pre-65  8.00%  9.00%  9.00%  7.00%  7.00%  8.00%
Health care trend rate post-65  7.00%  8.00%  8.00%  7.00%  6.00%  7.00%
Ultimate health care trend rate  5.00%  5.00%  5.00%  5.00%  5.00%  5.00%
Year in which ultimate reached 2011 2011 2011  2016 2011 2011 
A one-percentage-point increase in health care cost trend rates would have increased the total service cost and interest cost components of benefit costs by $22$24 million and increased the accumulated benefit obligation by $183$217 million at December 31, 2007.2009. A one-percentage-point decrease in the health care cost trend rates would have decreased the total service and interest cost components of benefit costs by $18$20 million and would have decreased the accumulated benefit obligation by $156$185 million at December 31, 2007.2009.

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At December 31, 2007,2009, the benefits expected to be paid, including prescription drug benefits, in each of the next five years and in the aggregate for the five fiscal years thereafter are as follows:
     
(in Millions)    
2008 $91 
2009  98 
2010  103 
2011  107 
2012  111 
2013 - 2017  599 
    
Total $1,109 
    
The process used in determining the long-term rate of return for assets and the investment approach for our other postretirement benefits plans is similar to those previously described for our qualified pension plans.

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Our plans’ weighted-average asset allocations and related targets by asset category at December 31 were as follows:
             
  2007 2006 Target
Equity securities  68%  68%  55%
Debt securities  20   25   20 
Other  12   7   25 
             
   100%  100%  100%
             
     
(in Millions)   
2010 $92 
2011  97 
2012  100 
2013  104 
2014  108 
2015 - 2019  611 
    
Total $1,112 
    
In December 2003, the Medicare Act was signed into law which provides for a non-taxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least “actuarially equivalent” to the benefit established by law. The effects of the subsidy reduced net periodic postretirement benefit costs by $17 million in 2009, $11 million in 2008 and $12 million in 2007, $16 million in 2006 and $15 million in 2005.2007.
At December 31, 2007,2009, the gross amount of federal subsidies expected to be received in each of the next five years and in the aggregate for the five fiscal years thereafter was as follows:
        
(in Millions) (in Millions) 
2008 $4 
2009 4 
2010 4  $5 
2011 4  6 
2012 5  6 
2013 - 2017 26 
2013 6 
2014 7 
2015 - 2019 39 
      
Total $47  $69 
      
The process used in determining the long-term rate of return for assets and the investment approach for the other postretirement benefits plans is similar to those previously described for the pension plans.
Target allocations for plan assets as of December 31, 2009 are listed below:
U.S. Large Cap Equity Securities20%
U.S. Small Cap and Mid Cap Equity Securities5
Non U.S. Equity Securities20
Fixed Income Securities25
Hedge Funds and Similar Investments20
Private Equity and Other10
Short-Term Investments0
100%
The fair values of the Company’s plan assets at December 31, 2009, by asset category are as follows:
Fair Value Measurements at
December 31, 2009
                 
              Balance at 
(in Millions)(a) Level 1  Level 2  Level 3  December 31, 2009 
Asset Category:
                
Short-term investments(b) $  $12  $  $12 
Equity securities                
U.S. Large Cap(c)  102   55      157 
U.S. Small/Mid Cap(d)  32   34      66 
Non U.S(e)  50   47      97 
Fixed income securities(f)  5   160      165 
Other types of investments                
Hedge Funds and Similar Investments(g)        63   63 
Private Equity and Other(h)        32   32 
             
Total $189  $308  $95  $592 
             
(a)See Note 4 — Fair Value for a description of levels within the fair value hierarchy.

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(b)This category predominantly represents certain short-term fixed income securities and money market investments that are managed in separate accounts or commingled funds. Pricing for investments in this category are obtained from quoted prices in actively traded markets or valuations from brokers or pricing services.
(c)This category comprises both actively and not actively managed portfolios that track the S&P 500 low cost equity index funds. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.
(d)This category represents portfolios of small and medium mid capitalization domestic equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.
(e)This category primarily consists of portfolios of non-U.S. developed and emerging market equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.
(f)This category includes corporate bonds from diversified industries, U.S. Treasuries, and mortgage backed securities. Pricing for investments in this category is obtained from quoted prices in actively traded markets and quotations from broker or pricing services. Non-exchange traded securities and exchange-traded securities held in commingled funds are classified as Level 2 assets.
(g)This category includes a diversified group of funds and strategies that attempt to capture financial market inefficiencies. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available pricing. Valuations for assets in this category may be based on relative publicly-traded securities, derivatives, and privately-traded securities.
(h)This category includes a diversified group of funds and strategies that primarily invests in private equity partnerships. This category also includes investments in timber and private mezzanine debt. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available pricing. Valuations for assets in this category may be based on discounted cash flow analyses, relative publicly-traded comparables and comparable transactions.
The VEBA trusts hold debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices in actively traded markets. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued based on underlying securities, using quoted prices in actively traded markets. Non-exchange traded fixed income securities are valued by the trustee based upon quotations available from brokers or pricing services. A primary price source is identified by asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustees challenge an assigned price and determine that another price source is considered to be preferable. Detroit Edison has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Detroit Edison selectively corroborates the fair values of securities by comparison of market-based price sources.
Fair Value Measurements Using Significant Unobservable Inputs (Level 3):
             
