UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period ended September 30, 2007March 31, 2008
Commission file number 1-2198
The Detroit Edison Company meets the conditions set forth in General Instruction H (1) (a) and (b) of Form 10-Q and is, therefore, filing this Form with the reduced disclosure format.
THE DETROIT EDISON COMPANY
(Exact name of registrant as specified in its charter)
   
Michigan 38-0478650
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
   
2000 2nd Avenue, Detroit, Michigan 48226-1279
(Address of principal executive offices) (Zip Code)
313-235-4000
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant: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 is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a non-accelerated filer.smaller reporting company. See definitionthe definitions of “large accelerated filer,” “accelerated filerfiler” and large accelerated filer”“smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated fileroAccelerated filero
Large accelerated fileroAccelerated fileroNon-accelerated filerþSmaller reporting companyo
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
YesoNoþ
All of the registrant’s 138,632,324 outstanding shares of common stock are owned by DTE Energy Company.
 
 

 

 

The Detroit Edison Company

Quarterly Report on Form 10-Q
Quarter Ended September 30, 2007March 31, 2008
Table ofOf Contents
     
  Page
Definitions
  1
 
Forward-Looking Statements
  2 
Part I —– Financial Information
    
Item 1. Financial Statements
    
Consolidated Statements of Operations (Unaudited)
  8 
Consolidated Statements of Financial Position (Unaudited)
  9 
Consolidated Statements of Cash Flows (Unaudited)
  11
 
Consolidated Statements of Changes in Shareholder’sShareholders’ Equity and Comprehensive Income (Unaudited)
  12 
Notes to Consolidated Financial Statements (Unaudited)
  13
 
Item 2. Management’s Narrative Analysis of Results of Operations
  3 
Item 4. Controls and Procedures
  7 
Part II —– Other Information
    
Item 1. Legal Proceedings
  23 
Item 1A. Risk Factors
  2523 
Item 5. Other Information
  23 
Item 6. Exhibits
  25
23 
Signature
  2624 
Supplemental Indenture
Twenty-Third Supplemental Indenture
Amendment No.8 to Amended & Restated Trade Receivables Purchase and Sale Agreement
Computation of Ratio of Earnings to Fixed Charges
 Chief Executive Officer Section 302 Certification
 Chief Financial Officer Section 302 Certification
 Chief Executive Officer Section 906 Certification
 Chief Financial Officer Section 906 Certification

 

Definitions
CompanyThe Detroit Edison Company and any subsidiary companies
   
CTA Costs to achieve, consisting of project management, consultant support and employee severance, related to the Performance Excellence Process
   
Customer Choice Statewide initiatives giving customers in Michigan the option to choose alternative suppliers for electricity.
   
Detroit Edison The Detroit Edison Company (a direct wholly owned subsidiary of DTE Energy Company) and subsidiary companies
   
DTE Energy DTE Energy Company, the parent of Detroit Edison and directly or indirectly the parent company of two gas utility subsidiaries and numerous non-utility subsidiaries
   
EPA United States Environmental Protection Agency
   
FERC Federal Energy Regulatory Commission
ITC TransmissionInternational Transmission Company (until February 28, 2003, a wholly owned subsidiary of DTE Energy Company)
   
MDEQ Michigan Department of Environmental Quality
   
MISO Midwest Independent System Operator, a Regional Transmission Organization
   
MPSC Michigan Public Service Commission
   
NRC Nuclear Regulatory Commission
   
PSCR A power supply cost recovery mechanism authorized by the MPSC that allows Detroit Edison to recover through rates its fuel, fuel-related and purchased power expenses.
   
Securitization Detroit Edison financed specific stranded costs at lower interest rates through the sale of rate reduction bonds by a wholly owned special purpose entity, Thethe Detroit Edison Securitization Funding LLC.
   
SFAS Statement of Financial Accounting Standards
   
Stranded Costs Costs incurred by utilities in order to serve customers in a regulated environment that absent special regulatory approval would not otherwise be recoverable if customers switch to alternative energy suppliers.
   
Units of Measurement
  
   
kWh Kilowatthour of electricity
   
MW Megawatt of electricity
   
MWh Megawatthour of electricity

1

Forward-Looking Statements
Certain information presented herein includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve certain risks and uncertainties that may cause actual future results to differ materially from those presently contemplated, projected, estimated or budgeted. There are manyMany factors that may impact forward-looking statements including, but not limited to, the following:
 • the effects of weather and other natural phenomena on operations and sales to customers, and purchases from suppliers;
 
 • economic climate and population growth or decline in the geographic areas where we do business;
 
 • environmental issues, laws, regulations, and the cost of remediation and compliance, including potential new federal and state requirements that could include carbon and more stringent mercury emission controls, a renewable portfolio standard and energy efficiency mandates;
 
 • 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 negotiation and impactsimpact of collective bargaining agreements;
 
 • unplanned outages;
 
 • access to capital markets and capital market conditions and the results of other financing efforts thatwhich can be affected by credit agency ratings;
 
 • the timing and extent of changes in interest rates;
 
 • the level of borrowings;
 
 • changes in the cost and availability of coal and other raw materials, and purchased power;
 
 • effects of competition;
 
 • impact of regulation by the FERC, MPSC, NRC and other applicable governmental proceedings and regulations, including any associated impact on rate structures;
 
 • changes in and application of federal, state and local tax laws and their interpretations, including the Internal Revenue Code, regulations, rulings, court proceedings and audits;
 
 • the ability to recover costs through rate increases;
 
 • the availability, cost, coverage and terms of insurance;
 
 • the cost of protecting assets against, or damage due to, terrorism;
 
 • changes in and application of accounting standards and financial reporting regulations;
 
 • changes in federal or state laws and their interpretation with respect to regulation, energy policy and other business issues;
 
 • amounts of uncollectible accounts receivable;
 
 • binding arbitration, litigation and related appeals; and
 
 • changes in the economic and financial viability of our suppliers, customers and trading counterparties, and the continued ability of such parties to perform their obligations to Detroit Edison; and
•implementation of new processes and new core information systems.Edison.
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 speakrefer 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.

