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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K
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
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2012
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-2198
The Detroit EdisonDTE Electric 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 EDISONDTE ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Michigan 38-0478650
Michigan
(State or other jurisdiction of incorporation or
organization)
 38-0478650
(I.R.S. Employer
Identification No.)
   
One Energy Plaza, Detroit, Michigan
48226-1279
(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). Yesoþ 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.þ
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 filer o
 
Accelerated filer o
 
Large accelerated fileroAccelerated filero
Non-accelerated filerþ
Smaller reporting companyo
(Do not check if a smaller reporting company)
 
Smaller reporting company o
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 EdisonTable of Contents

DTE Electric Company
Annual Report on Form 10-K
Year Ended December 31, 2009
2012
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Table of Contents

Definitions

ASC Accounting Standards Codification
   
ASU Accounting Standards Update
   
CTACIM CostsA Choice Incentive Mechanism authorized by the MPSC that allows DTE Electric to achieve, consistingrecover or refund non-fuel revenues lost or gained as a result of project management, consultant support and employee severance, related to the Performance Excellence Processfluctuations in electric Customer Choice sales.
   
Customer Choice Statewide initiativesMichigan legislation giving customers in Michigan the option to choose alternative suppliers for electricity.
   
Detroit EdisonDTE Electric The Detroit EdisonDTE Electric Company (a direct wholly owned subsidiary of DTE Energy Company)Energy) and subsidiary companiescompanies. Formerly known as The Detroit Edison Company.
   
DTE Energy DTE Energy Company, the parent of Detroit Edison and directly or indirectly the parent company of DTE Electric, DTE Gas Company and numerous utility and non-utility subsidiaries
   
EPA United States Environmental Protection Agency
   
FASB Financial Accounting Standards Board
   
FERC Federal Energy Regulatory Commission
   
FSPFTRs FASB Staff PositionFinancial transmission rights are financial instruments that entitle the holder to receive payments related to costs incurred for congestion on the transmission grid.
   
FTRsMCIT Financial transmission rightsMichigan Corporate Income Tax
   
MDEQ Michigan Department of Environmental Quality
   
MISO Midwest Independent System Operator is an Independent System Operator and the Regional Transmission Organization serving the Midwest United States and Manitoba, Canada.
   
MPSC Michigan Public Service Commission
   
NRC United States Nuclear Regulatory Commission
   
PSCR A power supply cost recoveryPower Supply Cost Recovery mechanism authorized by the MPSC that allows Detroit EdisonDTE Electric to recover through rates its fuel, fuel-related and purchased power costs.
   
RDMA Revenue Decoupling Mechanism authorized by the MPSC that is designed to minimize the impact on revenues of changes in average customer usage of electricity
Securitization Detroit EdisonDTE Electric financed specific stranded costs at lower interest rates through the sale of rate reduction bonds by a wholly-owned special purpose entity, The Detroit Edison Securitization Funding LLC.
   
SFASVIE Statement of Financial Accounting StandardsVariable Interest Entity

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Table of Contents

Units of Measurement  
Units of Measurement
GWhGigawatthour of electricity
   
kWh Kilowatthour of electricity
   
MW Megawatt of electricity
   
MWh Megawatthour of electricity

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Table of Contents

Forward-Looking StatementsFORWARD-LOOKING STATEMENTS
Certain information presented herein includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 with respect to the financial condition, results of operations and business of Detroit Edison.DTE Electric. Words such as "anticipate," "believe," "expect," "projected" and "goals" signify forward-looking statements. Forward-looking statements are not guarantees of future results and conditions, but rather are subject to numerous assumptions, risks and uncertainties that may cause actual future results to be materially different from those contemplated, projected, estimated or budgeted. Many factors may impact forward-looking statements including, but not limited to, the following:
the length and severity of ongoing economic decline resulting in lower demand, customer conservation and 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;
high levels of uncollectible accounts receivable;
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;
cost reduction efforts and the maximization of 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;


the amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals or new legislation;
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 amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals or new legislation;
the cost of protecting assets against, or damage due to, 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;
changes in federal or state laws and their interpretation with respect to regulation, energy policy and other business issues; and
binding arbitration, litigation and related appeals.
impact of electric utility restructuring in Michigan, including legislative amendments and Customer Choice programs;
economic conditions and population changes in our geographic area resulting in changes in demand, customer conservation, increased thefts of electricity and high levels of uncollectible accounts receivable;
environmental issues, laws, regulations, and the increasing costs of remediation and compliance, including actual and potential new federal and state requirements;
health, safety, financial, environmental and regulatory risks associated with ownership and operation of nuclear facilities;
changes in the cost and availability of coal and other raw materials and purchased power;
the potential for losses on investments, including nuclear decommissioning and benefit plan assets and the related increases in future expense and contributions;
access to capital markets 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;
the potential for increased costs or delays in completion of significant construction projects;
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 effects of weather and other natural phenomena on operations and sales to customers, and purchases from suppliers;
unplanned outages;
the cost of protecting assets against, or damage due to, terrorism or cyber attacks;
employee relations and the impact of collective bargaining agreements;
the availability, cost, coverage and terms of insurance and stability of insurance providers;
cost reduction efforts and the maximization of plant and distribution system performance;
the effects of competition;
changes in and application of accounting standards and financial reporting regulations;
changes in federal or state laws and their interpretation with respect to regulation, energy policy and other business issues;
binding arbitration, litigation and related appeals; and
the risks discussed in our public filings with the Securities and Exchange Commission.
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 referspeak 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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Table of Contents

Part I
Items 1. and 2. Business and Properties

General
Detroit Edison
DTE Electric is a Michigan corporation organized in 1903 and is a wholly-owned subsidiary of DTE Energy. Detroit EdisonDTE Electric is a public utility subject to regulation by the MPSC and the FERC. Detroit EdisonDTE Electric is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 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.DTE Electric.

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 fossilfossil-fuel plants, a hydroelectric pumped storage plant, and a nuclear plant and our wind and other renewable assets, and is purchased from electricity generators, suppliers and wholesalers.
The electricity we produce and purchase is sold to three major classes of customers: residential, commercial and industrial, principally throughout southeastern Michigan.
 ��           
Revenue by Service         
(in Millions) 2009  2008  2007 
Residential $1,820  $1,726  $1,739 
Commercial  1,702   1,753   1,723 
Industrial  730   894   854 
Other  299   289   384 
          
Subtotal  4,551   4,662   4,700 
Interconnection sales (1)  163   212   200 
          
Total Revenue $4,714  $4,874  $4,900 
          

Revenue by Service

 2012 2011 2010
 (In millions)
Residential$2,354
 $2,182
 $2,052
Commercial1,898
 1,704
 1,629
Industrial784
 692
 688
Other150
 456
 479
Subtotal5,186
 5,034
 4,848
Interconnection sales (a)105
 118
 145
Total Revenue$5,291
 $5,152
 $4,993

(1)(a)Represents power that is not distributed by Detroit Edison.DTE Electric.

Weather, economic factors, competition and electricity prices affect sales levels to customers. Our peak load and highest total system sales generally occur during the third quarter of the year, driven by air conditioning and other cooling-related demands. Our operations are not dependent upon a limited number of customers, and the loss of any one or a few customers would not have a material adverse effect on Detroit Edison.DTE Electric.

Fuel Supply and Purchased Power

Our power is generated from a variety of fuels and is supplemented with purchased power. We expect to have an adequate supply of fuel and purchased power to meet our obligation to serve customers. Our generating capability is heavily dependent upon the availability of coal. Coal is purchased from various sources in different geographic areas under agreements that vary in both pricing and terms. We expect to obtain the majority of our coal requirements through long-term contracts, with the balance to be obtained through short-term agreements and spot purchases. We have nine long-term and nine short-term contracts for a totalthe purchase of approximately 2822.1 million tons of low-sulfur western coal to be delivered from 20102013 through 2012. We also have nine long-term2015 and two short-term contracts for the purchase of approximately 93.5 million tons of Appalachian coal to be delivered from 20102013 through 2012.2014. All of these contracts have fixed prices.pricing schedules. We have approximately 87%81% of our 20102013 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 our expected western coal rail requirements under contract through 2015. All of our expected eastern coal rail requirements are under contract through 2013. Our expected vessel transportation contracts with companies to provide rail and vessel servicesrequirements for delivery of purchased coal to our generating facilities.facilities are under contract through 2014.
Detroit Edison
DTE Electric 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.cycles or during major plant outages.



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Table of Contents

Properties
Detroit Edison
DTE Electric 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, 20092012 are as follows:
               
  Location by  Summer Net   
  Michigan  Rated Capability (1)   
Plant Name County  (MW)  (%)  Year in Service
Fossil-fueled Steam-Electric              
Belle River (2) St. Clair  1,034   9.3  1984 and 1985
Conners Creek Wayne  230   2.1  1951
Greenwood St. Clair  785   7.1  1979
Harbor Beach Huron  103   0.9  1968
Marysville St. Clair  84   0.8  1943 and 1947
Monroe (3) Monroe  3,090   27.9  1971, 1973 and 1974
River Rouge Wayne  523   4.7  1957 and 1958
St. Clair (4) St. Clair  1,365   12.3  1953, 1954, 1959, 1961 and 1969
Trenton Channel Wayne  730   6.6  1949 and 1968
             
       7,944   71.7   
Oil or Gas-fueled Peaking Units Various  1,101   10.0  1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric Fermi 2 (5) Monroe  1,102   10.0  1988
Hydroelectric Pumped Storage Ludington(6) Mason  917   8.3  1973
             
       11,064   100.0   
             
  
Location by
Michigan
 
Summer Net
Rated
Capability (a)
  
Plant Name County (MW) (%) Year in Service
Fossil-fueled Steam-Electric      
  
Belle River (b) St. Clair 1,036
  9.8
 1984 and 1985
Greenwood St. Clair 793
  7.5
 1979
Harbor Beach Huron 95
  0.9
 1968
Monroe (c) Monroe 3,047
  28.9
 1971, 1973 and 1974
River Rouge Wayne 524
  5.0
 1957 and 1958
St. Clair St. Clair 1,379
  13.0
 1953, 1954, 1959, 1961 and 1969
Trenton Channel Wayne 675
  6.4
 1949 and 1968
    7,549
  71.5
  
Oil or Gas-fueled Peaking Units Various 1,018
  9.6
 1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric Fermi 2 (d) Monroe 1,086
  10.3
 1988
Hydroelectric Pumped Storage
Ludington (e)
 Mason 917
  8.6
 1973
    10,570
  100.0
  

(1)(a)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)(b)The Belle River capability represents Detroit Edison’sDTE Electric's entitlement to 81.39%81% of the capacity and energy of the plant. See Note 76 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
(3)(c)The Monroe powergenerating plant provided 38%37% of Detroit Edison’sDTE Electric's total 20092012 power generation.
(4)Excludes one oil-fueled unit (250 MW) in cold standby status.
(5)(d)Fermi 2 has a design electrical rating (net) of 1,150 MW.
(6)(e)Represents Detroit Edison’sDTE Electric's 49% interest in Ludington with a total capability of 1,872 MW. See Note 76 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
Detroit Edison
In 2008, a renewable portfolio standard was established for Michigan electric providers targeting 10% of electricity sold to retail customers from renewable energy by 2015. DTE Electric has approximately 720 MW of owned or contracted renewable energy, principally wind turbines located in Gratiot, Tuscola, Huron and Sanilac counties in Michigan, at December 31, 2012 representing approximately 8% of electricity sold to retail customers. Approximately 510 MW is in commercial operation at December 31, 2012 with an additional 210 MW expected in commercial operation in 2013 or early 2014.

DTE Electric owns and operates 677671 distribution substations with a capacity of approximately 33,347,00033,648,000 kilovolt-amperes (kVA) and approximately 423,600430,600 line transformers with a capacity of approximately 21,883,00022,306,000 kVA.

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Circuit miles of electric distribution lines owned and in service as of December 31, 2009:2012:
         
  Circuit Miles 
Operating Voltage-Kilovolts (kV) Overhead  Underground 
4.8 kV to 13.2 kV  28,243   13,884 
24 kV  177   681 
40 kV  2,317   363 
120 kV  54   13 
       
   30,791   14,941 
       
  Circuit Miles
Operating Voltage-Kilovolts (kV) Overhead Underground
4.8 kV to 13.2 kV 27,856
  14,585
 
24 kV 182
  696
 
40 kV 2,278
  383
 
120 kV 54
  8
 
  30,370
  15,672
 

There are numerous interconnections that allow the interchange of electricity between Detroit EdisonDTE Electric and electricity providers external to our service area. These interconnections are generally owned and operated by ITC Transmission, an unrelated company, and connect to neighboring energy companies.


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Regulation
Detroit Edison’s
DTE Electric'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’sDTE Electric'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 EdisonDTE Electric 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’sDTE Electric'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,Notes 3, 7, 8 10 and 1614 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’sDTE Electric's ability to control its uncollectible accounts receivable and collections expenses. Detroit Edison’sDTE Electric's uncollectible accounts receivable expense is directly affected by the level of government fundedgovernment-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. We also partner with federal, state and local officials to attempt to increase the share of low-income funding allocated to our customers. Changes in the level of funding provided to our low-income customers will affect the level of uncollectible expense.

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 and network reliability we continue to investmake capital investments in our generating plants and distribution system, which will improve both plant availability, operating efficiencies and operating efficiencies. We also are making capital investmentsenvironmental compliance 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 1A. 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, subject to limits. Customers choosing to purchase power from alternative electric suppliers represented approximately 3%10% of retail sales in 20092012, 2011 and 2008, and 4% of such sales in 2007.2010. 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.market costs. MPSC rate orders and

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recent 2008 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.performance and full service customer rates. We expect that in 20102013 customers choosing to purchase power from alternative electric suppliers 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:regulations. Actual costs to comply could vary substantially. Additional costs may result as the effects of various substances on the environment are studied and governmental regulations are developed and implemented.

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(in Millions)    
Air $2,200 
Water  55 
MGP sites  5 
Other sites  21 
    
Estimated total future expenditures through 2019 $2,281 
    
Estimated 2010 expenditures $82 
    
Estimated 2011 expenditures $253 
    
  (In millions)
Air$1,784
Water80
Contaminated and other sites13
Estimated total future expenditures through 2020$1,877
Estimated 2013 expenditures$336
Estimated 2014 expenditures$324

Air— Detroit Edison - DTE Electric is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze, mercury and mercuryother air pollution. The newThese rules will leadhave led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, with further emission controls planned for reductions in mercury and mercuryother emissions. 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 quantifyover the impact of those expected rulemakings at this time.next few years.

Water - In response to an EPA regulation, Detroit EdisonDTE Electric 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 and expected future studies, Detroit EdisonDTE Electric may be required to perform some mitigation activities, including the possible installation of additional controlinstall technologies to reduce the environmental impactimpacts of the intake structures.water intakes. However, a January 2007 circuit court decision remanded back to the EPA several provisionstypes 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 oftechnologies are unknown at 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.time. The EPA has also proposedissued 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)
Contaminated 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 MGPmanufactured gas plant (MGP) sites. Detroit EdisonDTE Electric owns, or previously owned, three former MGP sites. In addition to the MGP sites, we

We are also in the process 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 storage facility, electrical distribution substations, electric generating power plants, and underground and aboveground storage tank locations. Cleanup activities associated with these sites will be conducted over the next several years.

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Landfill— Detroit Edison owns Any significant change in assumptions, such as remediation techniques, nature and operates a permitted engineered ash storage facility atextent of contamination and regulatory requirements, could impact the Monroe Power Plant to disposeestimate of fly ash fromremedial action costs for these sites and affect the coal fired power plant. Detroit Edison performed an engineering analysis in 2009Company's financial position and identifiedcash flows and the need for embankment side slope repairs and reconstruction.rates we charge our customers.

The EPA has expressed its intentions to develop new federal regulations for coal ash under the authority of the Resources Conservation and Recovery Act (RCRA). Apublished proposed regulation is expected in the first quarter of 2010. Among the options EPA is currently considering, is a ruling that may designate coal ash as a “Hazardous Waste” as defined by RCRA. However, agencies and legislatures have urged EPArules to regulate coal ash, aswhich may result in a non-hazardous waste. If EPA were to designate coal ashdesignation as a hazardous waste, the agencywaste. The EPA could apply some, or all, of the disposal and reuse standards that have been applied to other existing hazardous wastes. Some of the regulatory actions currently being contemplated could have a material adversesignificant impact on our operations and financial position and the rates we charge our customers.
Global 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 equipment 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 customersthe impact of those expected rulemakings at this time.

See Notes 108 and 1714 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

EMPLOYEES

We had 4,864approximately 4,800 employees as of December 31, 2009,2012, of which 2,782approximately 2,700 were represented by unions. The majority of our union employees are under contractsa contract that expireexpires in June 2010 and August 2012.2013.

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Item 1A. Risk Factors

There are various risks associated with the operations of Detroit Edison.DTE Electric. To provide a framework to understand the operating environment of the Company, 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
We are subject to rate regulation.  Our electric rates are set by the MPSC and national economic conditionsthe FERC and cannot be changed 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. We typically self-implement base rate changes six months after rate case filings in accordance with Michigan law. However, if the

7


final rates authorized by our regulators in the final rate order are lower than the amounts we collected during the self-implementation period, we must refund the difference with interest. Our regulators may also disagree with our rate calculations under the various tracking mechanisms that are intended to mitigate the risk of certain aspects of our business. If we cannot agree with our regulators on an appropriate reconciliation of those mechanisms, it may impact our ability to recover certain costs through our customer rates. Our regulators may also decide to eliminate more of these mechanisms in future rate cases, which may make it more difficult for us to recover our costs in the rates we charge customers. We cannot predict what rates an MPSC order will adopt in future rate cases. New legislation, regulations or interpretations could change how our business operates, impact our ability to recover costs through rates or require us to incur additional expenses.