  HedgeFunds Similar  Private Equityand   
(in Millions) Investments  Other  Total 
Beginning Balance at January 1, 2009 $52  $26  $78 
Total realized/unrealized gains (losses)  4   3   7 
Purchases, sales and settlements  7   3   10 
          
Ending Balance at December 31, 2009 $63  $32  $95 
          
             
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period $4  $2  $6 
          

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NOTE 1518 — SUPPLEMENTAL CASH FLOW INFORMATION
A detailed analysis of the changes in assets and liabilities that are reported in the Consolidated Statements of Cash Flows follows:
             
(in Millions) 2009  2008  2007 
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
            
Accounts receivable, net $16  $72  $(163)
Inventories  30   (24)  (47)
Recoverable pension and postretirement costs  (13)  (852)  594 
Accrued pension liability — affiliates  9   598   (330)
Accounts payable  (56)  (82)  73 
Accrued power supply cost recovery revenue  7   82   41 
Accrued payroll  2   3   (50)
Income taxes payable  (109)  (29)  10 
General taxes     (12)  4 
Risk management and trading activities  8   1   (4)
Accrued postretirement liability — affiliates  (17)  259   (239)
Other assets  (26)  3   (387)
Other liabilities  110   99   285 
          
  $(39) $118  $(213)
          
Supplementary cash and non-cash information for the years ended December 31 were as follows:
             
(in Millions) 2009  2008  2007 
Cash Paid For            
Interest (excluding interest capitalized) $328  $290  $295 
Income taxes  319   24   280 

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NOTE 19 — RELATED PARTY TRANSACTIONS
We haveThe Company has agreements with affiliated companies to sell energy for resale, purchase power, provide fuel supply services, and provide power plant operation and maintenance services. We have an agreementThe Company has agreements with certain DTE Energy affiliates where we charge them for their use of the shared capital assets of the Company. Prior to March 31, 2007, under a service agreement with DTE Energy, various DTE Energy affiliates, including Detroit Edison, provideprovided corporate support services inclusive of various financial, auditing, tax, legal, treasury and cash management, human resources, information technology, and regulatory services, which were billed to DTE Energy corporate. Subsequent to March 31, 2007, a newly formed shared service company began to accumulate the aforementioned corporate support services type expenses, which previously had been recorded on the various operating units of DTE Energy Company, including Detroit Edison. These administrative and general expenses incurred by the shared services company were then charged to various subsidiaries of DTE Energy, including Detroit Edison.

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The following is a summary of transactions with affiliated companies:
                        
(in Millions) 2007 2006 2005 2009 2008 2007 
Revenues
  
Energy sales $ $46 $192  $1 $ $ 
Other services 5 5 5  4 6 5 
Shared capital assets 21 13 14  28 23 21 
Costs
  
Power purchases 3 35 102 
Fuel and power purchases 3 5 3 
Other services and interest 6 3 7  3 7 6 
Corporate expenses (net) 331  (86)  (97) 313 388 331 
Other
  
Dividends declared 305 305 305  305 228 305 
Dividends paid 305 305 305  305 305 305 
Capital contribution 175 150   250 175 175 
                
 December 31, December 31, 
(in Millions) 2007 2006 2009 2008 
Assets
  
Accounts receivable $3 $19  $3 $5 
Notes receivable 82 41 
Liabilities & Equity
  
Accounts payable 138 84  74 103 
Short-term borrowings 277  
Other liabilities ( pension obligations) 327 295 
Dividends payable 76 76 
Other liabilities 
Accrued pension liability 987 978 
Accrued postretirement liability 1,058 1,075 
Our accounts receivable from affiliated companies and accounts payable to affiliated companies are payable upon demand and are generally settled in cash within a monthly business cycle.
NOTE 1620 — SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
                                        