2

Part I — Item 2.
The Detroit Edison Company
Management’s Narrative Analysis of Results of Operations
The Management’s Narrative Analysis of Results of Operations discussion for Detroit Edison is presented in accordance with General Instruction H(2) (a) of Form 10-Q.
Factors impacting income:income: Net income decreased by $31increased $1 million in the thirdfirst quarter of 2008 compared to the same period in 2007 and decreased by $47 million for the nine-month period ended September 30, 2007. The decreases were due primarily to higher operation and maintenance expenses,gross margins, partially offset by lower depreciation and amortizationhigher operating expenses.
Increase (Decrease) in Statement of Operations Components Compared to Prior Year
        
 Three Nine     
(in Millions) Months Months  Three Months 
Operating Revenues $(57) $22  $59 
Fuel and Purchased Power  (21)  17  48 
        
Gross Margin  (36) 5  11 
Operation and Maintenance 109 123  10 
Depreciation and Amortization  (108)  (63) 10 
Taxes Other Than Income  (1) 6   (10)
Asset (Gains) and Reserves, Net 7 13 
Other Asset (Gains), Losses and Reserves, Net  (7)
        
Operating Income  (43)  (74) 8 
Other (Income) and Deductions  (11) —  3 
Income Tax Provision  (23)  (28) 4 
Cumulative Effect of Accounting Change —  (1)
        
Net Income $(31) $(47) $1 
        
Gross margindecreased by $36increased $11 million in the thirdfirst quarter of 2007 and increased by $5 million in the nine-month period ended September 30, 2007. The decrease in the third quarter of 2007 was partially due2008 as compared to the favorable impact of a September 2006 MPSC order related to the 2004 PSCR reconciliation, lower rates resulting primarily from the August 2006 settlementsame period in the MPSC show cause proceeding and weather related impacts.2007. The increase in the nine-month period of 20072008 was dueattributed to the favorable impact of a May 2007 MPSC order related to the 2005 PSCR reconciliation, higher margins due to returning sales from electric Customer Choice and weather related impacts,service territory performance, partially offset by the favorable impactreductions in revenues for over-collections of a September 2006 MPSC order related to the 2004 PSCR reconciliation, lower rates resulting primarily from the August 2006 settlement in the MPSC show cause proceedingour Regulatory Asset Recovery Surcharge (“RARS”) and the impact of poor economic conditions.our recoverable pension cost. Revenues include a component for the cost of power sold that is recoverable through the PSCR mechanism.
The following table displaysdetails changes in various gross margin components relative to the comparable prior period:
         
(in Millions) Three Months  Nine Months 
Weather related margin impacts $(7) $21 
Return of customers from electric Customer Choice  4   47 
Service territory economic performance  (4)  (25)
Impact of 2006 MPSC show cause order  (19)  (53)
Impact of 2005 MPSC PSCR reconciliation order  —   38 
Impact of 2004 MPSC PSCR reconciliation order  (39)  (39)
Other, net  29   16 
       
Increase (decrease) in gross margin $(36) $5 
       
Increase (Decrease) in Gross Margin Components Compared to Prior Year
     
(in Millions) Three Months 
Weather related margin impacts $3 
Return of customers from electric Customer Choice  8 
Service territory performance  8 
RARS over-collection  (3)
Recoverable pension cost  (4)
Other, net  (1)
    
Increase in gross margin $11 
    

3

                        
 Three Months Ended Nine Months Ended  Three Months Ended 
Power Generated and Purchased September 30 September 30  March 31 
(in Thousands of MWh) 2007 2006 2007 2006  2008 2007 
Power Plant Generation  
Fossil 11,055 10,867 31,729 29,382  10,240 10,557 
Nuclear 2,352 1,873 7,195 4,991  2,343 2,428 
         
 13,407 12,740 38,924 34,373      
  12,583 12,985 
Purchased Power 2,765 3,085 5,885 7,917  1,730 1,233 
              
System Output 16,172 15,825 44,809 42,290  14,313 14,218 
Less Line Loss and Internal Use  (1,160)  (483)  (2,568)  (2,165)  (845)  (784)
              
Net System Output 15,012 15,342 42,241 40,125  13,468 13,434 
              
  
Average Unit Cost ($/MWh)
  
Generation (1) $16.93 $17.78 $15.72 $16.33  $16.60 $15.41 
              
Purchased Power $69.61 $68.28 $68.03 $58.89  $61.60 $63.88 
              
Overall Average Unit Cost $25.94 $27.62 $22.59 $24.30  $22.04 $19.62 
              
 
(1) Represents fuel costs associated with power plants.
                        