Changes to Michigan's electric Customer Choice program could negatively impact our financial performance.  The electric Customer Choice program, as originally contemplated in Michigan, anticipated an eventual transition to a totally deregulated and competitive environment where customers would be charged market-based rates for their electricity. The State of Michigan currently experiences a hybrid market, where the MPSC continues to regulate electric rates for our customers, while alternative electric suppliers charge market-based rates. In addition, such regulated electric rates for certain groups of our customers exceed the cost of service to those customers. Due to distorted pricing mechanisms during the initial implementation period of electric Customer Choice, many commercial customers chose alternative electric suppliers. MPSC rate orders and 2008 energy legislation enacted by the State of Michigan are phasing out the pricing disparity over five years and have placed a 10 percent cap on the total potential Customer Choice related migration. However, even with the electric Customer Choice-related relief received in prior DTE Electric rate orders and the legislated 10 percent cap on participation in the electric Customer Choice program, there continues to be legislative and financial risk associated with the electric Customer Choice program. Electric Customer Choice migration is sensitive to market price and full service electric price changes.

Environmental laws and liability may be costly.  We are subject to and affected by 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 and can negatively affect the affordability of the rates we charge to our customers.

Uncertainty around future environmental regulations creates difficulty planning long-term capital projects in our generation fleet. 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 cleanup 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 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.

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, changes in federal nuclear regulation 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.

The supply and/or price of energy commodities and/or related services may impact our financial results.  We are dependent on coal for much of our electrical generating capacity. Price fluctuations, fuel supply disruptions and changes in transportation costs could have an unfavorablea negative impact on us.Our business follows the economic cyclesamounts we charge our utility customers for electricity. We have hedging strategies and regulatory recovery mechanisms in place to mitigate some of the negative fluctuations in commodity supply prices, but there can be no assurances that our financial performance will not be negatively impacted by price fluctuations.

The supply and/or price of 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

8


interruptions for these commodities and other items could have a negative impact on the amounts we charge our 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.for our products.

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 our 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.OurOur 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, potentiallyresulting in 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 Edisonour 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. Our electric rates 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 costsaccess 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 be impactedagain in the future constrain, our ability to issue new debt, including commercial paper, and refinance existing debt at reasonable interest rates. In addition, the level of borrowing by the time lag between the incurrence of costsother energy companies and the recovery of the costs in customers’ rates.market as a whole could limit our access to capital markets. Our regulators also may decidelong term revolving credit facility does not expire until 2016, but we regularly access capital markets 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 arefinance existing debt or fund new governor and legislature in 2010projects, and we cannot predict the outcome of that election. We cannot predict whether election resultspricing 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.demand for those future transactions.
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 performance.The electric Customer Choice program, as originally contemplated in Michigan, anticipated an eventual transition to a totally deregulated and competitive environment where customers would be charged market-based rates for their electricity. The State of Michigan currently experiences a hybrid market, where the MPSC continues to regulate electric rates for our customers, while alternative electric suppliers charge market-based rates. In addition, such regulated electric rates for certain groups of our customers exceed the cost of service to those customers. Due to distorted pricing mechanisms during the initial implementation period of electric Customer Choice, many commercial customers chose alternative electric suppliers. MPSC rate orders and recent energy legislation enacted by the State of Michigan are phasing out the pricing disparity over five years and have placed a cap on the total potential Customer Choice related migration. However, even with the electric Customer Choice-related relief received in recent Detroit Edison rate orders and the legislated 10 percent cap on participation in the electric Customer Choice program, there continues to be financial risk associated with the electric Customer Choice program. Electric Customer Choice migration is sensitive to market price and bundled electric service price increases.
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 delaydelays 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 and/or price of energy commodities and/or related service may impact
Weather significantly affects operations.  Deviations from normal hot and cold weather conditions affect our financial results.We are dependent on coal for muchearnings and cash flow. Mild temperatures can result in decreased utilization of our electrical generating capacity. Price fluctuations, fuel supply disruptionsassets, lowering income and increases in transportation costs could have a negative impact oncash flow. Ice storms, tornadoes, or high winds can damage the amounts we charge our customers for

10


electricity. We have hedging strategieselectric distribution system infrastructure and regulatory recovery mechanisms in placepower generation facilities and require us to mitigate negative fluctuations in commodity supply prices, but there can be no assurances that our financial performance willperform emergency repairs and incur material unplanned expenses. The expenses of storm restoration efforts may not be negatively impacted by price fluctuations.fully recoverable through the regulatory process.
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.
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 cleanup 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 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 existing 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 developingimplementing a strategy for complying with the existing state legislation, but we do not know what requirements may be added by federal legislation. In addition, there could be additional state requirements

9


increasing the percentage of power required to be provided by renewable energy sources. 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.

Regional and national economic conditions can have an unfavorable impact on us.  Our business follows the economic cycles of the customers we serve and the credit risk of counterparties we do business with. Should national or regional economic conditions deteriorate, reduced volumes of electricity, collections of accounts receivable, and reductions in federal and state energy assistance funding, and potentially higher levels of stolen electricity could result in decreased earnings and cash flow.

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.

Failure to maintain the security of personally identifiable information could adversely affect us.  In connection with our business we collect and retain personally identifiable information of our customers, shareholders and employees. Our customers, shareholders 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 fraudulent use of customer, shareholder, employee or DTE Electric data by cybercrime or otherwise could adversely impact our reputation and could result in significant costs, fines and litigation.

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.

A work interruption may adversely affect us.  Unions represent approximately 2,700 of our employees. The majority of our union employees are under a contract that expires in June 2013. We cannot predict the outcome of those negotiations. A union choosing to strike would have an impact on our business. We are unable to predict the effect a work stoppage would have on our costs of operation and financial performance.

We may not be fully covered by insurance.We 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 or a combination of other significant unforeseen events that could impact our operations. Economic losses might not be covered in full by insurance or our insurers may be unable to meet contractual obligations.
Failure to maintain the security of personally identifiable information could adversely affect us. In connection with our business 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 fraudulent use of customer, employee or Detroit Edison data by cybercrime or otherwise could adversely impact our reputation and could result in significant costs, fines and litigation.
Benefits of continuous improvement initiatives could be less than we expect. We have a continuous improvement program that is expected to result in significant cost savings. Actual results achieved through this program could be less than our expectations.
A work interruption may adversely affect us.Unions represent approximately 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.


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Item 3. Legal Proceedings

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

In July 2009, DTE Energy received a Notice of Violation/Violation (NOV)/Finding of Violation (NOV/FOV)(FOV) from the EPA alleging, among other things, that five Detroit Edisonof DTE Electric's power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and Title V operating permit requirements under the Clean Air Act. WeIn June 2010, the EPA issued a NOV/FOV making similar allegations related to a recent project and outage at Unit 2 of the Monroe Power Plant.

In August 2010, the United States Department of Justice, at the request of EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and DTE Electric, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require DTE Electric to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require DTE Electric to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from DTE Electric's fleet of coal-fired power plants until the new control equipment is operating. On August 23, 2011, the U.S. District Court judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy and DTE Electric. On October 20, 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit. Oral arguments at the Court of Appeals were held on November 27, 2012 and a decision is expected in early 2013.

DTE Energy and DTE Electric believe that the plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of our discussions with the EPA regarding the NOV/FOV, the EPA could bring legal action against Detroit Edison. Wetwo NOVs/FOVs, DTE Electric could also be required to install additional pollution control equipment at some or all of the power plants in question, implement early retirement of facilities where control equipment is not economical, engage in Supplemental Environmental Programs,supplemental environmental programs, and/or pay fines. WeDTE Energy and DTE Electric cannot predict the financial impact or outcome of this matter,these matters, or the timing of its resolution.

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For additional discussion on legal matters, see Notes 8 and 14 of the following Notes to Consolidated Financial Statements:Statements in Item 8 of this Report.

NoteItem 4.Title
10Regulatory Matters
16Commitments and ContingenciesMine Safety Disclosures

Not applicable.

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,DTE Electric, par value $10 per share, are owned by DTE Energy, and constitute 100% of the voting securities of Detroit Edison.DTE Electric. Therefore, no market exists for our common stock.

We paid cash dividends on our common stock of $317 million in 2012 and $305 million in 2009, 2008,2011, and 2007.2010.

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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Table of Contents

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 EdisonDTE Electric is presented in accordance with General Instruction I (2) (a) of Form 10-K for wholly-owned subsidiaries (reduced disclosure format).
Increase (Decrease) in Income Statement Components Compared to Prior Year
(in Millions)
 2009  2008 
       
Operating revenues $(160) $(26)
Fuel and purchased power  (287)  92 
       
Gross margin  127   (118)
Operation and maintenance  (45)  (100)
Depreciation and amortization  101   (21)
Taxes other than income  (27)  (45)
Asset (gains) losses and reserves, net  (1)  (9)
       
Operating income  99   57 
Other (income) and deductions  12   6 
Income tax provision  42   37 
       
Net Income $45  $14 
       

 2012 2011 2010
 (In millions)
Operating revenues$5,291
 $5,152
 $4,993
Fuel and purchased power1,758
 1,716
 1,580
Gross margin3,533
 3,436
 3,413
Operation and maintenance1,429
 1,369
 1,305
Depreciation and amortization822
 813
 849
Taxes other than income256
 240
 237
Asset (gains) losses and reserves, net(2) 12
 (6)
Operating Income1,028
 1,002
 1,028
Other (Income) and Deductions260
 298
 317
Income Tax Expense282
 267
 270
Net Income$486
 $437
 $441

Gross marginincreased $127$97 million in 2012 and decreased $118increased $23 million during 2009in 2011. Revenues associated with certain tracking mechanisms and 2008, respectively.surcharges are offset by related expenses elsewhere in the Consolidated Statement of Operations. The following table displaysdetails changes in various gross margin components relative to the comparable prior period:
         
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)
       
             
(in Thousands of MWh) 2009  2008  2007 
          
Electric Sales
            
Residential  14,625   15,492   16,147 
Commercial  18,200   18,920   19,332 
Industrial  9,922   13,086   13,338 
Other  3,229   3,218   3,300 
          
   45,976   50,716   52,117 
Interconnection sales (1)  5,156   3,583   3,587 
          
Total Electric Sales  51,132   54,299   55,704 
          
             
Electric Deliveries
            
Retail and Wholesale  45,976   50,716   52,117 
Electric Customer Choice, including self generators (2)  1,477   1,457   2,239 
          
Total Electric Sales and Deliveries  47,453   52,173   54,356 
          

(1)Represents power that is not distributed by Detroit Edison
(2)Includes deliveries for self generators who have purchased power from alternative energy suppliers to supplement their power requirements

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 2012 2011
 (In millions)
2011 rate case increase and weather effect, net of 2011 RDM$79
 $29
Restoration tracker, discontinued in 2011(47) 27
Securitization bond and tax surcharge25
 (39)
Renewable energy program35
 26
Energy optimization performance incentive(7) 17
Low Income Energy Efficiency Fund revenue deferral4
 (23)
Regulatory mechanisms and other8
 (14)
Increase in gross margin$97
 $23


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.
 2012 2011 2010
 (In thousands of MWh)
Electric Sales     
Residential15,666
 15,907
 15,726
Commercial16,832
 16,779
 16,570
Industrial9,989
 9,739
 10,195
Other958
 3,136
 3,210
 43,445
 45,561
 45,701
Interconnection sales (a)2,125
 3,512
 4,876
Total Electric Sales45,570
 49,073
 50,577
      
Electric Deliveries     
Retail and Wholesale43,445
 45,561
 45,701
Electric Customer Choice, including self generators5,197
 5,445
 5,005
Total Electric Sales and Deliveries48,642
 51,006
 50,706

(a) Represents power that is not distributed by DTE Electric.

12


Operation and maintenanceexpense decreased $45increased $60 million in 20092012 and decreased $100increased $64 million in 2008.2011. The decreaseincrease in 2009 was2012 is primarily due to $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 lowerhigher employee benefit-related expenses, lower stormbenefit expenses of $12$53 million, $9 million of reduced uncollectible expenses and $6 million of reduced maintenance activities, partially offset by higher pension and health care costs of $54 million and $14 million ofincreased energy optimization and renewable energy expenses.expenses of $17 million, higher power plant generation expenses of $12 million, increased distribution operations expenses of $4 million and higher expenses for low income energy assistance of $4 million, partially offset by reduced restoration and line clearance expenses of $22 million and reduced uncollectible expenses of $9 million. The increase in 2011 is primarily due to higher restoration and line clearance expenses of $41 million, higher generation maintenance and outage expenses of $25 million, higher energy optimization and renewable energy expenses of $19 million, higher employee benefit expense of $9 million, partially offset by reduced contributions of $23 million to the Low Income Energy Efficiency Fund due to a court order, and reduced uncollectible expenses of $7 million.

Depreciation and amortization expense increased $9 million in 2012 due primarily to higher amortization of regulatory assets, partially offset by the net effect of lower depreciation rates on a higher depreciable base. Depreciation and amortization expense was $36 million lower in 201l due primarily to reduced amortization of regulatory assets, partially offset by expenses related to a higher depreciable base.

Asset (gains) and losses, reserves and impairments, net decreased $14 million in 2012 and increased $18 million in 2011 principally attributable to a 2011 accrual of $19 million resulting from management's revisions of the timing and estimate of cash flows for the decommissioning of Fermi 1, partially offset by a 2011 revision of $6 million in the timing and estimate of cash flows for the Fermi 1 asbestos removal obligation and other items. See Note 7 of the Notes to the Consolidated Financial Statements.

Other (income) and deductions were lower by $38 million in 2012 and $19 million in 2011. The decrease in 20082012 was due primarily to the lower information systems implementation costscontributions to the DTE Foundation of $60 million, lower employee benefit-related expenses of $45$21 million and $29lower interest expense of $17 million. The 2011 decrease was due to lower interest expense of $24 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 increased $101 million in 2009 due primarily to a higher depreciable base and increased amortization of regulatory assets and decreased $21 million in 2008 due primarily to decreased amortization of regulatory assets.
Taxes other than incomewere lower by $27 million due primarily to a $30 million reduction in property tax expense due to refunds received in settlement of appeals of assessments for prior years. Taxes decreased $45 million in 2008 duecontributions to the Michigan 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.DTE Foundation of $7 million.
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, provided for an uncollectible expense tracking mechanism and a revenue decoupling mechanism will assist in mitigating these impacts.
To address the challenges of the national and regional economies, weOutlook We continue to move forward in our efforts to improve the operating performanceachieve operational excellence, sustained strong cash flows and cash flow of Detroit Edison. We continue to favorably resolve outstanding regulatory issues, many of which were addressed by Michigan legislation.earn our authorized return on equity. We expect that our planned significant environmental and renewable expenditures will result in earnings growth. Looking forward, we face additional issues,factors may impact earnings such as higher levelsweather, the outcome of capital spending, volatility in prices for coal and other commodities,regulatory proceedings, 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.change and electric choice. We expect to continue an intense focus on our continuous improvement efforts to improve productivity remove waste and decrease our costs while improving customer satisfaction.satisfaction with consideration of customer rate affordability.

15


On June 25, 2012, our Fermi 2 nuclear power plant was manually shutdown after one of the plant's two non-safety related feed-water pumps failed. Supported by a detailed analysis, DTE Electric decided to operate the plant with one feed-water pump at a reduced power level until the second feed-water pump is returned to service. The plant was restarted on July 30, 2012 which restored production to 68% of full capacity. We expect that a substantial portion of the property damage will be covered by existing insurance coverage, subject to deductibles. We are able to purchase sufficient power from MISO to continue to provide uninterrupted service to our customers. We plan to seek recovery of the related incremental purchased power costs through the PSCR process. The plant is scheduled to be brought down in the first quarter of 2013 to complete the repair.

Environmental Matters Climate regulation and/or legislation has been proposed and discussed within the U.S. Congress and the EPA. The EPA is implementing regulatory actions under the Clean Air Act to address emissions of greenhouse gases (GHGs). EPA regulation of GHGs requires the best available control technology (BACT) for new major sources or modifications to existing major sources that cause significant increases in GHG emissions. In June 2012, the EPA proposed new source performance standards for carbon dioxide emissions from new fossil-fueled power plants. These new source performance standards are expected to be finalized in 2013 as well as a proposed performance standard for carbon dioxide emissions from existing plants. 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 equipment beyond what is currently planned, financing costs related to additional capital expenditures, the purchase of emission offsets from market sources and the retirement of facilities where control equipment is not economical. 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 DTE Electric or its customers at this time.

13


Item 7A.Quantitative and Qualitative Disclosures aboutItem 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity
Market Price Risk

We have commodity price risk arising from market price fluctuations. We have risks in conjunction with the anticipated purchases of coal, uranium, electricity, and base metals to meet our service obligations. However, the Company doeswe do not bear significant exposure to earnings risk as such changes are included in the PSCR regulatory rate-recovery mechanism. The Company has tracking mechanisms to mitigate a portion of losses related to uncollectible accounts receivable. The Company isWe are exposed to short-term cash flow or liquidity risk as a result of the time differential between actual cash settlements and regulatory rate recovery.

Credit Risk

Bankruptcies

We purchase and sell electricity from and to governmental entities and 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 may have a material effect on our consolidated 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
DTE Electric 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, 20092012 would decrease $171$139 million and increase $186$148 million, respectively.

16



14


Item 8. Financial Statements and Supplementary Data

Item 8.Financial Statements and Supplementary Data
 Page
18
  
Consolidated Financial Statements
 
  
19
  
21
 
  
22
  
24
  
25
  
26
  
Financial Statement Schedule
 
  
73

17



15


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 Detroit Edison’sDTE Electric’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO), 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, 2009,2012, which is the end of the period covered by this report. Based on this evaluation, the Company’s Chief Executive OfficerCEO and Chief Financial OfficerCFO have concluded that such disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controlsforms and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act(ii) is accumulated and communicated to the Company’s management, including its Chief Executive OfficerCEO and Chief Financial Officer,CFO, 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

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Internal control over financial reporting is a process designed by, or under the supervision of, our CEO and CFO, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management of the Company has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009.2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control—Integrated Framework.Based on this assessment, management concluded that, as of December 31, 2009,2012, 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

There have been no changes in the Company’s internal control over financial reporting during the quarter ended December 31, 20092012 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

18



16



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholder of The Detroit EdisonDTE Electric Company


In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of DTE Electric Company (formerly known as The Detroit Edison CompanyCompany) and its subsidiaries at December 31, 2009,2012 and 2011, and the results of their operations and their cash flows for each of the year thenthree years in the period ended December 31, 2012 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 indexpresents 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’sCompany's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit.audits. We conducted our auditaudits 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, 2008 and the related consolidated statements of operations, cash flows, and changes in shareholder’s equity and comprehensive income for the years ended December 31, 2008 and 2007. Our audits also included the 2008 and 2007 information in the financial statement schedules listed in 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, 2008, and the results of their operations and their cash flows for the years 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.