 First Second Third Fourth   First Second Third Fourth   
(in Millions) Quarter Quarter Quarter Quarter(1) Year Quarter Quarter Quarter(1) Quarter Year 
2007
 
2009
 
Operating Revenues $1,094 $1,210 $1,403 $1,193 $4,900  $1,118 $1,108 $1,289 $1,199 $4,714 
Operating Income 131 162 227 223 743  214 189 318 178 899 
Net Income 40 60 107 110 317  78 79 149 70 376 
  
2006 
2008 
Operating Revenues 1,050 1,175 1,460 1,052 4,737  1,153 1,173 1,440 1,108 4,874 
Operating Income 161 164 270 181 776  139 151 316 194 800 
Net Income 59 57 138 67 321  41 51 159 80 331 

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(1) InThe 2009 Third Quarter results were adjusted for the fourth quartereffect of 2007,the January 2010 Detroit Edison recordedMPSC rate order that required the refund of a portion of the self implemented rate increase effective on July 26, 2009. The adjustments that increased operating income by $27resulted in a reduction of Operating Revenues of $11 million, ($18Operating Income of $11 million after-tax) to correct prior amounts. These adjustments were primarily to record property, plant and equipment and deferred CTA costs for expenditures that had been expensed in earlier quartersNet Income of 2007, including $14 million ($9 million after-tax) expensed in the second quarter of 2007.$7 million.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.Controls and Procedures
See Item 8. Financial Statements and Supplementary Data for management’s evaluation of disclosure controls and procedures, its report on internal control over financial reporting, and its conclusion on changes in internal control over financial reporting.
Item 9B.   Other Information Other Information
None.
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
All omitted per General Instruction I (2) (c) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Item 14. Principal Accountant Fees and Services
For the yearsyear ended December 31, 2007 and 2006,2009 professional services were performed by PricewaterhouseCoopers LLP (PwC). For the year ended December 31, 2008, professional services were performed by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, “Deloitte”). The following table presents fees for professional services rendered by PwC and Deloitte for the audit of Detroit Edison’s annual financial statements for the years ended December 31, 20072009 and December 31, 2006,2008, respectively, and fees billed for other services rendered by PwC and Deloitte during those periods.
                
 2007 2006  2009 2008 
Audit fees (1) $1,275,216 $1,652,619  $1,231,865 $1,466,413 
Audit-related fees (3)(2) 6,179 35,750  37,400 45,500 
          
Total $1,281,395 $1,688,369  $1,269,265 $1,511,913 
          
 
(1) Represents the aggregrateaggregate fees for the audits of Detroit Edison’s annual financial statements

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and for the reviews of the financial statements included in Detroit Edison’s Quarterly Reports on Form 10-Q. 2006 fees include procedures performed to audit internal control over financial reporting of consolidated DTE Energy. Such fees in 2007 were incurred by DTE Energy and indirectly allocated to Detroit Edison through overheads.
 
(2) Represents the aggregrateaggregate fees billed for audit-related services. The fees above exclude certain fees charged to DTE Energy that are indirectly allocated to Detroit Edison through overheads.
The above listed fees were pre-approved by the DTE Energy audit committee. Prior to engagement, the DTE Energy audit committee pre-approves these services by category of service. The DTE Energy audit committee may delegate to the chair of the audit committee, or to one or more other designated members of the audit committee, the authority to grant pre-approvals of all permitted services or classes of these permitted services to be provided by the independent auditor up to but not exceeding a pre-defined limit. The decision of the designated member to pre-approve a permitted service will be reported to the DTE Energy audit committee at the next scheduled meeting.

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Part IV
Item 15. Exhibits and Financial Statement Schedules
(a) The following documents are filed as part of this Annual Report on Form 10-K.
 (1) Consolidated financial statements. See “Item 8 Financial Statements and Supplementary Data.”
 
 (2) Financial statement schedule. See “Item 8 Financial Statements and Supplementary Data.”
 
 (3) Exhibits.
 (i) Exhibits filed herewith.
   
12-284-267Supplemental Indenture, dated as of November 1, 2009 to the Mortgage and Deed of Trust dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company N.A., as successor trustee (2009 Series CT).
4-268Thirtieth Supplemental Indenture, dated as of November 1, 2009 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (2009 Series CT Variable Rate Senior Notes due 2024).
12-36 Computation of Ratio of Earnings to Fixed Charges.
   