 Three Months Ended Nine Months Ended  Three Months Ended 
 September30 September 30  March 31 
(in Thousands of MWh) 2007 2006 2007 2006  2008 2007 
Electric Sales
  
Residential 4,836 4,883 12,340 12,233  3,932 3,786 
Commercial 5,166 4,927 14,345 13,440  4,362 4,309 
Industrial 3,278 3,695 9,974 10,058  3,516 3,374 
Wholesale 718 719 2,170 2,096  723 735 
Other 93 95 292 291  109 110 
              
 14,091 14,319 39,121 38,118  12,642 12,314 
Interconnections sales (1) 921 1,023 3,120 2,007  826 1,120 
              
Total Electric Sales 15,012 15,342 42,241 40,125  13,468 13,434 
              
  
Electric Deliveries
  
Retail and Wholesale 14,091 14,319 39,121 38,118  12,642 12,314 
Electric Customer Choice 389 319 1,163 2,188  398 451 
Electric Customer Choice — Self Generators (2) 180 215 447 693 
Electric Customer Choice – Self Generators (2) 58 67 
              
Total Electric Sales and Deliveries 14,660 14,853 40,731 40,999  13,098 12,832 
              
 
(1) Represents power that is not distributed by Detroit Edison.
 
(2) Represents deliveries for self generators who have purchased power from alternative energy suppliers to supplement their power requirements.
Operation and maintenanceexpense increased by $109 million for the third quarter of 2007 and by $123$10 million in the nine-monthfirst quarter of 2008 compared to the same period ended September 30, 2007. The increase for the quarter wasin 2007 primarily due primarily to a reduction in the deferral of CTA costs of $57 million, EBS implementation costs of $10 million, higher storm expenses of $9 million, increased plant expenses of $7 million higherof increased uncollectible expense of $5and $3 million increased corporate support expenses of $8 million and higher labor and benefit costs of $10 million. The increase for the nine-month period is due to EBS implementation costs of $43 million, higher storm expenses of $15 million, higher uncollectible expense of $7 million, increased corporate support expenses of $25 million and higher labor and benefit costs of $21 million. CTA expenses were deferred beginning in the third quarter of 2006. See Note 3 of the Notes to the Consolidated Financial Statements.expense.
Depreciation and amortizationexpense decreased by $108increased $10 million forin the thirdfirst quarter of 2008 compared to the same period in 2007. The 2008 increase is attributed to $4 million of higher software amortization primarily due to the Enterprise Business System implementation in the second quarter of 2007, increased depreciation of $3 million due to higher levels of depreciable plant and $2 million of increased amortization of our regulatory assets.
Taxes other than incomedecreased $63$10 million forin the nine-monthfirst quarter of 2008 compared to the same period ended September 30, 2007. The decrease for the quarter wasin 2007 due primarily to a $112$9 million net stranded cost write-off related todecrease in Michigan Single Business Tax (MSBT) expense, which was replaced with the September 2006 MPSC order regarding stranded costs. TheMichigan Business Tax (MBT) in 2008 and accounted for in the Income tax provision.

4

decrease for the nine-month period was due primarily to a $112 million net stranded cost write-off related to the September 2006 MPSC order regarding stranded costs partially offset by increased amortization of regulatory assets and higher depreciation expense due to increased levels of depreciable plant.
AssetOther asset (gains), losses and reserves, netwere $6expense decreased $7 million forin the thirdfirst quarter of 2007 and $122008 due to a $7 million for the nine-month period ending September 30,reserve established in 2007 representing reserves for a loan guaranty related to Detroit Edison’sour former ownership of a steam heating business now owned by Thermal Ventures II, LP (Thermal).
Outlook-– We will move forward in our efforts to continue to improve the operating performance of Detroit Edison. We continue to resolve outstanding regulatory issues and continue to pursue additional regulatory and/or legislative solutions for structural problems within the Michigan electric market, structure, primarily electric Customer Choice and the need to adjust rates for each customer class to reflect the full cost of service. We expect cash flows and operating performance to continue to be at risk due to the electric Customer Choice program until the issues associated with this program are resolved. We are also seeking regulatory reform to ensure more timely cost recovery and resolution of rate cases. If enacted, these issues would be addressed, for the most part, by the package of bills to establish a sustainable long-term energy plan recently passed by the Michigan House of Representatives, discussed below. Looking forward, additional issues, such as rising prices for coal and other commodities, health care and higher levels of capital spending, will result in us taking meaningful action to address our costs while continuing to provide quality customer service. We will utilize the DTE Energy Operating System and the Performance Excellence Processcontinue to seek opportunities to improve productivity, remove waste and decrease our costs while improving customer satisfaction.
Long term, we will be required to invest an estimated $2.4 billion on emission controls through 2018. We intend to seek recovery of these costsinvestments in future rate cases.
Additionally, our service territory may require additional generation capacity. A new base-load generating plant has not been built within the State of Michigan in over 20 years. Should our regulatory environment be conducive to such a significant capital expenditure, we may build, upgrade or co-invest in a base-load coal facility or a new nuclear plant. While weWe have not decided on construction of a new base-load nuclear plant,plant; however, in February 2007 we announced that we will preparepreparation of a license application for construction and operation of a new nuclear power plant on the site of Fermi 2. By completing the license application before the end of 2008, we may qualify for financial incentives under the Federal Energy Policy Act of 2005. We are also studying the possible transfer of a gas-fired peaking electric generating plant from our non-utility operations to our electric utility to support future power generation requirements.
The following variables, either individually or in combination, or acting alone, could impact our future results:
 • The amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals or new legislation;
 
 • ourOur ability to reduce costs and maximize plant and distribution system performance;
 
 • variationsVariations in market prices of power, coal and gas;
 
 • economicEconomic conditions within the State of Michigan;
 