/s/ Deloitte & TouchePricewaterhouseCoopers LLP

Detroit, Michigan
February 27, 200920, 2013

20



17


The Detroit EdisonDTE Electric Company

Consolidated Statements of Operations
             
  Year Ended December 31 
(in Millions) 2009  2008  2007 
Operating Revenues
 $4,714  $4,874  $4,900 
          
             
Operating Expenses
            
Fuel and purchased power  1,491   1,778   1,686 
Operation and maintenance  1,277   1,322   1,422 
Depreciation and amortization  844   743   764 
Taxes other than income  205   232   277 
Asset (gains) losses and reserves, net  (2)  (1)  8 
          
   3,815   4,074   4,157 
          
             
Operating Income
  899   800   743 
          
             
Other (Income) and Deductions
            
Interest expense  325   293   294 
Interest income  (2)  (6)  (7)
Other income  (39)  (51)  (40)
Other expenses  11   47   30 
          
   295   283   277 
          
             
Income Before Income Taxes
  604   517   466 
             
Income Tax Provision
  228   186   149 
          
             
Net Income
 $376  $331  $317 
          

 Year Ended December 31
 2012 2011 2010
 (In millions)
Operating Revenues$5,291
 $5,152
 $4,993
Operating Expenses     
Fuel and purchased power1,758
 1,716
 1,580
Operation and maintenance1,429
 1,369
 1,305
Depreciation and amortization822
 813
 849
Taxes other than income256
 240
 237
Asset (gains) losses and reserves, net(2) 12
 (6)
 4,263
 4,150
 3,965
Operating Income1,028
 1,002
 1,028
Other (Income) and Deductions     
Interest expense272
 289
 313
Interest income(1) 
 (1)
Other income(53) (47) (39)
Other expenses42
 56
 44
 260
 298
 317
Income Before Income Taxes768
 704
 711
Income Tax Expense282
 267
 270
Net Income$486
 $437
 $441

See Notes to Consolidated Financial Statements

21



18


The Detroit EdisonDTE Electric Company

Consolidated Statements of Financial PositionComprehensive Income
         
  December 31 
(in Millions) 2009  2008 
Assets
        
Current Assets
        
Cash and cash equivalents $34  $30 
Restricted cash  79   84 
Accounts receivable (less allowance for doubtful accounts of $118 and $121, respectively)        
Customer  696   709 
Affiliates  3   5 
Other  108   34 
Inventories        
Fuel  135   170 
Materials and supplies  173   169 
Notes receivable        
Affiliates  65   41 
Other  3   3 
Other  79   95 
       
   1,375   1,340 
       
         
Investments
        
Nuclear decommissioning trust funds  817   685 
Other  104   99 
       
   921   784 
       
         
Property
        
Property, plant and equipment  15,451   14,977 
Less accumulated depreciation and amortization  (6,133)  (5,828)
       
   9,318   9,149 
       
         
Other Assets
        
Regulatory assets  3,333   3,456 
Securitized regulatory assets  870   1,001 
Intangible assets  9   19 
Notes receivable — affiliates  17    
Other  118   93 
       
   4,347   4,569 
       
         
Total Assets
 $15,961  $15,842 
       
 2012 2011 2010
 (In millions)
Net income$486
 $437
 $441
Other comprehensive income:     
Benefit obligations, net of tax of $(1), $(2) and $—(2) (4) 
Comprehensive income$484
 $433
 $441

See Notes to Consolidated Financial Statements

22



The Detroit Edison19



DTE Electric Company

Consolidated Statements of Financial Position
         
  December 31 
(in Millions, Except Shares) 2009  2008 
Liabilities and Shareholder’s Equity
        
Current Liabilities
        
Accounts payable        
Affiliates $74  $103 
Other  251   346 
Accrued interest  83   80 
Accrued vacations  48   58 
Short-term borrowings     75 
Current portion long-term debt, including capital leases  660   153 
Other  213   263 
       
   1,329   1,078 
       
         
Long-Term Debt (net of current portion)
        
Mortgage bonds, notes and other  3,579   4,091 
Securitization bonds  793   932 
Capital lease obligations  25   33 
       
   4,397   5,056 
       
         
Other Liabilities
        
Deferred income taxes  1,871   1,894 
Regulatory liabilities  711   593 
Asset retirement obligations  1,285   1,205 
Unamortized investment tax credit  75   85 
Nuclear decommissioning  136   114 
Accrued pension liabilityaffiliates
  987   978 
Accrued postretirement liabilityaffiliates
  1,058   1,075 
Other  239   208 
       
   6,362   6,152 
       
         
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  3,196   2,946 
Retained earnings  693   622 
Accumulated other comprehensive income (loss)  (16)  (12)
       
   3,873   3,556 
       
         
Total Liabilities and Shareholder’s Equity
 $15,961  $15,842 
       
 December 31
 2012 2011
 (In millions)
ASSETS   
Current Assets   
Cash and cash equivalents$30
 $13
Restricted cash, principally Securitization102
 127
Accounts receivable (less allowance for doubtful accounts of $35 and $80, respectively)   
Customer697
 709
Affiliates5
 61
Other63
 76
Inventories   
Fuel246
 264
Materials and supplies193
 183
Notes receivable   
Affiliates
 26
Other2
 2
Regulatory assets162
 272
Other77
 63
 1,577
 1,796
Investments   
Nuclear decommissioning trust funds1,037
 937
Other133
 121
 1,170
 1,058
Property   
Property, plant and equipment17,689
 16,788
Less accumulated depreciation and amortization(6,717) (6,526)
 10,972
 10,262
Other Assets   
Regulatory assets3,348
 3,618
Securitized regulatory assets413
 577
Intangible assets30
 36
Notes receivable3
 4
Other138
 142
 3,932
 4,377
Total Assets$17,651
 $17,493

See Notes to Consolidated Financial Statements

23


20


Table of Contents

The Detroit Edison
DTE Electric Company
Consolidated Statements of Cash FlowsFinancial Position
             
  Year Ended December 31 
(in Millions) 2009  2008  2007 
Operating Activities
            
Net income $376  $331  $317 
Adjustments to reconcile net income to net cash from operating activities:            
Depreciation and amortization  844   743   764 
Deferred income taxes  15   91   (111)
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  1,194   1,281   765 
          
             
Investing Activities
            
Plant and equipment expenditures  (793)  (943)  (809)
Proceeds from sale of assets, net        3 
Restricted cash  5   50   (3)
Notes receivable from affiliate  (42  (41)   
Proceeds from sale of nuclear decommissioning trust fund assets  295   232   286 
Investment in nuclear decommissioning trust funds  (315)  (255)  (323)
Other investments  (46)  (54)  (33)
          
Net cash used for investing activities  (896)  (1,011)  (879)
          
             
Financing Activities
            
Issuance of long-term debt  129   862   50 
Redemption of long-term debt  (278)  (166)  (185)
Repurchase of long-term debt     (238)   
Short-term borrowings, net  (75)  (331)  129 
Short-term borrowings from affiliate     (277)  277 
Capital contribution by parent company  250   175   175 
Dividends on common stock  (305)  (305)  (305)
Other  (15)  (7)  (7)
          
Net cash from (used for) financing activities  (294)  (287)  134 
          
             
Net Increase (Decrease) in Cash and Cash Equivalents
  4   (17)  20 
Cash and Cash Equivalents at Beginning of the Period
  30   47   27 
          
Cash and Cash Equivalents at End of the Period
 $34  $30  $47 
          

 December 31
 2012 2011
 (In millions, except shares)
LIABILITIES AND SHAREHOLDER’S EQUITY   
Current Liabilities   
Accounts payable   
Affiliates$52
 $67
Other350
 421
Accrued interest61
 69
Current portion long-term debt, including capital leases443
 470
Regulatory liabilities66
 80
Short-term borrowings   
Affiliates80
 64
Other130
 
Other166
 230
 1,348
 1,401
Long-Term Debt (net of current portion)   
Mortgage bonds, notes and other4,221
 4,105
Securitization bonds302
 479
Capital lease obligations1
 9
 4,524
 4,593
Other Liabilities   
Deferred income taxes2,761
 2,701
Regulatory liabilities483
 454
Asset retirement obligations1,557
 1,440
Unamortized investment tax credit49
 57
Nuclear decommissioning159
 148
Accrued pension liability  affiliates
1,368
 1,231
Accrued postretirement liability  affiliates
996
 1,217
Other103
 115
 7,476
 7,363
    
Commitments and Contingencies (Notes 8 and 14)   
    
Shareholder’s Equity   
Common stock, $10 par value, 400,000,000 shares authorized, and 138,632,324 shares issued and outstanding3,196
 3,196
Retained earnings1,129
 960
Accumulated other comprehensive income (loss)(22) (20)
 4,303
 4,136
Total Liabilities and Shareholder’s Equity$17,651
 $17,493
See Notes to Consolidated Financial Statements

24




The Detroit Edison21


DTE Electric Company

Consolidated Statements of Changes in Shareholder’s Equity and Comprehensive incomeCash Flows
                         
                  Accumulated    
          Additional      Other    
  Common Stock  Paid in  Retained  Comprehensive    
(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           317      317 
Dividends declared on common stock           (305)     (305)
Net change in unrealized gains on investments, net of tax              1   1 
Capital contribution by parent company        175         175 
 
Balance, December 31, 2007  138,632   1,386   1,385   528   4   3,303 
 
Net income           331      331 
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              (2)  (2)
Benefit obligations, net of tax              (14)  (14)
Capital contribution by parent company        175         175 
 
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) 2009  2008  2007 
Net income $376  $331  $317 
          
Other comprehensive income:            
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 $372  $315  $318 
          
 Year Ended December 31
 2012 2011 2010
 (In millions)
Operating Activities     
Net income$486
 $437
 $441
Adjustments to reconcile net income to net cash from operating activities:     
Depreciation and amortization822
 813
 849
Deferred income taxes(52) 231
 322
Asset (gains) losses and reserves, net(2) 13
 (6)
Changes in assets and liabilities, exclusive of changes shown separately (Note 16)258
 (141) (253)
Net cash from operating activities1,512
 1,353
 1,353
Investing Activities     
Plant and equipment expenditures(1,230) (1,202) (864)
Restricted cash for debt redemption, principally Securitization5
 (3) (25)
Notes receivable from affiliate26
 77
 (21)
Proceeds from sale of nuclear decommissioning trust fund assets97
 80
 377
Investment in nuclear decommissioning trust funds(102) (97) (410)
Other(26) (32) (60)
Net cash used for investing activities(1,230) (1,177) (1,003)
Financing Activities     
Issuance of long-term debt496
 609
 614
Redemption of long-term debt(587) (554) (652)
Short-term borrowings, net130
 
 
Short-term borrowings from affiliate16
 64
 
Dividends on common stock(317) (305) (305)
Other(3) (7) (11)
Net cash used for financing activities(265) (193) (354)
Net Increase (Decrease) in Cash and Cash Equivalents17
 (17) (4)
Cash and Cash Equivalents at Beginning of the Period13
 30
 34
Cash and Cash Equivalents at End of the Period$30
 $13
 $30

See Notes to Consolidated Financial Statements

25




The Detroit Edison22


DTE Electric Company

Consolidated Statements of Changes in Shareholder’s Equity

     Additional   
Accumulated
Other
  
 Common Stock Paid-in Retained Comprehensive  
 Shares Amount Capital Earnings Income (Loss) Total
 (Dollars in millions, shares in thousands)
Balance, December 31, 2009138,632
 1,386
 1,810
 693
 (16) 3,873
Net income
 
 
 441
 
 441
Dividends declared on common stock
 
 
 (305) 
 (305)
Balance, December 31, 2010138,632
 1,386
 1,810
 829
 (16) 4,009
Net income
 
 
 437
 
 437
Dividends declared on common stock
 
 
 (306) 
 (306)
Benefit obligations, net of tax
 
 
 
 (4) (4)
Balance, December 31, 2011138,632
 $1,386
 $1,810
 $960
 $(20) $4,136
Net income
 
 
 486
 
 486
Dividends declared on common stock
 
 
 (317) 
 (317)
Benefit obligations, net of tax
 
 
 
 (2) (2)
Balance, December 31, 2012138,632
 $1,386
 $1,810
 $1,129
 $(22) $4,303

See Notes to Consolidated Financial Statements


23


DTE Electric Company

Notes to Consolidated Financial Statements
NOTE 1 — BASIS OF PRESENTATION

Corporate Structure
The Detroit Edison Company (Detroit Edison)
DTE Electric is a Michigan publican electric utility engaged in the generation, purchase, distribution and sale of electric energyelectricity to approximately 2.1 million customers in southeastern Michigan. Detroit EdisonDTE Electric is regulated by the MPSC and the FERC. In addition, we are regulated by other federal and state regulatory agencies including the NRC, the EPA and the MDEQ.
References in this report to “we,” “us,’ “our’ “our” or “Company” are to Detroit EdisonDTE Electric and its subsidiaries, collectively.

Basis of Presentation

The accompanying consolidated financial statementsConsolidated 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’syear's financial statement presentation.

Principles of Consolidation

The Company consolidates all majority ownedmajority-owned subsidiaries and investments in entities in which it has controlling influence. Non-majority owned investments are accounted for using the equity method when the Company is able to influence the operating policies of the investee. Non-majority owned investments include investments in limited liability companies, partnerships or joint ventures. When the 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. The Company eliminates all intercompany balances and transactions.

The Company evaluates whether an entity is a VIE whenever reconsideration events occur. The Company consolidates variable interest entities (VIEs)VIEs for which we are the primary beneficiary. In general, the Company determines whether it is the primary beneficiary. If the Company is not the primary beneficiary and an ownership interest is held, the VIE is accounted for under the equity method of a VIE through a qualitative analysis of risk which indentifies which variable interest holder absorbsaccounting. When assessing the majoritydetermination of the financial risk or rewards and variability of the VIE. In performing this analysis,primary beneficiary, the Company considers all relevant facts and circumstances, including: the design andpower, through voting or similar rights, to direct the activities of the VIE that most significantly impact the termsVIE’s economic performance and the obligation to absorb the expected losses and/or the right to receive the expected returns of the contractsVIE. The Company performs ongoing reassessments of all VIEs to determine if the VIEprimary beneficiary status has entered into,changed.

The Company has variable interests in VIEs through certain of its long-term purchase contracts. As of December 31, 2012, the identificationcarrying amount of variable interest holders including equity owners, customers, suppliersassets and debt holders and which parties participated significantlyliabilities in the designConsolidated Statements of Financial Position that relate to its variable interests under long-term purchase contracts are predominately related to working capital accounts and generally represent the amounts owed by the Company for the deliveries associated with the current billing cycle under the contracts. The Company has not provided any form of financial support associated with these long-term contracts. There is no significant potential exposure to loss as a result of its variable interests through these long-term purchase contracts.

In 2001, DTE Electric financed a regulatory asset related to Fermi 2 and certain other regulatory assets through the sale of rate reduction bonds by a wholly-owned special purpose entity, Securitization. DTE Electric performs servicing activities including billing and collecting surcharge revenue for Securitization. This entity is a VIE, and is consolidated by the Company. The maximum risk exposure related to Securitization is reflected on the Company’s Consolidated Statements of Financial Position.

The following table summarizes the major balance sheet items at December 31, 2012 and 2011 restricted for Securitization that are either (1) assets that can be used only to settle their obligations or (2) liabilities for which creditors do not have recourse to the general credit of the entity. If the qualitative analysis is inconclusive, a specific quantitative analysis is performed. Referprimary beneficiary.


24

Table of Contents

 December 31, December 31,
 2012 2011
 (In millions)
ASSETS   
Restricted cash$102
 $107
Accounts receivable34
 34
Securitized regulatory assets413
 577
Other assets7
 10
 $556
 $728
    
LIABILITIES   
Accounts payable and accrued current liabilities$11
 $14
Other current liabilities50
 55
Current portion long-term debt, including capital leases177
 164
Securitization bonds302
 479
Other long term liabilities7
 7
 $547
 $719

As of December 31, 2012 and December 31, 2011, DTE Electric had $3 million and $4 million in Notes receivable, related to Note 3 for discussion of changes in consolidation guidance applicable tonon-consolidated VIEs, and Note 16 for discussion of the Company’s involvement with VIE’s.respectively.

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

Revenues

Revenues from the sale and delivery of electricity are recognized as services are provided. We recordThe Company records revenues for electricelectricity provided but unbilled at the end of each month. Detroit Edison’s accruedRates for DTE Electric include provisions to adjust billings for fluctuations in fuel and purchased power costs, and certain other costs. Revenues are adjusted for differences between actual costs subject to reconciliation and the amounts billed in current rates. Under or over recovered revenues include a component forrelated to these cost recovery mechanisms are recorded on the costConsolidated Statements of power sold that is recoverableFinancial Position and are recovered or returned to customers through adjustments to the PSCR mechanism. Annual PSCR proceedings before the MPSC permit Detroit Edison to recover prudent and reasonable supply costs. Any over-collection or under-collection of costs, including interest, will be reflected in future rates. billing factors.

See Note 10.8 for further discussion of recovery mechanisms authorized by the MPSC.

Accounting for ISO Transactions
Detroit Edison
DTE Electric participates in the energy market through MISO. MISO requires that we submit hourly day-ahead, realreal- time and FTR bids and offers for energy at locations across the MISO region. Detroit EdisonDTE Electric accounts for MISO

26


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 recordIn any single hour DTE Electric records net purchases in a single hour in fuel,Fuel and purchased power and gas and net sales in a single hour in operatingOperating revenues inon the Consolidated Statements of Income. We recordOperations. DTE Electric records net sale billing adjustments when we receive invoices. We recordinvoices are received. DTE Electric records expense accruals for future net purchases adjustments basebased on historical experience, and reconcilereconciles accruals to actual expenses when we receive invoices.invoices are received from MISO.

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 Otheraccumulated other comprehensive incomeloss for the year ended December 31, 2009 include unrealized gains and losses from derivatives accounted for as cash flow hedges, unrealized gains and losses on available for sale securities, and2012 reflected changes in benefit obligations.
             