23-2023-22Consent of PricewaterhouseCoopers LLP.
23-23 Consent of Deloitte & Touche LLP.
   
31-3731-53 Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report.
   
31-3831-54 Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report.
 (ii) Exhibits incorporated herein by reference.
   
3(a) Restated Articles of Incorporation of The Detroit Edison Company, as filed December 10, 1991. (Exhibit 3-13 to Form 10-Q for the quarter ended June 30, 1999).
   
3(b) Bylaws of The Detroit Edison Company, as amended through September 22, 1999. (Exhibit 3-14 to Form 10-Q for the quarter ended September 30, 1999).
   
4(a) Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit B-1 to Registration Statement on Form A-2 (File No. 2-1630)) and indentures supplemental thereto, dated as of dates indicated

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below, and filed as exhibits to the filings set forth below:
   
  Supplemental Indenture, dated as of December 1, 1940, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit B-14 to Registration Statement on Form A-2 (File No. 2-4609)). (amendment)
   
  Supplemental Indenture, dated as of September 1, 1947, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit B-20 to Registration Statement on Form S-1 (File No. 2-7136)). (amendment)
   
  Supplemental Indenture, dated as of March 1, 1950, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust

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Company, National Association,N.A., as successor trustee (Exhibit B-22 to Registration Statement on Form S-1 (File No. 2-8290)). (amendment)
   
  Supplemental Indenture, dated as of November 15, 1951, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit B-23 to Registration Statement on Form S-1 (File No. 2-9226)). (amendment)
   
  Supplemental Indenture, dated as of August 15, 1957, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 3-B-30 to Form 8-K dated September 11, 1957). (amendment)
   
  Supplemental Indenture, dated as of December 1, 1966, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 2-B-32 to Registration Statement on Form S-9 (File No. 2-25664)). (amendment)
   
  Supplemental Indenture, dated as of February 15, 1990, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-212 to Form 10-K for the year ended December 31, 2000). (1990 Series B, C, E and F)
Supplemental Indenture, dated as of April 1, 1991, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-15 to Form 10-K for the year ended December 31, 1995). (1991 Series AP)
Supplemental Indenture, dated as of May 1, 1991, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee

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(Exhibit (Exhibit 4-178 to Form 10-K for the year ended December 31, 1996). (1991 Series BP and CP)
   
  Supplemental Indenture, dated as of May 15, 1991, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-179 to Form 10-K for the year ended December 31, 1996). (1991 Series DP)
   
  Supplemental Indenture, dated as of February 29, 1992, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-187 to Form 10-Q for the quarter ended March 31, 1998). (1992 Series AP)
   
  Supplemental Indenture, dated as of April 26, 1993, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-215 to Form 10-K for the year ended December 31, 2000). (amendment)
Supplemental Indenture, dated as of June 30, 1993, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-216 to Form 10-K for the year ended December 31, 2000). (1993 Series AP)
   
  Supplemental Indenture, dated as of August 1, 1999, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-204 to Form 10-Q for the quarter ended September 30, 1999). (1999 Series AP, BP and CP)
   
  Supplemental Indenture, dated as of August 1, 2000, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-210 to Form 10-Q for the quarter ended September 30, 2000). (2000 Series BP)
   
  Supplemental Indenture, dated as of March 15, 2001, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-222 to Form 10-Q for the quarter ended March 31, 2001). (2001 Series AP)

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  Supplemental Indenture, dated as of May 1, 2001, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between Detroit Edison and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-226 to Form 10-Q for the quarter ended June 30, 2001). (2001 Series BP)
   
  Supplemental Indenture, dated as of August 15, 2001, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and

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J.P. Morgan The Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-227 to Form 10-Q for the quarter ended September 30, 2001). (2001 Series CP)
   
  Supplemental Indenture, dated as of September 15, 2001, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-228 to Form 10-Q for the quarter ended September 30, 2001). (2001 Series D and E)
   
  Supplemental Indenture, dated as of September 17, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4.1 to Registration Statement on Form S-3 (File No. 333-100000)). (amendment and successor trustee)
   
  Supplemental Indenture, dated as of October 15, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-230 to Form 10-Q for the quarter ended September 30, 2002). (2002 Series A and B)
   
  Supplemental Indenture, dated as of December 1, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-232 to Form 10-K for the year ended December 31, 2002). (2002 Series C and D)
   
  Supplemental Indenture, dated as of August 1, 2003, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-235 to Form 10-Q for the quarter ended September 30, 2003). (2003 Series A)
   