 • weather,Weather, including the severity and frequency of storms;
 
 • levelsThe level of customer participation in the electric Customer Choice program; and
 
 • Any potential new federal and state environmental, renewable energy and energy efficiency requirements.
We expect cash flows and operating performance will continueIn April 2008, a package of bills to be at risk due toestablish a sustainable, long-term energy plan was passed by the electric Customer Choice program until the issues associated with this program are adequately addressed. We will accrue as regulatory assets any future unrecovered generation-related fixed costs (stranded costs) due to electric Customer Choice that we believe are recoverable under Michigan legislation and MPSC orders. We cannot predict the outcomeHouse of these matters. See Note 4Representatives. Key provisions of the Notes to Consolidated Financial Statements.bills include:
In January 2007, the MPSC submitted the State of Michigan’s 21st Century Energy Plan to the Governor of Michigan. The plan recommends that Michigan’s future energy needs be met through a combination of renewable resources and cleanest generating technology, with significant energy savings achieved by increased energy efficiency. The plan also recommends:
a requirement that all retail electric suppliers obtain at least 10 percent of their energy supplies from

5

 • renewable resources by 2015;A 10 percent limit on the electric Customer Choice program. Once customers representing 10 percent of a utility’s load have elected to receive their generation from an alternate electricity supplier, remaining customers would be maintained on full, bundled utility service. As of March 31, 2008, approximately 2 percent of Detroit Edison’s load was on the electric Customer Choice program. The bill also codifies prior MPSC requirements for customers returning to full utility service.
 
 • an opportunityA requirement that the MPSC set rates based on cost-of-service for utility-built generation, contingent uponall customer classes, eliminating the grantingcurrent subsidy for residential customers included in business customer rates. Elimination of the subsidy (de-skewing) would be phased in over a certificatefive year period. Rates for schools and other qualified educational institutions would be immediately set at their cost of need and competitive bidding of engineering, procurement and construction services;service.
 
 • investigatingA 12 month hard-stop deadline for the costMPSC to complete a rate case and the ability for the utility to self-implement rate changes six months after a rate filing, bringing Michigan in line with many other states. If the final rate case order leads to lower rates than the utility had self-implemented, the utility would refund, with interest, the difference. In addition, utility rate cases would be based on a forward test year. The bill also provides organizational changes which may enable the MPSC to obtain increased funding to hire staff to meet the new timetable.

5

•A Certificate of Need (CON) process for capital projects costing more than $500 million. The MPSC would be required to review for prudency proposed investments in new generating assets, acquisition of existing power plants, major upgrades of power plants, and long-term power purchase agreements. Utilities would also be provided the opportunity to recover interest expense during construction. As part of the CON process, the MPSC would be directed to establish and approve a requirement to bury certain power lines;financing plan and the recovery of new investments in customer rates.
 
 • creationA review and approval process, including evaluation criteria, for the MPSC for proposed utility merger and acquisitions in Michigan.
•A renewable portfolio standard (RPS) of a Michigan Energy Efficiency Program, administered4% by a third party under the direction2012 and 10% by 2015. Qualifying renewable energy sources would include wind, biomass, solar, hydro, geothermal, waste industrial gases and industrial thermal energy. After passage of the new law, the MPSC would establish a per meter surcharge to fund the RPS requirements. The monthly surcharge is limited to $3 for residential customers, $16.58 for commercial customers and $187.50 for industrial customers. The recovery mechanism starts prior to actual construction in order to smooth the rate impact for customers. Within 5 months of the passage of the new law, the utilities would file an RPS plan with initial funding estimatedthe MPSC. A utility will not have to comply with the RPS standards if the MPSC determines that the added costs of meeting the RPS standard exceed the per meter caps. The bills specify that a utility can build up to 33 percent of the generation required to meet the RPS. An additional 33 percent would be developed by others and sold to the utility. The remaining renewable generation would be contracted through long-term power purchase agreements (PPA).
•A requirement for utilities to create specific efficiency programs for each customer class including incentives for meeting performance goals. For electric sales, the program would target 0.3 percent annual savings in 2008/2009, ramping up to 1 percent annual savings by 2012. For natural gas sales, the targeted annual savings start at $68 million.0.1 percent in 2008/2009 before ramping up to 0.75 percent by 2012. The MPSC may allow a utility to recover over time the actual costs of its efficiency programs in base rates. Costs would be limited to 2 percent maximum of total utility revenues (1.5 percent of business revenues). The bill would also allow a natural gas utility that spends at least 0.5 percent of its revenues on energy efficiency programs to decouple revenues from volumetric sales, adjusting for sales volumes above or below forecasted levels. Similar to the RPS bills, a cost test would be implemented to ensure reasonable costs. If a utility spends at the MPSC approved levels, it would be considered in full compliance even if the savings targets are not met.
We continueThe bills move to review the energy plan and monitor legislativeMichigan Senate where action on some of its components. Without knowing how or if the plan will be fully implemented, weis anticipated by mid-summer 2008. We are unable to predict the impact on the Companyoutcome of the implementationlegislative process and the impact of the plan.
ENTERPRISE BUSINESS SYSTEMS
In 2003, we beganlegislative process to the development of our Enterprise Business Systems (EBS) project, an enterprise resource planning system initiative to improve existing processes and to implement new core information systems, relating to finance, human resources, supply chain and work management. As part of this initiative, we are implementing EBS software including, among others, products developed by SAP AG. The first phase of implementation occurred in 2005 in the regulated electric fossil generation unit. The second phase of implementation began in April 2007. The implementation and operation of EBS will be continuously monitored and reviewed and should ultimately strengthen our internal control structure and lead to increased cost efficiencies. Although our implementation plan includes detailed testing and contingency arrangements, we can provide no assurance that complications will not arise that could interrupt our operations. We expect EBS to be fully implemented by the end of 2007.Company.  