          Accumulated 
          Other 
  Benefit      Comprehensive 
(in Millions) Obligations  Other  Loss 
Beginning balances $(14) $2  $(12)
Current period change  (2)  (2)  (4)
          
Ending balance $(16) $  $(16)
          
 Benefit 
Accumulated
Other
Comprehensive
 Obligations Loss
 (In millions)
Beginning balance January 1, 2012$(20) $(20)
Current period change(2) (2)
Ending balance December 31, 2012$(22) $(22)


25


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.agreements, related to Securitization bonds. 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 generally calculated using the aging approach that utilizes rates developed in reserve studies. We establishDTE Electric establishes 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, which is typically in 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 yearexhausted. The time period for write-off was changed in 2012 from 365 days to 150 days after service has been terminated.

Unbilled revenues of $269$275 million and $282$264 million are included in customer accounts receivable at December 31, 20092012 and 2008,2011, respectively.

Notes Receivable

Notes receivable, or financing receivables, are primarily comprised of loans and are typically considered delinquent when payment is not received for periods ranging from 60 to 120 days. The Company ceases accruing interest (nonaccrual status), considers a note receivable impaired, and establishes an allowance for credit loss when it is probable that all principal and interest amounts due will not be collected in accordance with the contractual terms of the note receivable. Cash payments received on nonaccrual status notes receivable, that do not bring the account contractually current, are first applied to contractually owed past due interest, with any remainder applied to principal. Accrual of interest is generally resumed when the note receivable becomes contractually current.

In determining the allowance for credit losses for notes receivable, we consider the historical payment experience and other factors that are expected to have a specific impact on the counterparty’s ability to pay. In addition, the Company monitors the credit ratings of the counterparties from which we have notes receivable.

Inventories

The Company generally values inventory at average cost.

Property, Retirement and Maintenance, and Depreciation, Depletion and Amortization

Property is stated at cost and includes construction-related labor, materials, overheads and an allowance for funds used during construction (AFUDC). The cost of properties retired less salvage value is charged to accumulated depreciation. Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2.

Utility property is depreciated over its estimated useful life using straight-line rates approved by the MPSC.

Depreciation and amortization expense also includes the amortization of certain regulatory assets.

Approximately $13$12 million and $25$23 million of expenses related to Fermi 2 refueling outages were accrued at December 31, 20092012 and December 31, 2008,2011, respectively. Amounts are accrued on a pro-rata basis, generally over an 18-

27


month18-month period, that 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. See Note 8.

The Company bases depreciation provisions for utility property on straight-line rates approved by the MPSC.
cost of nuclear fuel is capitalized. The average estimated useful life for our generation and distribution property was 40 years and 37 years, respectively, at December 31, 2009.
The Company credits depreciation, depletion and amortization expense when we establish regulatory assets for plant-related costs such as depreciation or plant-related financing costs. The Company charges depreciation, depletion and amortization expense when we amortize these regulatory assets. The Company credits interest expense to reflect the accretion income on certain regulatory assets.
Capitalized software is classified as Property, plant and equipment and the related amortizationof nuclear fuel is included within Fuel and purchased power in Accumulated depreciation on the Consolidated Statements of Financial Position. The Company capitalizesOperations and is recorded using the costs associated with computer software the Company develops or obtains for use in our business. The Company amortizes Intangible assets on a straight-line basis over the expected periodunits-of-production method.


26


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 discounted 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 costs to sell.

Intangible Assets

The Company has certain intangible assets relating to emission allowances.allowances and renewable energy credits. Emission allowances and renewable energy credits are charged to fuel expense, using average cost, as the allowances and credits are consumed in the operation of the business. The Company’s intangible assets related to emission allowances were $6 million at December 31, 2012 and $9 million at December 31, 2011. The Company’s intangible assets related to renewable energy credits were $44 million and $39 million at December 31, 2012 and December 31, 2011, respectively.

Excise and Sales Taxes

The Company records the billing of excise and sales taxes as a receivable with an offsetting payable to the applicable taxing authority, with no net 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.

Investments in Debt and Equity Securities

The Company generally classifies investments in debt 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 earnings or in other comprehensive income or loss, respectively. Changes in the fair value of Fermi 2 nuclear decommissioning investments are recorded as adjustments to regulatory assets or liabilities, due to a recovery mechanism from customers. The Company’s equity 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 equity investment being written down to its estimated fair value. See Note 4.3.

28



Stock-Based Compensation

The Company received an allocation of costs from DTE Energy associated with stock-based compensation. Our allocation for 2009, 20082012, 2011 and 20072010 for stock-based compensation expense was approximately $24$42 million $15, $30 million and $13$23 million, respectively.
Asset (gains) losses
Government Grants

Grants are recognized when there is reasonable assurance that the grant will be received and reserves, net
In 2007, we recorded a $13 million reserve for a loan guarantythat any conditions associated with the grant will be met. When grants are received related to Detroit Edison’s former ownershipProperty, Plant and Equipment, the Company reduces the basis of a steam heating business now owned by Thermal Ventures II, LP (Thermal)the assets on the Consolidated Statements of Financial Position, resulting in lower depreciation expense over the life of the associated asset. Grants received related to expenses are reflected as a lossreduction of the associated expense in the period in which was partially offset by approximately $5 million in gains on land and other sales.the expense is incurred.
Subsequent Events

The Company has evaluated subsequent events through February 23, 2010, the date that these financial statements were issued.
27


Other Accounting Policies

See the following notes for other accounting policies impacting our financial statements:
Note Title
3New Accounting Pronouncements
4
 Fair Value
54
 Financial and Other Derivative Instruments
7
 Asset Retirement Obligations
108
 Regulatory Matters
119
 Income Taxes
1715
 Retirement Benefits and Trusteed Assets

29



NOTE 3 — 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 ASC 820 (SFAS No. 157,Fair Value Measurements). The 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. 124-2),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

30


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, 2008, with early application encouraged. Comparative disclosures for earlier periods at initial adoption are encouraged but not required. The Company adopted the standard effective January 1, 2009. See Note 5.
Subsequent Events
In May 2009, the FASB issued ASC 855 (SFAS No. 165,Subsequent Events). This standard provides 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 be issued.” Management must perform its assessment for both interim and annual financial reporting periods. The standard does not significantly change the Company’s practice for evaluating such events. 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, 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 ASU 2009-16 (SFAS No. 166) 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 consolidated financial statements.
Fair Value Measurements and Disclosures
In September and August 2009, respectively, the FASB 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 measurement 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 transaction prices from principal-to-principal or brokered transactions will not be considered in measuring the fair value of the investment. The amendments in this standard are effective for interim and annual periods ending after December 15, 2009.

31


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.
In 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. 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 for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010, with earlier application permitted. Alternatively, an entity may elect to adopt this standard on a retrospective basis. The Company is currently assessing the impact of Issue No. 08-1 on Detroit Edison’s consolidated financial statements. Adoption of this standard is not expected to have a material impact to the consolidated financial statements.

32


NOTE 4 — FAIR VALUE

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’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 and its counterparties is incorporated in the valuation of assets and liabilities through the use of credit reserves, the impact of which iswas immaterial for the years endedat December 31, 20092012 and 2008.December 31, 2011. The Company believes 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, whichthat prioritizes the inputs to 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 classifies fair value balances based on the fair value hierarchy defined as follows:

Level 1 — Consists of unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access as of the reporting date.
Level 2 — Consists 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.
Level 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 cost-benefit constraints.

28


The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2009:2012 and 2011:
                 
              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 
             
 December 31, 2012 December 31, 2011
 Level 1 Level 2 Level 3 Net Balance Level 1 Level 2 Level 3 Net Balance
 (In millions)
Assets:               
Cash equivalents (a)$
 $116
 $
 $116
 $
 $129
 $
 $129
Nuclear decommissioning trusts694
 343
 
 1,037
 577
 360
 
 937
Other investments (b)64
 44
 
 108
 55
 38
 
 93
Derivative assets — FTRs
 
 1
 1
 
 
 1
 1
Total$758
 $503
 $1
 $1,262
 $632
 $527
 $1
 $1,160
                
Assets:               
Current$
 $116
 $1
 $117
 $
 $129
 $1
 $130
Noncurrent758
 387
 
 1,145
 632
 398
 
 1,030
Total Assets$758
 $503
 $1
 $1,262
 $632
 $527
 $1
 $1,160

33

(a)
At December 31, 2012 available for sale securities of $116 million, included $102 million and $14 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively. At December 31, 2011 available for sale securities of $129 million, included $113 million and $16 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively.
(b)
Available for sale equity securities at December 31, 2012 and December 31, 2011 of $5 million and $4 million are included in Other investments on the Consolidated Statements of Financial Position, respectively.


The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 20092012 and 2008:2011:
         
  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  $ 
       
Transfers in/out of Level
 
Year Ended
December 31
 2012 2011
 (In millions)
Net Assets as of January 1$1
 2
Change in fair value recorded in regulatory assets/liabilities15
 2
Purchases, issuances and settlements:   
Settlements(15) (3)
Net Assets as of December 31$1
 $1
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, 2012 and 2011$1
 $1

No transfers between Levels 1, 2 or 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 inputsyears ended December 31, 2012 and an increased reliance on broker quotes for certain transactions.December 31, 2011.

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 short-term investments inand money market funds. The fair values of the shares ofin these fundsinvestments are based onupon observable market prices for similar securities and, therefore, have been categorized as Level 12 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 onin 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 EdisonThe Company has obtained an understanding of how these

29


prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Detroit Edisonthe Company 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

34


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 debtfinancial instruments included in the table below is determined by using quoted market prices when available. When quoted prices are not available, and a discountedpricing services may be used to determine the fair value with reference to observable interest rate indexes. The Company has obtained an understanding of how the fair values are derived. The Company also selectively corroborates the fair value of its transactions by comparison of market-based price sources. Discounted cash flow analysisanalyses based upon estimated current borrowing rates are also used to determine fair value when quoted market prices are not available. The table below showsfair values of notes receivable, excluding capital leases, are estimated using discounted cash flow techniques that incorporate market interest rates as well as assumptions about the fair value relativeremaining life of the loans and credit risk. Depending on the information available, other valuation techniques may be used that rely on internal assumptions and models. Valuation policies and procedures are determined by the Company's Treasury Department which reports to the carrying value for long-term debt securities. Certain other financial instruments, such as notes payable, customer depositsCompany's Vice President 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.Treasurer.
December 31, 2009December 31, 2008
Fair ValueCarrying ValueFair ValueCarrying Value
Long-Term Debt$5.2 billion$5.0 billion$5.0 billion$5.2 billion
Investments in Debt and Equity Securities
The Company generally classifies investments in debtfollowing table presents the carrying amount 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 earnings or in other comprehensive income or loss, respectively. Changes in the fair value of Fermi 2 nuclear decommissioning investments are recordedfinancial instruments as adjustments to regulatory assets or liabilities, due to a recovery mechanism from customers. The 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.of December 31, 2012 and December 31, 2011:
 December 31, 2012 December 31, 2011
 Carrying Fair Value Carrying Fair
 Amount Level 1 Level 2 Level 3 Amount Value
 (In millions)
Notes receivable, excluding capital leases$5
 $
 $
 $5
 $6
 $6
Notes receivable — affiliates
 
 
 
 26
 26
Short-term borrowings — affiliates80
 
 
 80
 64
 64
Short-term borrowings — other130
 
 130
 
 
 
Long-term debt4,963
 
 5,021
 620
 5,051
 5,740

Nuclear Decommissioning Trust Funds
Detroit Edison
DTE Electric 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. See Note 8 for additional information.
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 EdisonDTE Electric 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 costSee Note 7.


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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:
         
  December 31  December 31 
(in Millions) 2009  2008 
Fermi 2 $790  $649 
Fermi 1  3   3 
Low level radioactive waste  24   33 
       
Total $817  $685 
       

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 December 31 December 31
 2012 2011
 (In millions)
Fermi 2$1,021
 $915
Fermi 13
 3
Low level radioactive waste13
 19
Total$1,037
 $937

At December 31, 2009,2012, investments in the nuclear decommissioning trust funds consisted of approximately 51%61% in publicly traded equity securities, 48%38% in fixed debt instruments and 1% in cash equivalents. At December 31, 2008,2011, investments in the nuclear decommissioning trust funds consisted of approximately 42%57% in publicly traded equity securities, 57%41% in fixed debt instruments and 1%2% in cash equivalents. The debt securities at both December 31, 20092012 and December 31, 20082011 had an average maturity of approximately 5 years.6 and 7 years, respectively.

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
  2009 2008 2007
(in Millions)          
Realized gains $37  $34  $25 
Realized losses $(55) $(49) $(17)
Proceeds from sales of securities $295  $232  $286 
 
Year Ended
December 31
 2012 2011 2010
 (In millions)
Realized gains$37
 $46
 $192
Realized losses$(31) $(38) $(83)
Proceeds from sales of securities$97
 $80
 $377

Realized gains and losses from the sale of securities for the Fermi 2 and the low level radioactive waste funds are recorded to the asset retirement obligation regulatoryRegulatory asset and nuclearNuclear decommissioning liability. The following table sets forth the fair value and unrealized gains for the nuclear decommissioning trust funds:
         
(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 
       
 December 31, 2012 December 31, 2011
 Fair Unrealized Fair Unrealized
 Value Gains Value Gains
 (In millions)
Equity securities$631
 $122
 $533
 $80
Debt securities399
 27
 385
 22
Cash and cash equivalents7
 
 19
 
 $1,037
 $149
 $937
 $102

Securities held in the nuclear decommissioning trust funds are classified as available-for-sale. As Detroit EdisonDTE Electric 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 other than temporary impairments.
Impairment charges for unrealized
Unrealized losses incurred by the Fermi 2 trust are recognized as a regulatoryRegulatory asset. Detroit EdisonDTE Electric recognized $48$44 million and $92$67 million of unrealized losses as regulatoryRegulatory assets at December 31, 20092012 and 2008,2011, respectively. Since the decommissioning of Fermi 1 is funded by Detroit EdisonDTE Electric 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. There were no impairment charges unrealized losses recognized in 20092012, 2011 and 20082010 for Fermi 1. Detroit Edison recognized impairment charges of $0.2 million for Fermi 1 for the year ended December 31, 2007.
Other Available-For-Sale
Available-for-sale Securities
The following table summarizes the fair value of the 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, 20092012 and 2008,2011, these securities are comprised primarily of money-market and equity securities. During the year ended December 31, 2012 and December 31, 2011 no amounts of unrealized losses on available for sale securities were reclassified out of other comprehensive income into net income for the periods. Gains (losses) related to trading securities held at December 31, 2009, 2008,2012, 2011, and 20072010 were $8$9 million $(14), $3 million and $3$7 million, respectively.

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31


NOTE 54 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

The Company recognizes all derivatives at their fair value 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’sCompany'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 EdisonDTE Electric generates, purchases, distributes and sells electricity. Detroit EdisonDTE Electric 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, 2009:2012 and 2011:
         
  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)
        
 December 31
 2012 2011
 (In millions)
FTRs — Other current assets$1
 $1
Total derivatives not designated as hedging instrument$1
 $1

The effect of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position were $15 million in gains related to FTRs recognized in Regulatory liabilities for the year ended December 31, 2009 is as follows:2012, and $3 million in gains related to FTRs recognized in Regulatory liabilities for the year ended December 31, 2011.
         
      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)
        

37


The following represents the cumulative gross volume of derivative contracts outstanding as of December 31, 2009:2012:
CommodityNumber of Units
Emissions (Tons)FTRs (MWh)49,41161,927
FTRs (MW)4,486

NOTE 65 — 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
 2012 2011
Property, Plant and Equipment(In millions)
Generation$10,383
 $9,785
Distribution7,306
 7,003
Total17,689
 16,788
Less Accumulated Depreciation and Amortization   
Generation(3,880) (3,946)
Distribution(2,837) (2,580)
Total(6,717) (6,526)
Net Property, Plant and Equipment$10,972
 $10,262

The Allowance for Funds used During Construction (AFUDC) capitalized during 20092012 and 20082011 was approximately $12$19 million and $44$9 million, respectively.

The composite depreciation rate for Detroit EdisonDTE Electric was approximately 3.3% in 2009, 20082012, 2011 and 2007.2010.


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The average estimated useful life for our generation and distribution property was 40 years and 3741 years, respectively, at December 31, 2009.2012.

Capitalized software costs are classified as Property, plant and equipment and the related amortization is included in Accumulated depreciation and amortization on the Consolidated Statements of Financial Position. The Company capitalizes the costs associated with computer software it develops or obtains for use in its business. The Company amortizes capitalized software costs on a straight-line basis over the expected period of benefit, ranging from 5 to 15 years.

Capitalized software costs amortization expense was $55$62 million in 2009, $452012, $58 million in 2008,2011 and $31$55 million in 2007.2010. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 20092012 were $488$479 million and $161$245 million, respectively. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 20082011 were $454$501 million and $126$218 million, respectively. Amortization expense of capitalized software costs is estimated to be $60approximately $40 million annually for 20102013 through 2014.2017.

Gross property under capital leases was $121$6 million and $26 million at December 31, 20092012 and December 31, 2008.2011, respectively. Accumulated amortization of property under capital leases was $88$3 million and $80$14 million at December 31, 20092012 and December 31, 2008,2011, respectively.

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NOTE 76 — JOINTLY OWNED UTILITY PLANT
Detroit Edison
DTE Electric has joint ownership interest in two power plants, Belle River and Ludington Hydroelectric Pumped Storage. Detroit Edison’sDTE Electric’s share of direct expenses of the jointly owned plants are included in Fuel and 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, 20092012 was as follows:
         
      Ludington
      Hydroelectric
  Belle River Pumped Storage
In-service date  1984-1985   1973 
Total plant capacity  1,260 MW  1,872 MW
Ownership interest   *  49%
Investment (in Millions) $1,626  $197 
Accumulated depreciation (in Millions) $889  $128 
    
Ludington
Hydroelectric
 Belle River Pumped Storage
In-service date1984-1985
  1973
 
Total plant capacity1,270
MW  1,872
MW 
Ownership interest (a) 49% 
Investment (in millions)$1,661
  $199
 
Accumulated depreciation (in millions)$953
  $164
 

(a)Detroit Edison’s
DTE Electric’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.