  Supplemental Indenture, dated as of March 15, 2004, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-238 to Form 10-Q for the quarter ended March 31, 2004). (2004 Series A and B)
   
  Supplemental Indenture, dated as of July 1, 2004, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-240 to Form 10-Q for the quarter ended June 30, 2004). (2004 Series D)
   
  Supplemental Indenture, dated as of April 1, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between Detroit Edison and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4.3 to Registration Statement on Form S-4 (File No. 333-123926)). (2005 Series AR and BR)

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Supplemental Indenture, dated as of August 1, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4.2 to Form 8-K dated August 17, 2005). (2005 Series DT)
   
  Supplemental Indenture, dated as of September 15, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4.2 to Form 8-K dated September 29, 2005). (2005 Series C)
   
  Supplemental Indenture, dated as of September 30, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between Detroit Edison and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-248 to Form 10-Q for the quarter ended September 30, 2005). (2005 Series E)

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  Supplemental Indenture, dated as of May 15, 2006, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-250 to Form 10-Q for the quarter ended June 30, 2006). (2006 Series A)
Supplemental Indenture, dated as of December 1, 2006, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4.2 to Form 8-K dated December 8, 2006). (2006 Series CT)
   
  Supplemental Indenture, dated as of December 1, 2007, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4.2 to Form 8-K dated December 18, 2007). (2007 Series A)
Supplemental Indenture, dated as of May 1, 2008 to Mortgage and Deed of Trust dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-253 to Form 10-Q for the quarter ended June 30, 2008). (2008 Series ET)
Supplemental Indenture, dated as of June 1, 2008 to Mortgage and Deed of Trust dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-255 to Form 10-Q for the quarter ended June 30, 2008). (2008 Series G)
Supplemental Indenture, dated as of July 1, 2008 to Mortgage and Deed of Trust dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-257 to Form 10-Q for the quarter ended June 30, 2008). (2008 Series KT)
Supplemental Indenture, dated as of October 1, 2008 to Mortgage and Deed of Trust dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-259 to Form 10-Q for the quarter ended September 30, 2008). (2008 Series J)
Supplemental Indenture, dated as of December 1, 2008 to Mortgage and Deed of Trust dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee, providing for General and Refunding Mortgage Bonds. (Exhibit 4-261 to Form 10-K for the year ended December 31, 2008). (2008 Series LT)
Supplemental Indenture, dated as of March 15, 2009 to Mortgage and Deed of Trust dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company N.A., as successor trustee (Exhibit 4-263 to Form 10-Q for the quarter ended March 31, 2009). (2009 Series BT)
   
4(b) Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-152 to Registration Statement on Form S-3 (File No. 33-50325)).
   
4(c) Ninth Supplemental Indenture, dated as of October 10, 2001, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-229 to Form 10-Q for the quarter ended September 30, 2001). (5.050% Senior Notes due 2005 and 6.125%(6.125% Senior Notes due 2010)
   
4(d) Tenth Supplemental Indenture, dated as of October 23, 2002, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-231 to Form 10-Q for the quarter ended September 30, 2002). (5.20% Senior Notes due 2012 and 6.35% Senior Notes due 2032)
   
4(e) Eleventh Supplemental Indenture, dated as of December 1, 2002, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-233 to Form 10-Q for the quarter ended March 31,

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2003). (5.45% Senior Notes due 2032 and 5.25% Senior Notes due 2032)
   
4(f) Twelfth Supplemental Indenture, dated as of August 1, 2003, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-236 to Form 10-Q for the quarter ended September 30, 2003). (5 1/2% Senior Notes due 2030)

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4(g) Thirteenth Supplemental Indenture, dated as of April 1, 2004, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-237 to Form 10-Q for the quarter ended March 31, 2004). (4.875% Senior Notes Due 2029 and 4.65% Senior Notes due 2028)
   
4(h) Fourteenth Supplemental Indenture, dated as of July 15, 2004, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-239 to Form 10-Q for the quarter ended June 30, 2004). (2004 Series D 5.40% Senior Notes due 2014)
   
4(i) Sixteenth Supplemental Indenture, dated as of April 1, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4.1 to Registration Statement on Form S-4 (File No. 333-123926)). (2005 Series AR 4.80% Senior Notes due 2015 and 2005 Series BR 5.45% Senior Notes due 2035)
   
4(j)Seventeenth Supplemental Indenture, dated as of August 1, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4.1 to Form 8-K dated August 17, 2005). (2005 Series DT Variable Rate Senior Notes due 2029)
4(k) Eighteenth Supplemental Indenture, dated as of September 15, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4.1 to Form 8-K dated September 29, 2005). (2005 Series C 5.19% Senior Notes due October 1, 2023)
   