6

Part I — Item 4.
CONTROLS AND PROCEDURES
(a)Evaluation of disclosure controls and procedures
Management of the Company carried out an evaluation, under the supervision and with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in the Securities Exchange Act of 1934 (Exchange Act) Rules 13a-15(e) and 15d-15(e)) as of September 30, 2007,March 31, 2008, which is the end of the period covered by this report. Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that such controls and procedures are effective in ensuring that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be met.attained.
(b) Changes in internal control over financial reporting
In April 2007, we began implementing the second phase of our Enterprise Business Systems (EBS) project. EBS is an enterprise resource planning system initiative to improve existing processes and to implement new core information systems, relating to finance, human resources, supply chain and work management. Changes were made, and will be made, to many aspects of our internal control over financial reporting to adapt to EBS, and we are taking the necessary precautions to ensure that the transition to EBS will not have a material negative impact on our internal control over financial reporting. However, testing of the effectiveness of these controls has not been completed and, therefore, we can provide no assurance that internal control issues will not arise.
There have been no other changes in the Company’s internal control over financial reporting during the quarter ended September 30, 2007March 31, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

7

Part I – Item 1.
The Detroit Edison Company
Consolidated Statements of Operations (unaudited)(Unaudited)
                        
 Three Months Ended Nine Months Ended  Three Months Ended 
 September 30 September 30  March 31 
(in Millions) 2007 2006 2007 2006  2008 2007 
Operating Revenues
 $1,403 $1,460 $3,707 $3,685  $1,153 $1,094 
              
  
Operating Expenses
  
Fuel and purchased power 518 539 1,274 1,257  402 354 
Operation and maintenance 386 277 1,114 991  358 348 
Depreciation and amortization 203 311 583 646  192 182 
Taxes other than income 63 64 204 198  62 72 
Asset (gains) and reserves, net 6  (1) 12  (1)
Other reserves — 7 
              
 1,176 1,190 3,187 3,091  1,014 963 
              
  
Operating Income
 227 270 520 594  139 131 
              
  
Other (Income) and Deductions
  
Interest expense 73 60 222 208  76 74 
Interest income  (2)  (1)  (5)  (2)  (1)  (1)
Other income  (8)  (9)  (26)  (22)  (12)  (11)
Other expenses 7 9 22 29  11 9 
              
 70 59 213 213  74 71 
              
 
Income Before Income Taxes
 157 211 307 381  65 60 
  
Income Tax Provision
 50 73 100 128  24 20 
              
  
Income Before Accounting Change
 107 138 207 253 
 
Cumulative Effect of Accounting Change, net of tax
 — — — 1 
         
 
Net Income
 $107 $138 $207 $254  $41 $40 
              
See Notes to Consolidated Financial Statements (Unaudited)

8

The Detroit Edison Company
Consolidated Statements of Financial Position (Unaudited)
                
 September 30 December 31  March 31 December 31 
(in Millions) 2007 2006  2008 2007 
ASSETS
  
Current Assets
  
Cash and cash equivalents $43 $27  $30 $47 
Restricted cash 87 132  80 135 
Accounts receivable (less allowance for doubtful accounts of $86 and $72, respectively 
Accounts receivable (less allowance for doubtful accounts of $94 and $93, respectively) 
Customer 684 601  683 727 
Collateral held by others 37 —  33 32 
Affiliates 15 19  11 3 
Other 24 51  16 58 
Accrued power supply cost recovery revenue 115 116  25 75 
Notes receivable from affiliates 139 — 
Inventories  
Fuel 145 136  157 150 
Materials and supplies 149 130  169 165 
Prepaid property taxes 88 34 
Other 5 20  87 60 
          
 1,531 1,266  1,291 1,452 
          
  
Investments
  
Nuclear decommissioning trust funds 825 740  797 824 
Other 96 89  107 111 
          
 921 829  904 935 
          
  
Property
  
Property, plant and equipment 14,352 13,916  14,481 14,372 
Less accumulated depreciation  (5,732)  (5,580)
Accumulated depreciation  (5,723)  (5,640)
          
 8,620 8,336  8,758 8,732 
          
  
Other Assets
  
Regulatory assets 2,969 2,862  2,491 2,511 
Securitized regulatory assets 1,154 1,235  1,095 1,124 
Intangible assets 9 9  14 9 
Other 76 74  125 122 
          
 4,208 4,180  3,725 3,766 
          
  
Total Assets
 $15,280 $14,611  $14,678 $14,885 
          
See Notes to Consolidated Financial Statements (Unaudited)

9

The Detroit Edison Company
Consolidated Statements of Financial Position (Unaudited)
                
 September 30 December 31  March 31 December 31 
(in Millions, Except Shares) 2007 2006  2008 2007 
LIABILITIES AND SHAREHOLDER’S EQUITY
  
Current Liabilities
  
Accounts payable 
Affiliates $426 $84 
Other 312 327 
Accounts payable – affiliates $140 $138 
Accounts payable – other 351 396 
Accrued interest 65 79  66 77 
Dividends payable 76 76  76 76 
Accrued vacations 46 77  57 52 
Income and other taxes payable 220 26 
Short-term borrowings 240 277 
Short-term borrowings – affiliates 290 277 
Short-term borrowings – other 440 406 
Current portion of long-term debt, including capital leases 186 142  181 174 
Other 232 262  250 243 
          