39



NOTE 87 — ASSET RETIREMENT OBLIGATIONS

The Company has a legal retirement obligation for the decommissioning costs for its Fermi 1 and Fermi 2 nuclear plants.plants, dismantlement of facilities located on leased property and various other operations. The Company has conditional retirement obligations for disposal of asbestos and PCB removal at certain of its power plants. To a lesser extent, the Company has conditional retirement obligations at certain service centersplants and disposal costs for PCB contained within transformers and circuit breakers.various distribution equipment. 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 defersrecognizes regulatory assets or liabilities for timing differences that arise in the expense recognition offor legal asset retirement costs that are currently recovered in rates.
No liability has been recorded with respect to lead-based paint, as the quantities

33


If a reasonable estimate of fair value cannot be made in the Company’s facilities are unknown. In addition, thereperiod in which the retirement obligation is no incremental cost to demolitionsincurred, such as for assets with indeterminate lives, the liability is recognized when a reasonable estimate 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.fair value can be made. 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 20092012 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
 (In millions)
Asset retirement obligations at January 1, 2012$1,442
Accretion91
Revision in estimated cash flows2
Liabilities incurred26
Liabilities settled(4)
Asset retirement obligations at December 31, 2012$1,557

In 2001, DTE Electric began the final decommissioning of Fermi 1, with the goal of removing the remaining radioactive material and terminating the Fermi 1 license. In 2011, based on management decisions revising the timing and estimate of cash flows, DTE Electric accrued an additional $19 million with respect to the decommissioning of Fermi 1. Management has a legal obligation to decommission its nuclear power plants followingsuspended decommissioning activities and placed the expiration of their operating licenses. This obligation is reflected as an asset retirement obligationfacility in safe storage status. The expense amount has been recorded in Asset (gains) and losses, reserves and impairments, net on the Consolidated Statements of Financial Position. BasedOperations. In addition, in 2011, based on updated studies revising the timing and estimate of cash flows, a reduction of approximately $20 million was made to the DTE Electric asset retirement obligation for asbestos removal with approximately $6 million of the decrease associated with Fermi 1 recorded in Asset (gains) and losses, reserves and impairments, net on the actual or anticipated extended lifeConsolidated Statements of Operations.
In October 2011, the MPSC approved DTE Electric's request for a reduction to the nuclear decommissioning surcharge under the assumption that it would request an extension of the nuclear plant, decommissioning expenditures for Fermi 2 are expectedlicense for an additional 20 years beyond the term of the existing license which expires in 2025. DTE Electric expects to be incurred primarily duringrequest the periodlicense extension in 2014. This proposed extension of 2025 through 2050.the license, including the associated impact on spent nuclear fuel, resulted in a revision in estimated cash flows for the Fermi 2 asset retirement obligation of approximately $22 million in 2011. It is estimated that the cost of decommissioning Fermi 2 when its license expiresis $1.5 billion in 2025, will be $1.3 billion in 20092012 dollars and $3.4$10 billion in 20252045 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$1.5 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 minimum 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 EdisonDTE Electric 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.decommissioning. 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 returning the clean-up of the Fermi site.site to greenfield. This removal and

40


clean-up greenfielding 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.DTE Electric. Contributions to the Fermi 1 trust are discretionary. See Note 43 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

41


NOTE 108 — REGULATORY MATTERS
Regulation
Detroit EdisonRegulation

DTE Electric 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 EdisonDTE Electric 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.

34


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.

Regulatory Assets and Liabilities
Detroit Edison
DTE Electric 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 
       

42


 2012 2011
Assets(In millions)
Recoverable pension and postretirement costs:   
Pension$1,815
 $1,656
Postretirement costs316
 582
Asset retirement obligation424
 420
Recoverable Michigan income taxes253
 270
Recoverable income taxes related to securitized regulatory assets226
 316
Accrued PSCR revenue87
 147
Cost to achieve Performance Excellence Process82
 100
Other recoverable income taxes76
 81
Choice incentive mechanism66
 166
Recoverable restoration expense49
 58
Unamortized loss on reacquired debt37
 36
Enterprise Business Systems costs16
 18
Other63
 40
 3,510
 3,890
Less amount included in current assets(162) (272)
 $3,348
 $3,618
Securitized regulatory assets$413
 $577
Liabilities   
Renewable energy$230
 $192
Refundable revenue decoupling / deferred gain127
 127
Asset removal costs81
 73
Over recovery of Securitization54
 53
Energy Optimization26
 24
Fermi 2 refueling outage12
 23
Refundable uncollectible expense10
 13
Low Income Energy Efficiency Fund
 23
Other9
 6
 549
 534
Less amount included in current liabilities(66) (80)
 $483
 $454

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’sDTE Electric's rate base, thereby providing a return on invested costs.costs (except as noted). Certain other regulatory assets are not included in rate base but accrue recoverable carrying charges until surcharges to collect the assets are billed. 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.


35


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.

Recoverable pension and postretirement costs — Accounting rules for pension and postretirement benefit costs require, 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 impact of actuarial gains and losses and prior service costs 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 amortized and recognized as components of net periodic benefit costs. (a)
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. (a)
Recoverable Michigan income taxes In July 2007, the MBT was enacted by the State of Michigan. A State deferred tax liability was established, and an offsetting regulatory asset was recorded as the impact of the deferred tax liability will be reflected in rates as the related taxable temporary difference reverses and flows through current income tax expense. In May 2011, the MBT was repealed and the MCIT was enacted. The regulatory asset was remeasured to reflect the impact of the MCIT tax rate. (a)
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. (a)
Accrued PSCR revenue — Receivable for the temporary under-recovery of and a return on fuel and purchased power costs incurred by DTE Electric 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 are amortized over a ten-year period beginning with the year subsequent to the year the costs were deferred.
Other recoverable income taxes — Income taxes receivable from DTE Electric customers representing the difference in property-related deferred income taxes and amounts previously reflected in DTE Electric's rates. This asset will reverse over the remaining life of the related plant. (a)
Choice incentive mechanism (CIM) — Receivable for non-fuel revenues lost as a result of fluctuations in electric Customer Choice sales. The CIM was terminated in the October 20, 2011 MPSC order issued to DTE Electric.
Recoverable restoration expense — Receivable for the MPSC approved restoration expense tracking mechanism that tracks the difference between actual restoration expense and the amount provided for in base rates, recognized pursuant to MPSC authorization. The restoration expense tracking mechanism was terminated in the October 20, 2011 MPSC order issued to DTE Electric.
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.
Enterprise Business Systems (EBS) costs — The MPSC approved the deferral and amortization over ten years beginning in January 2009 of EBS costs that would otherwise be expensed.
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)(a)Regulatory assets not earning a return.return or accruing carrying charges.

43



LIABILITIES

LIABILITIESRenewable energy — Amounts collected in rates in excess of renewable energy expenditures.
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.
Refundable revenue decoupling/deferred gain — At December 31, 2011, amounts were accrued as refundable to DTE Electric customers for the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established by the MPSC. In 2012, the revenue decoupling liability was reversed and a new regulatory liability representing DTE Electric's obligation to refund the resulting gain was accrued. See further discussion below.
Asset removal costs — The amount collected from customers for the funding of future asset removal activities.
Over recovery of Securitization — Over recovery of securitization bond expenses.
Energy Optimization (EO) — Amounts collected in rates in excess of energy optimization expenditures.
Fermi 2 refueling outage — Accrued liability for refueling outage at Fermi 2 pursuant to MPSC authorization.
Refundable uncollectible expense (UETM) Liability for the MPSC approved uncollectible expense tracking mechanism that tracks the difference in the fluctuation in uncollectible accounts and amounts recognized pursuant to the MPSC authorization. The UETM was terminated in the October 20, 2011 MPSC order issued to DTE Electric.

36


Low Income Energy Efficiency Fund(LIEEF) — Escrow of LIEEF funds collected by DTE Electric as ordered by the MPSC pursuant to July 2011 Michigan Court of Appeals decision.

2009 Electric Rate Case Filing- Court of Appeals Decision

On April 10, 2012, the Michigan Court of Appeals (COA) issued a decision relating to an appeal of the January 11, 2010 MPSC order in DTE Electric's January 2009 rate case filing.

The COA found that the record of evidence in the 2009 rate case order was insufficient to support the MPSC's authorization to recover costs for the pilot advanced metering infrastructure (AMI) program and remanded this matter to the MPSC. The MPSC had approved $37 million of rate base related to the AMI program in the January 2010 order. DTE Electric is currently operating its AMI program pursuant to the MPSC's approval set forth in its October 20, 2011 order, which was not reviewed by or subject to the COA's April 10, 2012 decision. On November 28, 2012, DTE Electric filed the necessary data and evidence to the MPSC supporting the AMI program expenditures. DTE Electric's AMI program expenditures are $110 million as of December 31, 2012, net of Department of Energy matching grant funds of $60 million.

The Court affirmed the use of a number of tracking mechanisms (restoration, line clearance, uncollectibles expense and choice incentive) and the peak demand computations approved in the January 2010 order. The COA also determined that the MPSC only had statutory authority to implement a Revenue Decoupling Mechanism (RDM) for gas providers, but not for electric providers, thereby reversing the MPSC's decision to authorize an RDM for DTE Electric. DTE Electric had accrued a total of $127 million of RDM refund liabilities for the 2010 and 2011 RDM reconciliation periods. No party appealed the COA decision regarding the RDM determination.

On August 1, 2012, DTE Electric filed an application for approval of accounting authority to defer for future amortization the gain resulting from the reversal of the Company's $127 million regulatory liability associated with the operation of the RDM. On August 14, 2012, the MPSC dismissed DTE Electric's initial pilot RDM reconciliation case. On September 25, 2012, 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. Includedapproving the Company's accounting application. As described in the approvedaccounting application, DTE Electric will amortize the new regulatory liability to income, at a monthly rate of approximately $10.6 million, beginning January 2014. It is currently anticipated that with this accounting treatment, along with other cost saving measures, DTE Electric will not need to increase in revenues was a return on equity of 11% on an expected 49% equitybase rates until 2015. If DTE Electric's base rates are increased prior to January 1, 2015, the Company will cease amortization and 51% debt capital structure. Sincerefund to customers 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 portionremaining unamortized balance of the estimated refund due customers, including interest. The MPSC ordered Detroit Edison to file a refund plan by April 1, 2010.new regulatory liability.
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;

44


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 (EO) Plans
In March 2009, Detroit Edison filed an Energy Optimization Plan with the MPSC as required under 2008 PA 295.
The Energy Optimization Plan applicationEO plan is designed to help each customer class reduce their electric usage by: (1)1) building customer awareness of energy efficiency options and (2)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

In May 2012, DTE Electric filed an application for approval of its reconciliation of its 2011 EO plan expenses. On October 31, 2012, the MPSC approved DTE Electric's reconciliation. The MPSC order also approved performance incentive surcharges for DTE Electric of $8.4 million to be applied to customer bills rendered on and after January 1, 2013.

In August 2012, DTE Electric filed an amended EO plan with the MPSC. The plan application proposed energy optimizationthe recovery of EO expenditures for the period 2009-20112013-2015 of $134$224 million and further requestsrequested approval of surcharges that are designeda surcharge to recover these costs. On December 20, 2012, the MPSC approved DTE Electric's EO plan.

DTE Electric Restoration Expense Tracker Mechanism (RETM) and Line Clearance Tracker (LCT) Reconciliation

In January 2012, DTE Electric filed an application with the MPSC for approval of the reconciliation of its 2011 RETM and LCT. The Company's 2011 restoration expenses were higher than the amount provided in rates. Accordingly, DTE Electric requested net recovery of approximately $44 million. An MPSC order was issued June 2, 2009 approvingis expected in the Energy Optimization Plansfirst quarter of $1172013.

DTE Electric Uncollectible Expense True-Up Mechanism (UETM)
In February 2012, DTE Electric filed an application with the MPSC for approval of its UETM for 2011 requesting authority to refund approximately $9 million for Detroit Edison. The surcharges consisting of costs related to recover these costs were implemented effective June 3, 2009.2011 uncollectible expense. An MPSC order was issued September 29, 2009 approving incentive mechanisms foris expected in the utility. The mechanism allows a maximum payoutfirst quarter of 15%2013.


37


DTE Electric Choice Incentive Mechanism (CIM)
2009 Detroit Edison Depreciation Filing
In 2007, the MPSC ordered Michigan utilities to file depreciation studies using the current method,January 2012, DTE Electric filed an approach that considers the time value of money and an inflation adjusted method proposed by the Company that removes excess escalation. In complianceapplication with the MPSC order, Detroit Edison filedfor approval of its ordered depreciation studies in November 2009. The various required depreciation studies indicate composite depreciation ratesCIM reconciliation for the period from 3.05%January 1, 2011 through October 28, 2011, the termination date of the CIM pursuant to 3.54%. Thethe October 20, 2011 MPSC rate order. On January 17, 2013, the MPSC approved a settlement agreement authorizing the Company has proposed no change to recover $63 million, plus interest, from its current composite depreciation rate of 3.33%. The Company expects an order in this proceeding in the fourth quarter of 2010.customers through a surcharge to be implemented over a ten-month period beginning March 2013 through December 2013.

Power Supply Cost Recovery Proceedings

The PSCR process is designed to allow usDTE Electric to recover all of ourits power supply costs if incurred under reasonable and prudent policies and practices. OurDTE Electric's power supply costs include fuel and related transportation costs, purchased and net interchange power costs, nitrogen oxide and sulfur dioxide emission allowances costs, urea costs, transmission costs and MISO costs. The MPSC reviews these costs, policies and practices for prudence in annual plan and reconciliation filings.
2007 Plan
2011 PSCR Year An MPSC order was issued on January 25,In March 2012, DTE Electric filed the 2011 PSCR reconciliation calculating a net under-recovery of $148 million that includes an under-recovery of $52.6 million for the 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.year. 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.

45


The following table summarizes Detroit Edison’s2011 PSCR reconciliation includes an over-refund of $3.8 million for the 2011 refund of the self-implementation rate increase related to the 2009 electric rate case filing currently pending withand a credit of $10.5 million related to the MPSC:expiration of a wholesale power sales contract.
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

20092013 Plan Year In September 2008, Detroit Edison submitted2012, DTE Electric filed 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 20102013 PSCR plan case seeking approval of a levelized PSCR factor of 5.64 4.74mills/kWh belowabove the amount included in base rates for all PSCR customers. The filing supports a 2010total power supply expense forecast of $1.2 billion. Also included in the filing is a request$1.5 billion. The plan also includes approximately $81 million 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’sits projected 2012 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.under-recovery.
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.

46


NOTE 119 — 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 EdisonDTE Electric is determined on an individual company basis with no allocation of tax benefitsexpenses or expensesbenefits from other affiliates of DTE Energy. We had an income tax payable to DTE Energy of $75$13 million at December 31, 20092012 and we had an income tax payablereceivable from DTE Energy of $33$48 million at December 31, 2008 due to DTE Energy.2011.

Total income tax expense varied from the statutory federal income tax rate for the following reasons:
             
(Dollars in Millions) 2009  2008  2007 
Income tax expense at 35% statutory rate $211  $181  $163 
             
Investment tax credits  (6)  (6)  (7)
Depreciation  3   3   3 
Employee Stock Ownership Plan dividends  (4)  (2)  (4)
Medicare Part D subsidy  (5)  (4)  (4)
Domestic production activities deduction  (5)  (2)  (2)
State and other income taxes, net of federal benefit  36   19   1 
Other, net  (2)  (3)  (1)
          
Total $228  $186  $149 
          
             
Effective income tax rate  37.7%  36.0%  32.0%
          
 2012 2011 2010
 (In millions)
Income before income taxes$768
 $704
 $711
Income tax expense at 35% statutory rate$269
 $246
 $249
Investment tax credits(6) (6) (6)
Depreciation3
 3
 3
Employee Stock Ownership Plan dividends(3) (3) (3)
Domestic production activities deduction(16) (6) (6)
State and other income taxes, net of federal benefit40
 39
 40
Other, net(5) (6) (7)
Income Tax Expense$282
 $267
 $270
Effective income tax rate36.7% 38.0% 38.0%


38


Components of income tax expense (benefits) were as follows:
             
(in Millions) 2009  2008  2007 
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 $228  $186  $149 
          
Investment tax credits are deferred and amortized to income over the average life of the related property.
 2012 2011 2010
Current income tax expense (benefit)(In millions)
Federal$267
 $15
 $(89)
State and other income tax67
 21
 37
Total current income taxes334
 36
 (52)
Deferred income tax expense (benefit)     
Federal(47) 193
 297
State and other income tax(5) 38
 25
Total deferred income taxes(52) 231
 322
Total$282
 $267
 $270

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 tax assets (liabilities) were comprised of the following at December 31:
         
(in Millions) 2009  2008 
Property, plant and equipment $(1,409) $(1,297)
Securitized regulatory assets  (474)  (545)
Pension and benefits  103   110 
Other comprehensive income  9   (1)
Other, net  (76)  (142)
       
  $(1,847) $(1,875)
       

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 2012 2011
 (In millions)
Property, plant and equipment$(2,578) $(2,285)
Securitized regulatory assets(261) (384)
Pension and benefits73
 67
Other comprehensive income15
 15
Other, net(24) (182)
 $(2,775) $(2,769)
    
Current deferred income tax liability (included in Current Liabilities — Other)$(14) $(68)
Long-term deferred income tax liabilities$(2,761) $(2,701)
 $(2,775) $(2,769)
    
Deferred income tax assets$557
 $608
Deferred income tax liabilities(3,332) (3,377)
 $(2,775) $(2,769)
         
(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 Statements of Financial Position. Investment tax credits are deferred and amortized to income over the average life of the related property.

Uncertain Tax Positions

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
             
(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
 2012 2011 2010
 (In millions)
Balance at January 1$59
 $18
 $96
Additions for tax positions of prior years
 45
 1
Reductions for tax positions of prior years(3) (5) 
Additions for tax positions of current year
 1
 6
Settlements(52) 
 (85)
Balance at December 31$4
 $59
 $18

The Company had $3 million and $4 million of unrecognized tax benefits at December 31, 2009,2012 and at December 31, 2011, respectively, that, if recognized, would favorably impact our effective tax rate by $2 million.rate. The Company does not anticipate any material decrease in unrecognized tax benefits in the next 12 months.


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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 $6$1 million and $1$2 million at December 31, 20092012 and December 31, 2008,2011, respectively. The Company had no accrued penalties pertaining to income taxes. The Company recognized $5 million for interest expense (income) related to income taxes during 2009of $(3) million, $1 million and an immaterial amount during 2008.$1 million in 2012, 2011 and 2010, respectively.