4(l) Nineteenth Supplemental Indenture, dated as of September 30, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-247 to Form 10-Q for the quarter ended September 30, 2005). (2005 Series E 5.70% Senior Notes due 2037)
   
4(m) Twentieth Supplemental Indenture, dated as of May 15, 2006, to the Collateral Trust Indenture dated as of June 30, 1993, between The Detroit Edison Company and J.P. MorganThe Bank of New York Mellon Trust Company, National Association,N.A., as successor trustee (Exhibit 4-249 to Form 10-Q for the quarter ended June 30, 2006). (2006 Series A Senior Notes due 2036)

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4(n)Twenty-First Supplemental Indenture, dated as of December 1, 2006, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Trust Company, N.A., as successor trustee (Exhibit 4.1 to Form 8-K dated December 8, 2006). (2006 Series CT Variable Rate Senior Notes due 2036)
4(o) Twenty-Second Supplemental Indenture, dated as of December 1, 2007, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Trust Company, N.A., as successor trustee (Exhibit 4.1 to Form 8-K dated December 18, 2007). (2007 Series A Senior Notes due 2038)
   
4(p)Twenty-Fourth Supplemental Indenture, dated as of May 1, 2008, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Trust Company, N.A., as successor trustee (Exhibit 4-254 to Form 10-Q for the quarter ended June 30, 2008). (2008 Series ET Variable Rate Senior Notes due 2029)
Amendment dated June 1, 2009 to the Twenty-fourth Supplemental Indenture, dated as of May 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (2008 Series ET Variable Rate Senior Notes due 2029) (Exhibit 4-265 to Form 10-Q for the quarter ended June 30, 2009)
Twenty-Fifth Supplemental Indenture, dated as of June 1, 2008, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Trust Company, N.A., as successor trustee (Exhibit 4-256 to Form 10-Q for the quarter ended June 30, 2008). (2008 Series G 5.60% Senior Notes due 2018)
Twenty-Sixth Supplemental Indenture, dated as of July 1, 2008, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Trust Company, N.A., as successor trustee (Exhibit 4-258 to Form 10-Q for the quarter ended June 30, 2008). (2008 Series KT Variable Rate Senior Notes due 2020)
Amendment dated June 1, 2009 to the Twenty-sixth Supplemental Indenture, dated as of July 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (2008 Series KT Variable Rate Senior Notes due 2020) (Exhibit 4-266 to Form 10-Q for the quarter ended June 30, 2009)

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Twenty-Seventh Supplemental Indenture, dated as of October 1, 2008, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Trust Company, N.A., as successor trustee (Exhibit 4-260 to Form 10-Q for the quarter ended September 30, 2008). (2008 Series J 6.40% Senior Notes due 2013)
Twenty-Eighth Supplemental Indenture, dated as of December 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. (Exhibit 4-262 to Detroit Edison’s Form 10-K for the year ended December 31, 2008). (2008 Series LT 6.75% Senior Notes due 2038)
Twenty-Ninth Supplemental Indenture, dated as of March 15, 2009, to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-264 to Detroit Edison’s Form 10-Q for the quarter ended March 31, 2009). (2009 Series BT 6.00% Senior Notes due 2036)
4(c) Trust Agreement of Detroit Edison Trust I. (Exhibit 4.9 to Registration Statement on Form S-3 (File No. 333-100000)).
   
4(q)4(d) Trust Agreement of Detroit Edison Trust II. (Exhibit 4.10 to Registration Statement on Form S-3 (File No. 333-100000)).
   
10(a) Securitization Property Sales Agreement dated as of March 9, 2001, between The Detroit Edison Securitization Funding LLC and The Detroit Edison Company. (Exhibit 10-42 to Form 10-Q for the quarter ended March 31, 2001).
   