 1,803 1,350  1,851 1,839 
          
  
Long-term Debt (net of current portion)
 
Long-Term Debt (net of current portion)
 
Mortgage bonds, notes and other 3,461 3,515  3,221 3,473 
Securitization bonds 1,064 1,184  996 1,065 
Capital lease obligations 44 50  40 42 
          
 4,569 4,749  4,257 4,580 
          
  
Other Liabilities
  
Deferred income taxes 1,755 1,928  1,800 1,825 
Regulatory liabilities 604 255  574 583 
Asset retirement obligations 1,111 1,069  1,165 1,160 
Unamortized investment tax credit 97 105  92 95 
Nuclear decommissioning 129 119  130 134 
Accrued pension liability 376 364  47 47 
Accrued postretirement liability 1,064 1,055  818 816 
Other 501 502  500 503 
          
 5,637 5,397  5,126 5,163 
          
  
Commitments and Contingencies (Notes 4 and 6)
 
Commitments and Contingencies (Notes 5 and 8)
 
  
Shareholder’s Equity
  
Common stock, 400,000,000 shares authorized, 138,632,324 shares issued and outstanding 2,771 2,596 
Common stock, $10 par value, 400,000,000 shares authorized, and 138,632,324 shares issued and outstanding 2,946 2,771 
Retained earnings 495 516  493 528 
Accumulated other comprehensive income 5 3  5 4 
          
 3,271 3,115  3,444 3,303 
          
  
Total Liabilities and Shareholder’s Equity
 $15,280 $14,611  $14,678 $14,885 
          
See Notes to Consolidated Financial Statements (Unaudited)

10

The Detroit Edison Company
Consolidated Statements of Cash Flows (Unaudited)
        
 Nine Months Ended         
 September 30  Three Months Ended 
 2007 2006  March 31 
(in Millions)(in Millions)  2008 2007 
Operating Activities
  
Net Income $207 $254  $41 $40 
Adjustments to reconcile net income to net cash from operating activities:  
Depreciation and amortization 583 646  192 182 
Deferred income taxes  (191) 31   (14)  (48)
Asset (gains) and reserves, net 12  (1)  (1) 7 
Changes in assets and liabilities, exclusive of changes shown separately 367  (252) 113 41 
          
Net cash from operating activities 978 678  331 222 
          
  
Investing Activities
  
Plant and equipment expenditures  (598)  (735)  (213)  (253)
Proceeds from sale of assets, net — 22 
Restricted cash for debt redemptions 45 43  55 47 
Proceeds from sale of nuclear decommissioning trust fund assets 227 136  52 57 
Investment in nuclear decommissioning trust funds  (254)  (163)  (61)  (66)
Notes receivable from affiliates  (139)  —
Other investments  (16)  (12)  (12) — 
          
Net cash used for investing activities  (735)  (709)  (179)  (215)
          
  
Financing Activities
  
Issuance of long-term debt — 247 
Redemption of long-term debt  (132)  (123)  (74)  (73)
Repurchase of long-term debt  (238) — 
Short-term borrowings, net  (37)  (16) 47  (35)
Capital contribution by parent company 175 150  175 175 
Dividends on common stock  (228)  (229)  (76)  (76)
Other  (5)  (6)  (3) — 
          
Net cash from (used for) financing activities  (227) 23 
Net cash used for financing activities  (169)  (9)
          
  
Net Increase (Decrease) in Cash and Cash Equivalents
 16  (8)
Net Decrease in Cash and Cash Equivalents
  (17)  (2)
Cash and Cash Equivalents at Beginning of the Period
 27 26  47 27 
          
Cash and Cash Equivalents at End of the Period
 $43 $18  $30 $25 
          
See Notes to Consolidated Financial Statements (Unaudited)

11

The Detroit Edison Company
Consolidated Statements of Changes in Shareholder’s Equity and
and Comprehensive Income (unaudited)(Unaudited)
                                            
 Accumulated   Accumulated  
 Other   Additional Other  
(Dollars in Millions, Common Stock Retained Comprehensive  
Shares in Thousands) Shares Amount Earnings Income Total
Balance, December 31, 2006 138,632 $2,596 $516 $3 $3,115 
 Common Stock Paid In Retained Comprehensive  
(Dollars in Millions, shares in thousands) Shares Amount Capital Earnings Income Total
  
Balance, December 31, 2007 138,632 $1,386 $1,385 $528 $4 $3,303 
Net income — — 207 — 207  — — — 41 — 41 
Capital contribution by parent company — 175 — — 175  — — 175 — — 175 
Dividends declared on common stock — —  (228) —  (228) — — —  (76) —  (76)
Net change in unrealized gains on investments, net of tax — — — 2 2  — — — — 1 1 
Balance, September 30, 2007
 138,632 $2,771 $495 $5 $3,271 
Balance, March 31, 2008
 138,632 $1,386 $1,560 $493 $5 $3,444 
The following table displays other comprehensive income for the nine-monththree-month periods ended September 30:March 31:
                
(in Millions) 2007 2006  2008 2007 
Net income $207 $254  $41 $40 
Other comprehensive income, net of tax:  
Net unrealized gains on investments:  
Amounts reclassified from income, net of taxes of $1 and $-, respectively 2 — 
Amounts reclassified to income, net of taxes of $1 and $1 1 2 
          