In 2009,2012, DTE Energy and its subsidiaries settled a federal tax audit for the 2004 through 20062009 and 2010 tax years. The resulting change toyears, which resulted in the recognition of $52 million of unrecognized tax benefits was not significant.by Detroit Edison. The Company’s U.S.Company's federal income tax returns for years 20072011 and subsequent years remain subject to examination by the IRS. The Company’sCompany's Michigan Business Tax returns for the year 2008 and subsequent years is subject to examination by the State of Michigan. The Company also files tax returns in numerous state and local jurisdictions with varying statutes of limitation.

Michigan BusinessCorporate Income Tax (MCIT)
In July 2007,
On May 25, 2011, the Michigan Business Tax (MBT) was enacted by the State of Michigan to replacerepealed and the Michigan Single BusinessCorporate Income Tax (MSBT)was enacted effective January 1, 2008.2012. The MBT is comprised ofnew MCIT subjects corporations with business activity in Michigan to a 6 percent tax rate on an apportioned income tax base and eliminates the modified gross receipts tax and nearly all credits available under the old MBT. The MCIT also eliminated the future deductions allowed under MBT that enabled companies to establish a one-time deferred tax asset upon enactment of 0.8 percent and an apportioned business incomethe MBT to offset deferred tax liabilities that resulted from enactment of 4.95 percent. The MBT provides credits for Michigan business investment, compensation, and research and development. Legislation was also enacted, in 2007, by the StateMBT.

As a result of Michigan creating a deduction for businesses that realize an increase in theirthe enactment of the MCIT, the net state deferred tax liability duewas remeasured to reflect the impact of the new MCIT tax rate on cumulative temporary differences expected to reverse after the effective date. The net impact of this remeasurement was a decrease in deferred income tax liabilities of $30 million that was offset against the regulatory asset established upon the enactment of the MBT. The 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 netDue to the elimination of the related federalfuture tax benefit. Thedeductions allowed under the MBT, the one-time MBT deferred tax asset balance is $367 million as of December 31, 2009 and is reported netthat was established upon the enactment of the related federalMBT has been remeasured to zero. The net impact of this remeasurement is a reduction of net deferred tax liability.assets of $342 million. The regulated asset balance is $343$342 million and decrease in deferred tax assets was offset against the regulated liability balance is $367 million asregulatory liabilities established upon enactment of December 31, 2009 and is further discussedthe MBT.

Consistent with the original establishment of these deferred tax assets (liabilities), no recognition of these non-cash transactions have been reflected in Note 10.the Consolidated Statements of Cash Flows.

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NOTE 1210 — LONG-TERM DEBT
Our
The Company's long-term debt outstanding and weighted average interest rates(1)rates(a) of debt outstanding at December 31 were:
         
(in Millions) 2009  2008 
Detroit Edison Taxable Debt, Principally Secured
        
5.9% due 2010 to 2038 $2,829  $2,841 
Detroit Edison Tax- Exempt Revenue Bonds (2)
        
5.5% due 2011 to 2038  1,263   1,263 
       
   4,092   4,104 
Less amount due within one year  (513)  (13)
       
  $3,579  $4,091 
       
         
Securitization Bonds
        
6.5% due 2010 to 2015 $933  $1,064 
Less amount due within one year  (140)  (132)
       
  $793  $932 
       
 2012 2011
Taxable Debt, Principally Secured(In millions)
5.0% due 2013 to 2042$3,777
 $3,515
Tax- Exempt Revenue Bonds (b)   
5.3% due 2014 to 2038707
 893
 4,484
 4,408
Less amount due within one year(263) (303)
 $4,221
 $4,105
    
Securitization Bonds 
  
6.6% due 2013 to 2015$479
 $643
Less amount due within one year(177) (164)
 $302
 $479

(1)(a)Weighted average interest rates as of December 31, 20092012 are shown below the description of each category of debt.
(2)(b)Detroit Edison Tax-Exempt Revenue Bonds are issued by a public body that loans the proceeds to Detroit EdisonDTE Electric on terms substantially mirroring the Revenue Bonds.


40


Debt Issuances

In 2009, we2012, the Company issued the following long-term debt:
               
(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 
              
MonthType Interest Rate Maturity Amount
       (In millions)
JuneMortgage Bonds (a) 2.65% 2022 $250
JuneMortgage Bonds (a) 3.95% 2042 250
       $500
_____________________________
(1)(a)Proceeds were used to refund existing Tax-Exempt Revenue Bonds.
(2)These Tax-Exempt Revenue Bonds were converted from a variable rate modefor the early redemption of DTE Electric long-term debt; for the repayment of short-term borrowings; and 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.for general corporate purposes.

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Debt Retirements and Redemptions
The
In 2012, the following debt was retired, through optional redemption or payment at maturity, during 2009.
               
(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 
              
redeemed:
(1)These Tax-Exempt Revenue Bonds were redeemed with the proceeds from the issuance of new Detroit Edison Tax-Exempt Revenue Bonds.
Month Type Interest Rate Maturity Amount
        (In millions)
March/September Securitization Bonds 6.42% 2012 $164
April Mortgage Bonds 7.90% 2012 10
April Mortgage Bonds 8.36% 2012 3
July Senior Notes 5.20% 2012 225
December Tax Exempt Bonds 3.05% 2024 65
December Tax Exempt Bonds 5.45% 2032 64
December Tax Exempt Bonds 5.25% 2032 56
        $587

The following table shows the scheduled debt maturities, excluding any unamortized discount or premium on debt:
                             
                      2015 &    
(in Millions) 2010  2011  2012  2013  2014  thereafter  Total 
Amount to mature $513  $152  $303  $313  $341  $2,475  $4,097 
           2018 &  
 2013
 2014 2015 2016 2017 thereafter Total
 (In millions)
Amount to mature$440
 $500
 $315
 $151
 $
 $3,565
 $4,971

Cross Default Provisions

Substantially all of the net properties of Detroit EdisonDTE Electric are subject to the lien of its mortgage. Should Detroit EdisonDTE Electric fail to timely pay its indebtedness under this mortgage, such failure may create cross defaults in the indebtedness of DTE Energy.

NOTE 1311 — PREFERRED AND PREFERENCE SECURITIES

At December 31, 2009, Detroit Edison2012, DTE Electric had approximately 6.75 million shares of preferred stock with a par value of $100$100 per share and 30 million shares of preference stock with a par value of $1$1 per share authorized, with no shares issued.

NOTE 1412 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS
Detroit Edison
DTE Electric has a $69$300 million five-year unsecured revolving credit agreement expiring in October 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 2220 banks andthat may be used for general corporate borrowings, but areis intended to provide liquidity support for ourthe Company's commercial paper program. No one bank provides more than 8.5% of the commitment in anythe facility. Borrowings under the facilitiesfacility are available at prevailing short-term interest rates. The above agreements requirefacility will expire in October 2016. At December 31, 2012, there was $130 million outstanding against this facility, while there were no amounts outstanding against this facility at December 31, 2011.

The agreement requires the Company to maintain a total funded debt to capitalization ratio as defined in the agreements, of no more than 0.65 to 1.1. In the agreements, “total funded debt” means all indebtedness of the Company and its consolidatedsubsidiaries, including capital lease obligations, hedge agreements and guarantees of third parties' debt, but excluding contingent obligations and nonrecourse and junior subordinated debt. “Capitalization” means the sum of (a) total funded debt plus (b) “consolidated net worth,” which is equal to consolidated total stockholders' equity of the Company and its consolidated subsidiaries (excluding pension effects under certain FASB statements), as determined in accordance with accounting principles generally accepted in the United States of America. At December 31, 2009,2012, the total funded debt to total capitalization ratio for Detroit Edison is DTE Electric was 0.52 to 1. Should we have delinquent obligations1.

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We had no outstanding commercial paper of as of December 31, 2009 and December 31, 2008.
Detroit Edison had no short-term borrowings at December 31, 2009 and $75 million outstanding at December 31, 2008. The weighted average interest rate for short-term borrowings was 1.3%0.4% at December 31, 2008.2012.

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NOTE 1513 — CAPITAL AND OPERATING LEASES
Lessee
The Company leases various assets under capital and operating leases, including coal cars,railcars, 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, 20092012 were:
         
  Capital  Operating 
(in Millions) Leases  Leases 
2010 $9  $23 
2011  7   22 
2012  5   22 
2013  5   19 
2014  4   14 
Thereafter  7   77 
       
Total minimum lease payments  37  $177 
        
Less imputed interest  5     
        
Present value of net minimum lease payments  32     
Less current portion  7     
        
Non-current portion $25     
        
 Capital Operating
 Leases Leases
 (In millions)
2013$3
 $26
20141
 21
2015
 18
2016
 16
2017
 16
Thereafter
 66
Total minimum lease payments4
 $163
Less imputed interest
  
Present value of net minimum lease payments4
  
Less current portion(3)  
Non-current portion$1
  

Rental expense for operating leases was $48$29 million in 2009, $392012, $27 million in 2008,2011, and $48$22 million in 2007.2010. Contingent rental payments of $27 million were incurred in 2012 related to power purchase agreements. The contingent payments are based upon delivery of energy and renewable energy credits, which are dependent upon future production.

NOTE 1614 — COMMITMENTS AND CONTINGENCIES
Environmental
Environmental

Air Detroit Edison DTE Electric is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze, mercury, and mercuryother air pollution. The newThese rules will leadhave led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, mercury and mercuryother emissions. To comply with these requirements, Detroit EdisonDTE Electric has spent approximately $1.5$1.9 billion through 2009.2012. The Company estimates Detroit EdisonDTE Electric will make future undiscounted capital expenditures of up to $73approximately $335 million in 20102013 and up to $2.2approximately $1.6 billion of additional capital expenditures through 20192020 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. The Cross State Air Pollution Rule (CSAPR), finalized in July 2011, requires further reductions of sulfur dioxide and nitrogen oxides emissions beginning in 2012. On December 30, 2011, the U. S. Court of Appeals for the District of Columbia Circuit granted the motions to stay the rule, leaving DTE Electric temporarily subject to the previously existing Clean Air Interstate Rule (CAIR). On August 21, 2012, the Court issued its decision, vacating CSAPR and leaving CAIR in place. The EPA's petition seeking a rehearing of the U.S. Court of Appeals decision regarding the CSAPR was denied on January 24, 2013. The Electric Generating Unit Maximum Achievable Control Technology (EGU MACT) Rule was finalized on December 16, 2011. The EGU MACT requires reductions of mercury and other hazardous air pollutants (HAPs). Itbeginning in 2015. Because these rules were recently finalized and technologies to comply are still being tested, it is not possible to quantify the impact of those expected rulemakings at this time.these rulemakings.

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 DTE Electric power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and Title V operating permit requirements under the Clean Air Act. WeAn additional NOV/FOV was received in June 2010 related to a recent project and outage at Unit 2 of the Monroe Power Plant.

On August 5, 2010, the U. S. Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and DTE Electric, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require DTE Electric to install and operate the best available control technology at Unit 2 of the

42


Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require DTE Electric to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from DTE Electric's fleet of coal-fired power plants until the new control equipment is operating.

On August 23, 2011, the U.S. District judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy.On October 20, 2011, the EPA caused to be filed a Notice of Appeal. Oral arguments took place on November 27, 2012 in the appeal of the August 2011 summary judgment before a three-judge panel of the Sixth Circuit Court of Appeals in Cincinnati, Ohio. A decision in this appeal is expected in early 2013. DTE Energy and DTE Electric believe that the plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of our discussions with the EPA regarding the NOV/FOV and the EPA could bring legal action against Detroit Edison. Weresult of the appeals process, the Company could also be required to install additional pollution control equipment at some or all of the power plants in question, implement early retirement of facilities where control equipment is not economical, engage in Supplemental Environmental Programs,supplemental environmental programs, and/or pay fines. WeThe Company cannot predict the financial impact or outcome of this matter, or the timing of its resolution.

On November 9, 2012, the Sierra Club filed a Notice of Intent to Sue DTE Electric for Violations of the Clean Air Act at the St. Clair, Belle River, and Trenton Channel power plants. The notice cites 1,330 total exceedances of the 6-minute opacity standard at nine electric generating units over a five-year period. The Sierra Club obtained the opacity exceedance data from excess emission reports that are submitted every quarter by DTE Electric to the MDEQ. No enforcement actions have been initiated by the MDEQ over this five-year period as a result of the reported opacity exceedances. The Company will develop a strategy for responding to the petition from the Sierra Club that is expected in early 2013.

Water In response to an EPA regulation, Detroit Edison isDTE Electric would be required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of completed studies and expected future studies, Detroit EdisonDTE Electric may be required to install additional control technologies to reduce the impacts of the water intakes. Initially, itintake structures. The initial rule published in 2004 was estimated that Detroit Edison could incur up to approximately $55 million over the four to six years subsequent to 2008subsequently remanded and a proposed rule published in additional capital expenditures to comply with these requirements. However, a January 2007 circuit court decision remanded back to2011. The proposed rule specified an eight year compliance timeline. In July 2012, the EPA several provisionsannounced that a notice 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 ofits final action on 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

51


develop a revised rule, a draft of which is expected towill be published by summer 2010.issued June 2013. The EPA has also proposedissued 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 and Other SitesDetroit EdisonPrior 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, have been designated as manufactured gas plant (MGP) sites. DTE Electric conducted remedial investigations at contaminated sites, including three former manufactured gas plant (MGP)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, electric generating power plants, and underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is expected to be incurred over the next several years. At December 31, 20092012 and 2008,2011, the Company had $9$9 million and $12$8 million, respectively, accrued for remediation. Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows.
Landfill— Detroit Edison
DTE Electric owns and operates a permitted engineered ash storage facility at the Monroe Power Plant to dispose of fly ash from the coal fired power plant. The EPA has published proposed rules to regulate coal ash under the authority of the Resources Conservation and Recovery Act (RCRA). The proposed rule published in June 2010 contains two primary regulatory options to regulate coal ash residue. The EPA is currently considering either designating coal ash as a “Hazardous Waste” as defined by RCRA or regulating coal ash as non-hazardous waste under RCRA. Agencies and legislatures have urged the EPA to regulate coal ash as a non-hazardous waste. If the EPA designates coal ash as a hazardous waste, the agency could apply some, or all, of the disposal and reuse standards that have been applied to other existing hazardous wastes to disposal and reuse of coal ash. Some of the regulatory actions currently being contemplated could have a significant impact on our operations and financial position and the rates we charge our customers. It is not possible to quantify the impact of those expected rulemakings at this time.


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Other

In March 2011, the EPA finalized a new set of regulations regarding the identification of non-hazardous secondary materials that are considered solid waste, industrial boiler and process heater maximum achievable control technologies (IBMACT) for major and area sources, and commercial/industrial solid waste incinerator new source performance standard and emission guidelines (CISWI). The effective dates of the major source IBMACT and CISWI regulations were stayed anda re-proposal was issued by the EPA in December 2011. The re-proposed rules may impact our existing operations and may require us, in certain instances, to install new air pollution control devices. The re-proposed regulations will provide a minimum period of three years for compliance with the applicable standards. Final IBMACT and CISWI were issued by the EPA in December 2012. The Company will assess the financial impact, if any, on current operations for compliance with the applicable new standards.

In 2010, the EPA finalized a new sulfur dioxide ambient air quality standard that requires states to submit plans for non-attainment areas to be in compliance by 2017. Michigan's proposed non-attainment area includes DTE Electric facilities in southwest Detroit Edison performed an engineering analysisand areas of Wayne County. Preliminary modeling runs by the MDEQ suggest that emission reductions may be required by significant sources of sulfur dioxide emissions in 2009these areas, including DTE Electric power plants. The state implementation plan process is in the preliminary stage and identifiedany required emission reductions for DTE Electric sources to meet the need for embankment side slope repairs and reconstruction.standard cannot be estimated currently.

Nuclear Operations

Property Insurance
Detroit Edison
DTE Electric 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
DTE Electric maintains a policy for extra expenses, including replacement power costs necessitated by Fermi 2’s2's unavailability due to an insured event. This policy has a 12-week waiting period and provides an aggregate $490$490 million of coverage over a three-yearthree-year period.
Detroit Edison
DTE Electric has $500$500 million in primary coverage and $2.25$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.$2.75 billion, subject to a $1 million deductible.

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$3.2 billion, plus any amounts recovered from reinsurance, government indemnity, or other sources to cover losses.

Under the NEIL policies, Detroit EdisonDTE Electric could be liable for maximum assessments of up to approximately $28$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 of January 1, 2010,2013, as required by federal law, Detroit EdisonDTE Electric maintains $375$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.$300 million. Further, under the Price-Anderson Amendments Act of 2005, deferred premium charges up to $117.5$117.5 million could be levied against each licensed nuclear facility, but not more than $17.5$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.


44


Nuclear Fuel Disposal Costs

In accordance with the Federal Nuclear Waste Policy Act of 1982, Detroit EdisonDTE Electric 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

52


EdisonDTE Electric 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’sThe DOE's Yucca Mountain Nuclear Waste Repository program for the acceptance and disposal of spent nuclear fuel atwas terminated in 2011. DTE Electric currently employs a permanent repositoryspent nuclear fuel storage strategy utilizing a fuel pool. The Company continues to develop its on-site dry cask storage facility and has postponed the proposed fiscal year 2011 federal budget recommends termination of fundinginitial offload from the spent fuel pool until 2014. The dry cask storage facility is expected to provide sufficient spent fuel storage capability for completionthe life of the government’s long-term storage facility. Detroit Edisonplant as defined by the original operating license.

DTE Electric is a party in the litigation against the DOE for both past and future costs associated with the DOE’sDOE's failure to accept spent nuclear fuel under the timetable set forth in the Federal Nuclear Waste Policy Act of 1982. Detroit Edison currently employsIn July 2012, DTE Electric executed a settlement agreement with the federal government for costs associated with the DOE's delay in acceptance of spent nuclear fuel storage strategy utilizingfrom Fermi 2 for permanent storage. The settlement provided for a fuel pool. We have begun work on an on-sitepayment of approximately $48 million, received in August 2012, for delay-related costs experienced by DTE Electric through 2010, and a claims process for submittal of delay-related costs from 2011 through 2013. The settlement proceeds reduced the cost of the dry cask storage facility which is expectedassets. The federal government continues to provide sufficient storage capabilitymaintain its legal obligation to accept spent nuclear fuel from Fermi 2 for the life of the plant as defined by the original operating license.permanent storage. Issues relating to long-term waste disposal policy and to the disposition of funds contributed by Detroit EdisonDTE Electric 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 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
Labor Contracts

We had approximately 4,800 employees as 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 amount2012, of the bank loan guarantee.
Labor Contracts
There are several bargaining units for the Company’s union employees.which approximately 2,700 were represented by unions. The majority of our union employees are under contractsa contract that expireexpires in June 2010 and August 2012.2013.