10(b)Certain arrangements pertaining to the employment of Anthony F. Earley, Jr. with The Detroit Edison Company, dated April 25, 1994. (Exhibit 10-53 to Form 10-Q for the quarter ended March 31, 1994).
10(c)Certain arrangements pertaining to the employment of Gerard M. Anderson with The Detroit Edison Company, dated October 6, 1993. (Exhibit 10-48 to Form 10-K for year ended December 31, 1993).
10(d)Certain arrangements pertaining to the employment of David E. Meador with The Detroit Edison Company, dated January 14, 1997. (Exhibit 10-5 to Form 10-K for the year ended December 31, 1996).
10(e)Amended and Restated Post-Employment Income Agreement, dated March 23, 1998, between The Detroit Edison Company and Anthony F. Earley, Jr. (Exhibit 10-21 to Form 10-Q for the quarter ended March 31, 1998).
10(f)The Detroit Edison Company Supplemental Long-Term Disability Plan, dated January 27, 1997. (Exhibit 10-4 to Form 10-K for the year ended December 31, 1996).
10(g) Form of The Detroit Edison Company’s Five-Year Credit Agreement, dated as of October 17, 2005, by and among The Detroit Edison Company, the lenders party thereto, Barclays Bank PLC, as Administrative Agent, and Citibank, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.1 to Form 8-K dated October 17, 2005).
   
10(c)10(h) Form of Amendment No.1 to The Detroit Edison Company’s Five-YearTwo-Year Credit Agreement, dated as of January 10, 2007,April 29, 2009, by and among The Detroit Edison, Company, the lenders party thereto, Barclays, Bank PLC, as Administrative Agent, and Citibank, N.A.JPMorgan and JPMorgan Chase Bank, N.A.,RBS, as Co-Syndication AgentsAgents. (Exhibit 10.1 to Form 8-K dated January 10, 2007).
10(d)Form of Second Amended and Restated Five-Year Credit Agreement, dated as of October 17, 2005, by and among The Detroit Edison Company, the lenders party thereto, Barclays Bank PLC, as Administrative Agent, and Citibank, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.2 to Form 8-K dated October 17, 2005)
10(e)Form of Amendment No. 1. to Second Amended and Restated Five-Year Credit Agreement dated as of January 10, 2007, by and among The Detroit Edison Company, the lenders party thereto, Barclays Bank PLC, as Administrative Agent, and Citibank, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.2 to Form 8-K dated January 10, 2007).
10(f)Certain arrangements pertaining to the employment of Anthony F. Earley, Jr. with The Detroit Edison Company, dated April 25, 1994. (Exhibit 10-53 to Form 10-Q for the quarter ended March 31, 1994)

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10(g)Certain arrangements pertaining to the employment of Gerard M. Anderson with The Detroit Edison Company, dated October 6, 1993. (Exhibit 10-48 to Form 10-K for year ended December 31, 1993)
10(h)Certain arrangements pertaining to the employment of David E. Meador with The Detroit Edison Company, dated January 14, 1997. (Exhibit 10-5 to Form 10-K for the year ended December 31, 1996)
10(i)Amended and Restated Post-Employment Income Agreement, dated March 23, 1998, between The Detroit Edison Company and Anthony F. Earley, Jr. (Exhibit 10-21 to Form 10-Q for the quarter ended March 31, 1998)
10(j)Executive Post-Employment Income Arrangement, dated March 27, 1989, between The Detroit Edison Company and S. Martin Taylor. (Exhibit 10-22 to Form 10-Q for the quarter ended March 31, 1998)
10(k)The Detroit Edison Company Supplemental Long-Term Disability Plan, dated January 27, 1997. (Exhibit 10-4 to Form 10-K for the year ended December 31, 1996)
10(l)Executive Vehicle Plan of The Detroit Edison Company, dated as of September 1, 1999. (Exhibit 10-41 to Form 10-Q for the quarter ended March 31, 2001)
10(m)Loan Agreement dated as of December 1, 2006 between The Detroit Edison Company and the Michigan Strategic Fund (Exhibit 10.1 to Form 8-K dated December 8, 2006)
10(n)Amended and Restated Trade Receivables Purchase and Sale Agreement among Detroit Edison, CAFCO, Citibank and Citicorp, individually and as Agent dated March 9, 2001 (Exhibit 99-43 to Form 10-Q dated March 31, 2001)
10(o)Amendment No. 1 dated as of January 17, 2003 to the Amended and Restated Trade Receivables Purchase and Sale Agreement among Detroit Edison, CAFCO, Citibank and Citicorp, individually and as Agent dated March 9, 2001, as amended (Exhibit 10-41 to Form 10-K for the year ended December 31, 2006)
10(p)Amendment No. 2 dated as offiled May 28, 2003 to the Amended and Restated Trade Receivables Purchase and Sale Agreement among Detroit Edison, CAFCO, Citibank and Citicorp, individually and as Agent dated March 9, 2001, as amended (Exhibit 99-12 to Form 10-Q dated June 30, 2003)
10(q)Amendment No. 3 dated as of February 25, 2004 to the Amended and Restated Trade Receivables Purchase and Sale Agreement among Detroit Edison, CAFCO, Citibank and Citicorp, individually and as Agent dated March 9, 2001, as amended (Exhibit 99-16 to Form 10-Q dated March 31, 2004)
10(r)Amendment No. 4 dated as of January 20, 2005 to the Amended and Restated Trade Receivables Purchase and Sale Agreement among Detroit Edison, CAFCO, Citibank and Citicorp, individually and as Agent dated March 9, 2001,