Comprehensive income $209 $254  $42 $42 
          
See Notes to Consolidated Financial Statements (Unaudited)

12

The Detroit Edison Company
Notes to Consolidated Financial Statements (unaudited)(Unaudited)
NOTE 1 — GENERAL
These Consolidated Financial Statements should be read in conjunction with the Notes to Consolidated Financial Statements included in the 20062007 Annual Report on Form 10-K.
The accompanying Consolidated Financial Statements are prepared using accounting principles generally accepted in the United States of America. These accounting principles require us to use estimates and assumptions that impact reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from our estimates.
The Consolidated Financial Statements are unaudited, but in our opinion include all adjustments necessary for a fair presentation of such financial statements. All adjustments are of a normal recurring nature, except as otherwise disclosed in these Consolidated Financial Statements and Notes to Consolidated Financial Statements. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2007.
References in this report to “we,” “us,” “our,” or “Company” are to The Detroit Edison Company and its subsidiaries, collectively.2008.
Asset Retirement Obligations
We haveThe Company records asset retirement obligations in accordance with SFAS No. 143,Accounting for Asset Retirement Obligationsand FIN 47,Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. The Company has a legal retirement obligation for the decommissioning costs of ourfor its Fermi 1 and Fermi 2 nuclear plants. We haveThe Company has conditional retirement obligations for the disposal of asbestos at certain of ourits power plants. To a lesser extent, we havethe Company has conditional retirement obligations at certain service centers, and disposal costs for PCB contained within transformers and circuit breakers. We recognizeThe 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.
Timing differences arise in the expense recognition of legal asset retirement costs that we arethe Company is currently recovering in rates. We deferThe Company defers such differences under SFAS No. 71,Accounting for the Effects of Certain Types of Regulation.
A reconciliation of the asset retirement obligations for the 2007 nine-month periodthree months ended March 31, 2008 follows:
        
(in Millions)  
Asset retirement obligations at January 1, 2007 $1,069 
Asset retirement obligations at January 1, 2008 $1,170 
Accretion 53  19 
Liabilities settled  (5)  (2)
Revision in estimated cash flows 3   (10)
      
Asset retirement obligations at September 30, 2007 $1,120 
Asset retirement obligations at March 31, 2008 1,177 
Less amount included in current liabilities  (9)  (12)
      
 $1,111  $1,165 
      
A significant portionApproximately $1 billion of the asset retirement obligations representsrepresent nuclear decommissioning liabilities whichthat are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear power plant.

13

Retirement Benefits and Trusteed Assets
The following details the components of net periodic benefit costs for qualified and non-qualified pension benefits and other postretirement benefits follow:for the three months ended March 31:
                 
          Other Postretirement 
  Pension Benefits  Benefits 
(in Millions) 2007  2006  2007  2006 
             
Three Months Ended September 30
Service cost $13  $12  $13  $10 
Interest cost  36   34   21   22 
Expected return on plan assets  (36)  (34)  (13)  (12)
Amortization of                
Net loss  12   11   13   14 
Prior service cost  2   2   1   1 
Net transition liability  —   —   2   2 
Special termination benefits  3   14   —   2 
             
Net periodic benefit cost $30  $39  $37  $39 
             
                
 Other Postretirement                 
 Pension Benefits Benefits  Pension Benefits Other Postretirement Benefits 
(in Millions) 2007 2006 2007 2006  2008 2007 2008 2007 
         
Nine Months Ended September 30
Service cost $38 $38 $36 $34  $12 $13 $12 $11 
Interest cost 104 102 67 66  37 34 23 23 
Expected return on plan assets  (111)  (102)  (40)  (37)  (41)  (37)  (14)  (13)
Amortization of 
Net loss 34 34 38 40 
Amortization of: 
Net actuarial loss 7 11 7 12 
Prior service cost 5 6 3 3  2 2 — 1 
Net transition liability — — 5 5  — — 1 2 
Special termination benefits 8 28 2 3  — 4 — 2 
                  
Net periodic benefit cost $78 $106 $111 $114  $17 $27 $29 $38 
                  
Special termination benefitsTermination Benefits in the above tables representtable represents costs associated with ourthe Company’s Performance Excellence Process.
The Company expects to contribute $150 million to its qualified pension plans during its fiscal year 2008. No contributions have been made to the plans for the three months ended March 31, 2008.
The Company expects to contribute $5 million to its non-qualified pension plans during its fiscal year 2008. No contributions have been made to the plans for the three months ended March 31, 2008.
The Company expects to contribute $76 million to its postretirement medical and life insurance benefit plans during its fiscal year 2008. No contributions have been made to the plans for the three months ended March 31, 2008.
Income Taxes
UncertainThe Company’s effective income tax rate for the three months ended March 31, 2008 was 37% as compared to 33% for the three months ended March 31, 2007. The increase in effective tax rate was primarily attributable to higher state income taxes related to the Michigan Business Tax Positions
We adopted the provisions of FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109 (FIN 48)onwhich was effective January 1, 2007. This interpretation prescribes a recognition threshold and a measurement attribute for the financial statement reporting of tax positions taken or expected to be taken on a tax return. As a result of the implementation of FIN 48, we recognized a $0.7 million decrease in liabilities which was accounted for as an increase to the January 1, 2007 balance of retained earnings. The total amount of unrecognized2008.
Unrecognized tax benefits amounted to $11.9 millionat March 31, 2008 and $6 million at January 1,December 31, 2007, and September 30, 2007, respectively. The declineif recognized, would not materially impact our effective tax rate. We do not anticipate any significant changes in the unrecognized tax benefits during the nine months ended September 30, 2007 was attributable to settlements with the Internal Revenue Service (IRS) for the 2002next twelve months.
Short-Term Credit Arrangements and 2003 tax years. Unrecognized tax benefits totaling $0.1Borrowings
Detroit Edison has a $200 million at January 1, 2007, if recognized, would favorably impact our effective tax rate. None of the unrecognized tax benefits at September 30, 2007 would impact our effective tax rate if recognized.
We recognize interest and penalties pertaining to income taxes in Interest expense and Other expenses, respectively, on our Consolidated Statements of Operations. Accrued interest pertaining to income taxes totaled $0.9 million and $0.3 million at January 1, 2007 and September 30, 2007, respectively. We had no accrued penalties pertaining to income taxes. We recognized interest expense related to income taxes of $0.1 million and $0.4 million for the three and nine months ended September 30, 2007, respectively. We recognized interest expense related to income taxes of $0.8 million for both of the three and nine months ended September 30, 2006.
Our U.S. federal income tax returns for years 2004 and subsequent years remain subject to examinationshort-term financing agreement secured by the IRS. We also file tax returns incustomer accounts receivable. This agreement contains certain state jurisdictions with varying statutes of limitation.