Purchase Commitments

As of December 31, 2009,2012, 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.commitments. The Company estimates that these commitments will be approximately $1.5$0.8 billion from 20102013 through 2025. 2028 as detailed in the following table:
 (In millions)
2013$475
2014277
201588
20162
20172
2018 - 20284
 $848

The Company also estimates that 20102013 capital expenditures will be approximately $940 million.$1.6 billion. 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

The Company purchases and sells electricity from and to governmental entities and numerous companies operating in the steel, automotive, energy, retail and other industries. Certain of its customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. The Company regularly reviews contingent matters relating to these customers and its purchase and sale contracts and records provisions for amounts considered at risk of probable loss. The Company believes its accrued amounts are adequate for probable loss. The final resolution of these matters may have a material effect on its consolidated financial statements.

The Company provides services to the domestic automotive industry, including GM, Ford Motor Company (Ford) and Chrysler and many
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Other Contingencies
Other
The Company is involved in certain other 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. The Company cannot predict the final disposition of such proceedings. The Company regularly reviews legal matters and records provisions for claims that it can estimate and are considered probable of loss. The resolution of these pending proceedings is not expected to have a material effect on the Company’s operations or financial statements in the periods they are resolved.

See Note 108 for a discussion of contingencies related to Regulatory Matters.

NOTE 1715 — RETIREMENT BENEFITS AND TRUSTEED ASSETS
Measurement Date
In 2008, the Company changed the measurement date of its pension and postretirement benefit plans from November 30 to December 31. As a result, the Company recognized an adjustment of $15 million ($9 million after-tax) to retained earnings, which represents approximately one month of pension and other postretirement 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, 2009 and December 31, 2008 are based on measurement dates of December 31, 2009 and December 31, 2008, respectively.
Pension Plan Benefits
Detroit Edison
DTE Electric participates in various plans that provide pension and other postretirement benefits for DTE Energy and its affiliates. Detroit EdisonThe plans are sponsored by DTE Energy Corporate Services, LLC (LLC), a subsidiary of DTE Energy. DTE Electric is allocated net periodic benefit costs for its share of the amounts of the combined plans.

Effective January 1, 2012, the Company discontinued offering future non-represented employees a cash balance retirement plan benefit. In prior years, Detroit Edison served asits place, the plan sponsor for a pension plan that changed in 2008Company will annually contribute an amount equivalent to be sponsored by DTE Energy Corporate Services, LLC, (LLC) a subsidiaryfour percent of DTE Energy. The change in plan sponsorship did not changean employee's eligible pay to the pension cost or contributions allocated to Detroit Edison, or the benefits of plan participants.employee's defined contribution retirement savings plan.

The Company’s policy is to fund pension costs by contributing amounts consistent with the Pension Protection Act of 2006 provisions and additional amounts when it deems appropriate. At the discretion of management, and depending upon financial market conditions, we deem appropriate. The Company anticipatesanticipate making up to a $200$275 million contribution to the pension plans in 2010.2013.

Net pension cost includes the following components:
             
  Pension Plans 
(in Millions) 2009  2008  2007 
Service cost $43  $45  $51 
Interest cost  158   148   138 
Expected return on plan assets  (165)  (163)  (148)
Amortization of:            
Net actuarial loss  38   27   46 
Prior service cost  7   5   6 
Special termination benefits        8 
          
Net pension cost $81  $62  $101 
          
Special termination benefits in the above tables represent costs associated with our Performance Excellence Process.
 2012 2011 2010
 (In millions)
Service cost$64
 $55
 $52
Interest cost155
 154
 153
Expected return on plan assets(166) (168) (171)
Amortization of:     
Net loss124
 99
 70
Prior service cost1
 4
 5
Settlements2
 2
 
Net pension cost$180
 $146
 $109
         
  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 

54


         
  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 
 2012 2011
 (In millions)
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income   
Net actuarial loss$289
 $437
Amortization of net actuarial loss(125) (99)
Amortization of prior service cost(1) (4)
Total recognized in Regulatory assets and Other comprehensive income$163
 $334
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income$343
 $480
Estimated amounts to be amortized from Regulatory assets and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year 
  
Net actuarial loss$143
 $120
Prior service cost$1
 $1


46


The following table reconciles the obligations, assets and funded status of the plan as well as the amount recognized as prepaid pension cost or pension liability in the Consolidated Statements of Financial Position at December 31. During 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 assets 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.31:
         
  Pension Plans 
(in Millions) 2009  2008 
Accumulated benefit obligation, end of year
 $2,490  $2,206 
       
         
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  43   45 
Interest cost  158   149 
Actuarial (gain) loss  264   (53)
Benefits paid  (156)  (156)
Measurement date change     16 
Plan amendments     13 
       
Projected benefit obligation, end of year
 $2,677  $2,368 
       
         
Change in plan assets
        
Plan assets at fair value, beginning of year $1,387  $2,599 
Adjustment due to plan sponsorship change     (752)
December 2007 contributions     150 
December 2007 payments     (15)
Actual return on plan assets  252   (557)
Company contributions  204   104 
Measurement date change     14 
Benefits paid  (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 
       

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Assumptions used in determining the projected benefit obligation and net pension costs are listed below:
             
  2009 2008 2007
Projected benefit obligation
            
Discount rate  5.90%  6.90%  6.50%
Rate of compensation increase  4.00%  4.00%  4.00%
             
Net pension costs
            
Discount rate  6.90%  6.50%  5.70%
Rate of compensation increase  4.00%  4.00%  4.00%
Expected long-term rate of return on plan assets  8.75%  8.75%  8.75%
 2012 2011
 (In millions)
Accumulated benefit obligation, end of year$3,307
 $2,963
Change in projected benefit obligation   
Projected benefit obligation, beginning of year$3,196
 $2,899
Service cost64
 55
Interest cost155
 154
Actuarial loss342
 251
Settlements2
 2
Benefits paid(174) (165)
Projected benefit obligation, end of year$3,585
 $3,196
Change in plan assets   
Plan assets at fair value, beginning of year$1,957
 $1,936
Actual return on plan assets220
 (18)
Company contributions208
 204
Benefits paid(174) (165)
Plan assets at fair value, end of year$2,211
 $1,957
Funded status of the plan$(1,374) $(1,239)
Amount recorded as:   
Current liabilities$(6) $(8)
Noncurrent liabilities(1,368) (1,231)
 $(1,374) $(1,239)
Amounts recognized in Regulatory assets (see Note 8)   
Net actuarial loss$1,805
 $1,645
Prior service cost10
 11
 $1,815
 $1,656

At December 31, 2009,2012, the benefits related to the 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)   
2010 $161 
2011  165 
2012  169 
2013  175 
2014  180 
2015 - 2019  993 
    
Total $1,843 
    
 (In millions)
2013$182
2014187
2015193
2016200
2017208
2018 - 20221,145
Total$2,115

Assumptions used in determining the projected benefit obligation and net pension costs are listed below:
 2012 2011 2010
Projected benefit obligation     
Discount rate4.15% 5.00% 5.50%
Rate of compensation increase4.20% 4.20% 4.00%
Net pension costs     
Discount rate5.00% 5.50% 5.90%
Rate of compensation increase4.20% 4.00% 4.00%
Expected long-term rate of return on plan assets8.25% 8.50% 8.75%

The Company employs a formal process in determining the long-term rate of return for various asset classes. Management 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

47


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.

The 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, 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 hedge funds are used to enhance long-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.

56



Target allocations for plan assets as of December 31, 20092012 are listed below:
U.S. Large Cap Equity Securities2522%
U.S. Small Cap and Mid Cap Equity Securities56
Non U.S. Equity Securities2014
Fixed Income Securities2526
Hedge Funds and Similar Investments20
Private Equity and Other86
Short-Term Investments3
 
100100%
The fair values of the Company’s plans assets
Fair Value Measurements at December 31, 2009, by asset category are as follows:
Fair Value Measurements at
2012 and December 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 
             
2011 (a):
 December 31, 2012 December 31, 2011
(in Millions)Level 1 Level 2 Level 3 Net Balance Level 1 Level 2 Level 3 Net Balance
 (In millions)
Asset Category:               
Short-term investments (b)$
 $16
 $
 $16
 $
 $23
 $
 $23
Equity securities               
U.S. Large Cap (c)478
 31
 
 509
 440
 27
 
 467
U.S. Small/Mid Cap (d)108
 3
 
 111
 110
 4
 
 114
Non U.S. (e)372
 85
 
 457
 272
 79
 
 351
Fixed income securities (f)61
 491
 
 552
 61
 448
 
 509
Hedge Funds and Similar Investments (g)147
 56
 238
 441
 132
 40
 205
 377
Private Equity and Other (h)
 
 125
 125
 
 
 116
 116
Total$1,166
 $682
 $363
 $2,211
 $1,015
 $621
 $321
 $1,957

(a)See Note 43 — 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 backedmortgage-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 includesutilizes a diversified group of funds and strategies that attempt to capture financial market inefficiencies.inefficiencies and includes publicly traded debt and equity, publicly traded mutual funds, commingled and limited partnership funds and non-exchange traded securities. Pricing for investmentsLevel 1 and Level 2 assets in this category is based on limited observable inputsobtained from quoted prices in actively traded markets and quoted prices from broker or pricing services. Non-exchange traded securities held in commingled funds are classified as there is little, if any, publicly available pricing.Level 2 assets. Valuations for some Level 3 assets in this category may be based on relative publicly-traded securities, derivatives, and privately-traded securities.limited observable inputs as there may be little, if any, publicly available pricing.

48


(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, relativerelevant 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 EdisonDTE Electric 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 EdisonDTE Electric 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 
          
 Year Ended December 31, 2012 Year Ended December 31, 2011
 
Hedge Funds
and Similar
 Private Equity   
Hedge Funds
and Similar
 Private Equity  
 Investments and Other Total Investments and Other Total
 (In millions)
Beginning Balance$205
 $116
 $321
 $206
 $118
 324
Total realized/unrealized gains (losses):    

      
Realized gains (losses)13
 (4) 9
 (3) 4
 1
Unrealized gains (losses)(3) 8
 5
 1
 (21) (20)
Purchases, sales and settlements:    

      
Purchases176
 23
 199
 44
 16
 60
Sales(153) (18) (171) (43) (1) (44)
Ending Balance$238
 $125
 $363
 $205

$116

$321
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$11
 $4
 $15
 $3
 $(20) $(17)

There were no transfers between Level 3 and Level 2 and there were no significant transfers between Level 2 and Level 1 in the years ended December 31, 2012 and 2011.

The Company also sponsors defined contribution retirement savings plans. Participation in one of these plans is available to substantially all represented and non-represented employees. The Company matches employee contributions up to certain predefined limits based upon eligible compensation, and the employee’s contribution rate.rate and, in some cases, years of credit service. The cost of these plans was $16$19 million, $18 million, and $17 million in 2009, $16 million in 2008,each of the years ended 2012, 2011, and $17 million in 2007.2010, respectively.

Other Postretirement Benefits

The 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. The 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.

Effective January 1, 2012, in lieu of offering future non-represented employees post-employment health care and life insurance benefits, the Company will allocate $4,000 per year to an account in a tax-exempt trust for each employee. The accumulated balance and earnings in an employee's account will vest when the employee has ten years of service, regardless of age. These funds will be available to the employee to use for health care expenses after the employee leaves the Company.

Effective January 1, 2013, the Company replaced sponsored retiree medical, prescription drug and dental coverage for current and future Medicare eligible non-represented retirees, spouses, surviving spouses, or same sex domestic partners with a Retiree Health Care Allowance (RHCA) account of $3,500 or $3,250 per year depending on their date of hire. Local 17

49


employees hired after September 24, 2012 will receive a $4,000per year allocation to an account in a tax-exempt trust for each employee, in lieu of offering post-employment health care and life insurance benefits. Current Local 17 employees, spouses, surviving spouse, or same sex domestic partners, who retired after November 6, 2012 will receive a RHCA of $3,250 per year upon becoming eligible for Medicare.

In January 2013, the Company contributed $120 million to its other postretirement benefit plans. At the discretion of management, subject to MPSC requirements, the Company may make up to a $90an additional $120 million contribution to theits VEBA trusts in 2010.2013.

Net postretirement cost includes the following components:
             
(in Millions) 2009  2008  2007 
Service cost $45  $48  $48 
Interest cost  102   94   90 
Expected return on plan assets  (42)  (58)  (54)
Amortization of:            
Net loss  53   27   51 
Prior service costs  2   2   4 
Net transition obligation  2   2   7 
Special termination benefits        2 
          
Net postretirement cost $162  $115  $148 
          

58


Special termination benefits in the above tables represent costs associated with our Performance Excellence Process.
         
(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 
       
 2012 2011 2010
 (In millions)
Service cost$51
 $49
 $47
Interest cost91
 91
 95
Expected return on plan assets(61) (62) (52)
Amortization of:     
Net loss58
 40
 38
Prior service costs (credit)(16) (15) 2
Net transition asset2
 2
 2
Net postretirement cost$125
 $105
 $132
         
(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 

59

 2012 2011
 (In millions)
Other changes in plan assets and APBO recognized in Regulatory assets   
Net actuarial loss (gain)$(14) $139
Amortization of net actuarial loss(58) (40)
Prior service cost (credit)(207) (3)
Amortization of prior service credit16
 15
Amortization of transition asset(2) (2)
Total recognized in Regulatory assets$(265) $109
Total recognized in net periodic pension cost and Regulatory assets$(140) $214
Estimated amounts to be amortized from Regulatory assets into net periodic benefit cost during next fiscal year   
Net actuarial loss$50
 $55
Prior service credit$(69) $(16)
Net transition obligation$
 $2


50


The following table reconciles the obligations, assets and funded status of the plans including amounts recorded as accrued postretirement cost in the Consolidated Statements of Financial Position at December 31:
         
(in Millions) 2009  2008 
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 $(1,058) $(1,075)
       
         
Non-current liabilities $(1,058) $(1,075)
       
         
Amounts recognized in regulatory assets (see Note 10)
        
Net actuarial loss $510  $600 
Prior service cost  (2)   
Net transition obligation  7   9 
       
  $515  $609 
       
 2012 2011
Change in accumulated postretirement benefit obligation(In millions)
Accumulated postretirement benefit obligation, beginning of year$1,868
 $1,742
Service cost51
 49
Interest cost91
 91
Plan amendments(207) (3)
Actuarial loss12
 60
Medicare Part D subsidy5
 4
Benefits paid(68) (75)
Accumulated postretirement benefit obligation, end of year$1,752
 $1,868
Change in plan assets   
Plan assets at fair value, beginning of year$651
 $682
Actual return on plan assets88
 (17)
Company contributions95
 66
Benefits paid(78) (80)
Plan assets at fair value, end of year$756
 $651
Funded status, end of year$(996) $(1,217)
Amount recorded as:   
Non-current liabilities$(996) $(1,217)
Amounts recognized in Regulatory assets (see Note 8)   
Net actuarial loss$560
 $633
Prior service cost(244) (53)
Net transition obligation
 2
 $316
 $582

At December 31, 2012, 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)
2013$78
201482
201587
201691
201797
2018-2022556
 $991

Assumptions used in determining the projected benefit obligation and net benefit costs are listed below:
             
  2009  2008  2007 
Projected Benefit Obligation
            
Discount rate  5.90%  6.90%  6.50%
             
Net Benefit Costs
            
Discount rate  6.90%  6.50%  5.70%
Expected long-term rate of return on Plan assets  8.75%  8.75%  8.75%
Health care trend rate pre-65  7.00%  7.00%  8.00%
Health care trend rate post-65  7.00%  6.00%  7.00%
Ultimate health care trend rate  5.00%  5.00%  5.00%
Year in which ultimate reached  2016   2011   2011 
 2012 2011 2010
Projected benefit obligation     
Discount rate4.15% 5.00% 5.50%
Health care trend rate pre- and post- 657.00% 7.00% 7.00%
Ultimate health care trend rate5.00% 5.00% 5.00%
Year in which ultimate reached2019
 2016
 2016
Net benefit costs     
Discount rate5.00% 5.50% 5.90%
Expected long-term rate of return on plan assets8.25% 8.75% 8.75%
Health care trend rate pre- and post- 657.00% 7.00% 7.00%
Ultimate health care trend rate5.00% 5.00% 5.00%
Year in which ultimate reached2020
 2019
 2016
A one-percentage-pointone percentage-point increase in health care cost trend rates would have increased the total service cost and interest cost components of benefit costs by $24$21 million and increased the accumulated benefit obligation by $217$218 million at December 31, 2009.2012. A one-percentage-pointone percentage-point decrease in the health care cost trend rates would have decreased the total service and interest cost components of benefit costs by $20$13 million and would have decreased the accumulated benefit obligation by $185$185 million at December 31, 2009.2012.

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At December 31, 2009, the benefits expected to be paid, including prescription drug benefits, in each51


     
(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.
At December 31, 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)   
2010 $5 
2011  6 
2012  6 
2013  6 
2014  7 
2015 - 2019  39 
    
Total $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 theits pension plans.