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as amended (Exhibit 99-18 to Form 10-K dated December 31, 2004)
10(s)Amendment No. 5, dated as of January 18, 2007 to the Amended and Restated Trade Receivables Purchase and Sale Agreement among Detroit Edison, CAFCO, Citibank and Citicorp, individually and as Agent dated March 9, 2001, as amended (Exhibit 10-42 to Form 10-K for the year ended December 31, 2006)
10(t)Amendment No. 6 dated as of January 18, 2007 to the Amended and Restated Trade Receivables Purchase and Sale Agreement among Detroit Edison, CAFCO, Citibank and Citicorp, individually and as Agent dated March 9, 2001, as amended (Exhibit 10-01 to Form 8-K dated January 18, 2007)
10(u)Amendment No. 7 dated as of January 17, 2008 to the Amended and Restated Trade Receivables Purchase and Sale Agreement among Detroit Edison, CAFCO, Citibank and Citicorp, individually and as Agent dated March 9, 2001, as amended. (Exhibit 10-1 to Form 8-K dated January 17, 2008)2009).
   
99(a) Belle River Participation Agreement, dated as of December 1, 1982, between The Detroit Edison Company and Michigan Public Power Agency. (Exhibit 28-5 to Registration Statement No. 2-81501).

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99(b) Belle River Transmission Ownership and Operating Agreement, dated as of December 1, 1982, between The Detroit Edison Company and Michigan Public Power Agency. (Exhibit 28-6 to Registration Statement No. 2-81501)
99(c)Inter-Creditor Agreement, dated as of March 9, 2001, among Citicorp North America, Inc., Citibank, N.A., The Bank of New York, The Detroit Edison Securitization Funding LLC and The Detroit Edison Company. (Exhibit 99-41 to Form 10-Q for the quarter ended March 31, 2001).
 (iii)(iii) Exhibits furnished herewith.
   
32-3732-53 Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report.
   
32-3832-54 Chief Financial Officer Section 906 Form 10-K Certification of Periodic Report.

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The Detroit Edison Company
Schedule II Valuation and Qualifying Accounts
                        
 Year Ended December 31  Year Ended December 31 
(in Millions) 2007 2006 2005  2009 2008 2007 
Allowance for Doubtful Accounts (shown as deduction from accounts receivable in the consolidated statements of financial position)
 
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statements of Financial Position)
 
Balance at Beginning of Period $72 $54 $55  $121 $93 $72 
Additions:  
Charged to costs and expenses 63 53 41  62 81 63 
Charged to other accounts (1) 4 3 4  7 5 4 
Deductions (2)  (46)  (38)  (46)  (72)  (58)  (46)
              
Balance At End of Period $93 $72 $54  $118 $121 $93 
              
 
(1) Collection of accounts previously written off.
 
(2) Non-collectible accounts written off.

7173


Signatures
Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
     
 THE DETROIT EDISON COMPANY
(Registrant)

 
 
Date: March 17, 2008February 23, 2010 By /s/ PETER B. OLEKSIAK
ANTHONY F. EARLEY, JR.   
   Anthony F. Earley, Jr. Peter B. Oleksiak
   Chairman of the Board and
Chief Executive Officer 
Vice President and Controller, and
 Chief Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
       
By /s/ ANTHONY F. EARLEY, JR. By /s/ PETER B. OLEKSIAK
       
  Anthony F. Earley, Jr.
Chairman of the Board and
Chief Executive Officer
   Peter B. Oleksiak
Chairman of the Board and
Vice President, and Controller and
Chief Executive Officer Investor Relations, and
Chief Accounting Officer
       
By /s/ SANDRA KAY ENNIS By /s/ DAVID E. MEADOR
       
  Sandra Kay EnnisDavid E. Meador

Director and Corporate Secretary
   David E. Meador
Director, Executive Vice President
and Chief Financial Officer
       
By /s/ BRUCE D. PETERSON    
       
  Bruce D. Peterson

Director
Date: March 17, 2008    
Date: February 23, 2010

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