Target allocations for plan assets as of December 31, 20092012 are listed below:
U.S. Large Cap Equity Securities2021%
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 Other1410
Short-Term Investments0
 100%
The fair values of the Company’s plan assets
Fair Value Measurements at December 31, 2009, by asset category are as follows:
Fair Value Measurements at
2012 and 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 
             
2011(a):
 December 31, 2012 December 31, 2011
 Level 1 Level 2 Level 3 Net Balance Level 1 Level 2 Level 3 Net Balance
Asset Category:(In millions)
Short-term investments (b)$1
 $1
 $
 $2
 $1
 $8
 $
 $9
Equity securities               
U.S. Large Cap (c)122
 2
 
 124
 116
 10
 
 126
U.S. Small/Mid Cap (d)70
 
 
 70
 46
 4
 
 50
Non U.S. (e)151
 4
 
 155
 116
 10
 
 126
Fixed income securities (f)25
 162
 
 187
 15
 156
 
 171
Hedge Funds and Similar Investments (g)68
 15
 78
 161
 53
 14
 63
 130
Private Equity and Other (h)
 
 57
 57
 
 
 39
 39
Total$437
 $184
 $135
 $756
 $347
 $202
 $102
 $651

(a)See Note 43 — 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 includesutilizes a diversified group of funds and strategies that attempt to capture financial market inefficiencies.inefficiencies and includes publicly traded debt and equity, publicly traded mutual funds, commingled and limited partnership funds and non-exchange traded securities. Pricing for investmentsLevel 1 and Level 2 assets in this category is based on limited observable inputsobtained from quoted prices in actively traded markets and quoted prices from broker or pricing services. Non-exchange traded securities held in commingled funds are classified as there is little, if any, publicly available pricing.Level 2 assets. Valuations for some Level 3 assets in this category may be based on relative publicly-traded securities, derivatives, and privately-traded securities.limited observable inputs as there may be little, if any, publicly available pricing.
(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, relativerelevant 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 EdisonDTE Electric 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 EdisonDTE Electric selectively corroborates the fair values of securities by comparison of market-based price sources.


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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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 Year Ended December 31, 2012 Year Ended December 31, 2011
 Hedge Funds and Similar Investments Private Equity and Other Total Hedge Funds and Similar Investments Private Equity and Other Total
 (In millions)
Beginning Balance$63
 $39
 $102
 $52
 $36
 $88
Total realized/unrealized gains (losses):    

      
Realized gains (losses)4
 (7) (3) (1) 1
 
Unrealized gains (losses)
 9
 9
 2
 (14) (12)
Purchases, sales and settlements:    

     

Purchases56
 25
 81
 45
 31
 76
Sales(45) (9) (54) (35) (15) (50)
Ending Balance$78
 $57
 $135
 $63
 $39
 $102
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
 $1
 $5
 $3
 $(11) $(8)

There were no transfers between Level 3 and Level 2 and there were no significant transfers between Level 2 and Level 1 in the years ended December 31, 2012 and 2011.

Healthcare Legislation

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 $4 million in 2012, $5 million in 2011 and $5 million in 2010.

NOTE 1816 — 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)
          
 2012 2011 2010
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately(In millions)
Accounts receivable, net$24
 $(62) $
Inventories7
 (53) (71)
Recoverable pension and postretirement costs106
 (436) (26)
Accrued pension liability — affiliates137
 271
 (27)
Accounts payable(64) 41
 47
Income taxes payable/receivable114
 54
 (77)
Accrued postretirement liability — affiliates(221) 157
 3
Regulatory assets125
 (18) (77)
Other assets108
 (80) (54)
Other liabilities(78) (15) 29
 $258
 $(141) $(253)

Supplementary cash andinformation for the years ended December 31, were as follows:
 2012 2011 2010
Cash paid (received) for:(In millions)
Interest (excluding interest capitalized)$280
 $294
 $315
Income taxes223
 (18) 28


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Supplementary 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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 2012 2011 2010
 (In millions)
Change in capital expenditures not paid$(22) $47
 $27

NOTE 1917 — RELATED PARTY TRANSACTIONS

The 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. The 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,A shared services company accumulates various DTE Energy affiliates, including Detroit Edison, provided corporate support services inclusive of various financial, auditing, tax, legal, treasuryexpenses 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 tocharges various subsidiaries of DTE Energy, including Detroit Edison.DTE Electric. DTE Electric records federal, state and local income taxes payable to or receivable from DTE Energy based on its federal, state and local tax provisions.

The following is a summary of transactions with affiliated companies:
             
(in Millions) 2009  2008  2007 
Revenues
            
Energy sales $1  $  $ 
Other services  4   6   5 
Shared capital assets  28   23   21 
Costs
            
Fuel and power purchases  3   5   3 
Other services and interest  3   7   6 
Corporate expenses (net)  313   388   331 
Other
            
Dividends declared  305   228   305 
Dividends paid  305   305   305 
Capital contribution  250   175   175 
         
  December 31, 
(in Millions) 2009  2008 
Assets
        
Accounts receivable $3  $5 
Notes receivable  82   41 
Liabilities & Equity
        
Accounts payable  74   103 
Other liabilities        
Accrued pension liability  987   978 
Accrued postretirement liability  1,058   1,075 
 2012 2011 2010
Revenues(In millions)
Energy sales$2
 $1
 $1
Other services11
 4
 7
Shared capital assets26
 30
 29
Costs 
  
  
Fuel and power purchases5
 1
 4
Other services and interest1
 2
 2
Corporate expenses (net)322
 304
 294
Other 
  
  
Dividends declared317
 305
 305
Dividends paid317
 305
 305
 December 31
 2012 2011
Assets(In millions)
Accounts receivable$5
 $61
Income taxes receivable (included in other current assets)
 48
Notes receivable
 26
Liabilities   
Accounts payable52
 67
Short-term borrowing80
 64
Income taxes payable (included in other current liabilities)13
 

Accrued pension liability1,368
 1,231
Accrued postretirement liability996
 1,217

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.

Charitable contributions to the DTE Energy Foundation were approximately $21 million and $13 million for the years ended December 31, 2011 and 2010, respectively. The DTE Energy Foundation is a non-consolidated not-for-profit private foundation, the purpose of which is to contribute and assist charitable organizations and does not serve a direct business or political purpose of DTE Electric.


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NOTE 2018 — SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
                     
  First  Second  Third  Fourth    
(in Millions) Quarter  Quarter  Quarter(1)  Quarter  Year 
2009
                    
Operating Revenues $1,118  $1,108  $1,289  $1,199  $4,714 
Operating Income  214   189   318   178   899 
Net Income  78   79   149   70   376 
                     
2008                    
Operating Revenues  1,153   1,173   1,440   1,108   4,874 
Operating Income  139   151   316   194   800 
Net Income  41   51   159   80   331 

 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
  
     Year
2012(In millions)
Operating Revenues$1,198
 $1,289
 $1,542
 $1,262
 $5,291
Operating Income (a)213
 265
 378
 172
 1,028
Net Income97
 127
 195
 67
 486
2011 
  
  
  
  
Operating Revenues1,192
 1,240
 1,517
 1,203
 5,152
Operating Income205
 235
 335
 227
 1,002
Net Income85
 104
 158
 90
 437

(1)(a)The 2009 Third Quarter
In the fourth quarter of 2012, the Company recorded an adjustment that decreased operating income by $9 million ($5 million after tax) to correct other postretirement benefit expenses reported in prior periods. This adjustment is not considered material to the operating results were adjusted for the effectof any of the January 2010 Detroit Edison MPSC rate order that required the refund of a portion of the self implemented rate increase effective on July 26, 2009. The adjustments resulted in a reduction of Operating Revenues of $11 million, Operating Income of $11 million and Net Income of $7 million.relevant periods.

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55


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
Item 9B.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 yearyears ended December 31, 20092012 and December 31, 2011 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’sDTE Electric’s annual financial statements for the years ended December 31, 20092012 and December 31, 2008,2011, respectively, and fees billed for other services rendered by PwC and Deloitte during those periods.
         
  2009  2008 
Audit fees (1) $1,231,865  $1,466,413 
Audit-related fees (2)  37,400   45,500 
       
Total $1,269,265  $1,511,913 
       
 2012 2011
Audit fees (a)$1,248,808
 $1,144,625
Audit-related fees (b)39,000
 36,250
All other fees (c)375,000
 210,000
Total$1,662,808
 $1,390,875

(1)(a)Represents the aggregate fees for the audits of Detroit Edison’sDTE Electric’s annual financial statements included in the Annual Reports on Form 10-K and for the reviews of the financial statements included in Detroit Edison’sthe Quarterly Reports on Form 10-Q.
(2)(b)Represents the aggregate fees billed for audit-related services for various attest services.
(c)Represents consulting services for the purpose of providing advice and recommendations.

The above listed fees were pre-approved by the DTE Energy audit committee.Audit Committee. Prior to engagement, the DTE Energy audit committeeAudit Committee pre-approves these services by category of service. The DTE Energy audit committeeAudit Committee may delegate to the chair of the audit committee,Audit Committee, or to one or more other designated members of the audit committee,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 committeeAudit Committee at the next scheduled meeting.

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56



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.
(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.
(i)Exhibits filed herewith.
4-267Supplemental 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).
12-3612-45 Computation of Ratio of Earnings to Fixed Charges.
   
23-2223-27 Consent of PricewaterhouseCoopers LLP.
   
23-23Consent of Deloitte & Touche LLP.
31-5331-79 Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report.
   
31-5431-80 Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report.
(ii)Exhibits incorporated herein by reference.
(ii)Exhibits incorporated herein by reference.
  Certain exhibits listed below refer to "The Detroit Edison Company" and were effective prior to the change to DTE Electric Company effective January 1, 2013.
3(a) Restated Articles of Incorporation of The Detroit EdisonDTE Electric Company, as filed December 10, 1991.amended effective January 1, 2013. (Exhibit 3-133-1 to Form 10-Q for the quarter ended June 30, 1999)8-K filed January 2, 2013).
   
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 The Bank of New York Mellon Trust Company, 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 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 The Bank of New York Mellon Trust Company, 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 The Bank of New York Mellon Trust Company, 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 The Bank of New York Mellon Trust

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Company, 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 The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-23 to Registration Statement on Form S-1 (File No. 2-9226)). (amendment)

57


  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 The Bank of New York Mellon Trust Company, 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 The Bank of New York Mellon Trust Company, 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 The Bank of New York Mellon Trust Company, 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) C)


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 The Bank of New York Mellon Trust Company, N.A., as successor trustee (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 The Bank of New York Mellon Trust Company, 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 The Bank of New York Mellon Trust Company, 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 The Bank of New York Mellon Trust Company, 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 August 1, 1999, 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 (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 The Bank of New York Mellon Trust Company, 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 The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-222 to Form 10-Q for the quarter ended March 31, 2001). (2001 Series AP)

67


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 The Bank of New York Mellon Trust Company, 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 The Bank of New York Mellon Trust Company, 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 The Bank of New York Mellon Trust Company, 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 The Bank of New York Mellon Trust Company, 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 The Bank of New York Mellon Trust Company, 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 The Bank of New York Mellon Trust Company, 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 The Bank of New York Mellon Trust Company, 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 The Bank of New York Mellon Trust Company, 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 The Bank of New York Mellon Trust Company, 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 The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.3 to Registration Statement on Form S-4 (File No. 333-123926)). (2005 Series AR and BR)
   
  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 The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.2 to Form 8-K dated September 29, 2005). (2005 Series C)

58


   
  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 The Bank of New York Mellon Trust Company, 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 The Bank of New York Mellon Trust Company, 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, 2007, 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 (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.trustee. (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)Supplemental Indenture, dated as of August 1, 2010, 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. (Exhibit 4-269 to Form 10-Q for the quarter ended September 30, 2010). (2010 Series B)
Supplemental Indenture, dated as of September 1, 2010, 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. (Exhibit 4-271 to Form 10-Q for the quarter ended September 30, 2010). (2010 Series A)
Supplemental Indenture, dated as of December 1, 2010, to Mortgage and Deed of Trust, dated as of October 1, 1924between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-273 to Form 10-K for the year ended December 31, 2010). (2010 Series CT)



Supplemental Indenture, dated as of March 1, 2011, to Mortgage and Deed of Trust, dated as of October 1, 1924between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-274 to Form 10-Q for the quarter ended March 31, 2011). (2011 Series AT) 



Supplemental Indenture, dated as of May 15, 2011, 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 4-275 to Form 10-Q for the quarter ended June 30, 2011). (2011 Series B)


Supplemental Indenture, dated as of August 1, 2011, 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 4-276 to Form 10-Q for the quarter ended September 30, 2011). (2011 Series GT)

Supplemental Indenture, dated as of August 15, 2011, 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 4-277 to Form 10-Q for the quarter ended September 30, 2011). (2011 Series D, 2011 Series E, 2011 Series F)

Supplemental Indenture, dated as of September 1, 2011, to Mortgage and Deed to 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 4-278 to Detroit Edison Form 10-Q for the quarter ended September 30, 2011. (2011 Series H)
Supplemental Indenture, dated as of June 20, 2012, 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 (Exhibit 4-279 to Form 10-Q for the quarter ended June 30, 2012). (2012 Series A and B)

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 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 4-152 to Registration Statement on Form S-3 (File No. 33-50325)).
Ninth Supplemental Indenture, and indentures supplemental thereto, dated as of October 10, 2001,the dates indicated below and filed as exhibits 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 4-229 to Form 10-Q for the quarter ended September 30, 2001). (6.125% Senior Notes due 2010)filings set forth below:
   
  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 The Bank of New York Mellon Trust Company, 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)
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 The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-233 to Form 10-Q for the quarter ended March 31, 2003). (5.45% Senior Notes due 2032 and 5.25%(6.35% Senior Notes due 2032)
   
  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 The Bank of New York Mellon Trust Company, 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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  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 The Bank of New York Mellon Trust Company, 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)
   
  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 The Bank of New York Mellon Trust Company, 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)
   
  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 The Bank of New York Mellon Trust Company, 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)
   
  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 The Bank of New York Mellon Trust Company, 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)
   
  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 The Bank of New York Mellon Trust Company, 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)

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  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 The Bank of New York Mellon Trust Company, 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)
   
  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 Mellon 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)
   
  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 (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 Mellon 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 Mellon 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-sixthTwenty-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) (ExhibitExhibit 4-266 to Form 10-Q for the quarter ended June 30, 2009)

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61


  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 TrustMellon 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’sEdison'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’sEdison's Form 10-Q for the quarter ended March 31, 2009). (2009 Series BT 6.00% Senior Notes due 2036)
   
4(c) Thirty-First Supplemental Indenture, dated as of August 1, 2010 to the Collateral Trust AgreementIndenture, dated as of June 1, 1993 by and between The Detroit Edison Company and The Bank of New York Mellon Trust I.Company, N.A., as successor trustee. (Exhibit 4.94-270 to Registration Statement on Form S-3 (File No. 333-100000))10-Q for the quarter ended September 30, 2010). (2010 Series B 3.45% Senior Notes due 2020)
   
4(d) Thirty-Second Supplemental Indenture, dated as of September 1, 2010, to the Collateral Trust AgreementIndenture, dated as of June 1, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust II.Company, N.A., as successor trustee. (Exhibit 4.104-272 to Registration Statement on Form S-3 (File No. 333-100000)10-Q for the quarter ended September 30, 2010.). (2010 Series A 4.89% Senior Notes due 2020)
   
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)10(c) 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)10(d) 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)10(e) 
Form of The Detroit Edison Company’sAmended and Restated Five-Year Credit Agreement, dated as of August 20, 2010 and amended and restated as of October 17, 2005,21, 2011, 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., and The Royal Bank of Scotland plc, as Co-Syndication Agents (Exhibit 10.1 to Form 8-K dated October 17, 2005)21, 2011).
10(h)Form of Detroit Edison Two-Year Credit Agreement, dated as of April 29, 2009, by and among Detroit Edison, the lenders party thereto, Barclays, as Administrative Agent, and Citibank, JPMorgan and RBS, as Co-Syndication Agents. (Exhibit 10.1 to Form 8-K filed May 5, 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).
(iii) Exhibits furnished herewith.



















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iii.Exhibits furnished herewith.
32-53
32-79 Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report.
   
32-5432-80 Chief Financial Officer Section 906 Form 10-K Certification of Periodic Report.
101.INSXBRL Instance Document
101.SCHXBRL Taxonomy Extension Schema
101.CALXBRL Taxonomy Extension Calculation Linkbase
101.DEFXBRL Taxonomy Extension Definition Database
101.LABXBRL Taxonomy Extension Label Linkbase
101.PREXBRL Taxonomy Extension Presentation Linkbase

72




The Detroit Edison63


DTE Electric Company

Schedule II — Valuation and Qualifying Accounts
             
  Year Ended December 31 
(in Millions) 2009  2008  2007 
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statements of Financial Position)
            
Balance at Beginning of Period $121  $93  $72 
Additions:            
Charged to costs and expenses  62   81   63 
Charged to other accounts (1)  7   5   4 
Deductions (2)  (72)  (58)  (46)
          
Balance At End of Period $118  $121  $93 
          

 Year Ended December 31
 2012 2011 2010
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statements of Financial Position)(In millions)
Balance at Beginning of Period$80
 $93
 $118
Additions:     
Charged to costs and expenses40
 47
 57
Charged to other accounts (a)7
 8
 8
Deductions (b)(92) (68) (90)
Balance At End of Period$35
 $80
 $93

(1)(a)Collection of accounts previously written off.
(2)(b)Non-collectibleUncollectible accounts written off.

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64



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
DTE ELECTRIC COMPANY
(Registrant)
 
Date:February 23, 201020, 2013 By  /s/ ANTHONY F. EARLEY, JR.GERARD M. ANDERSON   
   Anthony F. Earley, Jr.Gerard M. Anderson  
   
Chairman of the Board and
Chief Executive 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.GERARD M. ANDERSON By /s/ PETER B. OLEKSIAKDAVID E. MEADOR
 Gerard M. Anderson   David E. Meador
  Anthony F. Earley, Jr.
Chairman of the Board and
Director, Executive Vice President and Chief
Chief Executive Officer   Peter B. Oleksiak
Vice President, Controller and Investor Relations, and
Chief AccountingFinancial Officer
(Principal Executive Officer)(Principal Financial Officer)
       
By /s/ SANDRA KAY ENNISDONNA M. ENGLAND By /s/ DAVID E. MEADORLISA A. MUSCHONG
Donna M. EnglandLisa A. Muschong
Chief Accounting OfficerDirector
(Principal Accounting Officer)
       
Sandra Kay Ennis
Director and Corporate Secretary
David E. Meador
Director, Executive Vice President and Chief Financial Officer
       
By /s/ BRUCE D. PETERSON    
  Bruce D. Peterson    
  Bruce D. Peterson
Director
    

Date: February 23, 201020, 2013

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Supplemental Information to be Furnished With Reports Filed Pursuant to Section 15(d) of the Securities Exchange Act of 1934 by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Securities Exchange Act of 1934.

No annual report, proxy statement, form of proxy or other proxy soliciting material has been sent to security holders of DTE Electric Company during the period covered by this Annual Report on Form 10-K for the fiscal year ended December 31, 2012.


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