14

Michigan Business Tax
On July 12, 2007, the Michigan Business Tax (MBT) was enacted by the State of Michigan to replace the Michigan Single Business Tax (MSBT) effective January 1, 2008.
The MBT is comprised of the following:
•An apportioned modified gross receipts tax of 0.8 percent; and
•An apportioned business income tax of 4.95 percent.
The MBT provides credits for Michigan business investment, compensation, and research and development. The MBT will be accounted for as an income tax.
Effective with the enactment of the MBT in the third quarter of 2007, a state deferred tax liability of $296 million was recognized by the Company for cumulative differences between book and tax assets and liabilities. Effective September 30, 2007, legislation was adopted by the State of Michigan creating a deduction for businesses that realize an increase in their deferred tax liability due to the enactment of the MBT. Therefore, a deferred tax asset of $296 million was establishedcovenants related to the future deduction.delinquency of accounts receivable. At March 31, 2008, Detroit Edison exceeded the default-to-delinquency ratio, giving the lender the right to terminate the agreement. Detroit Edison has received a letter agreement from the lender waiving its right to terminate. The deduction will be claimed during the period of 2015 through 2029. The recognition of the enactment of the MBT did not have an impact on our income tax provision for the three and nine months endedwaiver expires September 30, 2007.
2008. The $296Company had an outstanding balance of $200 million of deferred tax liabilities and assets recognized were offset by corresponding regulatory assets$125 million at March 31, 2008 and liabilities in accordance with SFAS No. 71,Accounting for the Effects of Certain Types of Regulation,as the impacts of the deferred tax liabilities and assets recognized upon enactment and amendment of the MBT will be reflected in our rates.December 31, 2007, respectively.
Stock-Based Compensation
Effective January 1, 2006, ourOur parent company, DTE Energy, adoptedfollows SFAS No. 123(R),Share-Based Payment, (SFAS 123(R),using the modified prospective transition method. We receiveThe Company received an allocation of costs associated with stock compensation and the related impact of cumulative accounting adjustments. OurThe allocation for the three months ended September 30,March 31, 2008 and 2007 and 2006 for stock-based compensation expense was approximately $3 million and $2$4 million, respectively, while such allocation was $14 million and $10 million for the nine months ended September 30, 2007 and 2006, respectively. The cumulative effect of the adoption of SFAS 123(R), effective January 1, 2006, was an increase in net income of $1 million for the nine months ended September 30, 2006 as a result of estimating forfeitures for previously granted stock awards and performance shares.

1514

Consolidated Statements of Cash Flows
A detailed analysisThe following provides detail of the changes in assets and liabilities that are reported in the Consolidated Statements of Cash Flows, follows:and supplementary cash information:
         
  Nine Months Ended 
  September 30 
  2007  2006 
(in Millions)        
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
        
Accounts receivable, net $(103) $(116)
Inventories  (25)  (28)
Accrued pensions  36   104 
Accounts payable  329   6 
Accrued PSCR refund  2   (162)
Income taxes payable  173   76 
General taxes  32   10 
Postretirement obligation  9   21 
Other assets  (303)  (136)
Other liabilities  217   (27)
       
  $367  $(252)
       
Supplementary cash and non-cash information follows:
         
  Nine Months Ended
  September 30
(in Millions) 2007 2006
Cash Paid for:        
Interest paid (excluding interest capitalized) $235  $215 
Income taxes paid, net of refunds $112  $1 
Under an inter-company credit agreement, we had short-term notes receivable from DTE Energy and affiliates. Short-term excess cash or cash shortfalls are remitted to or funded by DTE Energy. This credit arrangement involves the charge and payment of interest at rates that approximate market.
         
  Three Months Ended 
  March 31 
(in Millions) 2008  2007 
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
        
Accounts receivable, net $76  $(9)
Inventories  (11)  7 
Accrued pensions  7   13 
Accounts payable  —   (2)
Accrued PSCR refund  52   49 
Income taxes payable  3   62 
General taxes  (9)  11 
Postretirement obligation  2   5 
Other assets  4   (35)
Other liabilities  (11)  (60)
       
  $113  $41 
       
         
Supplementary Cash Information
        
Cash paid for interest (net of interest capitalized) $87  $114 
Cash paid for income taxes $1  $1 
Asset (gains) andOther reserves net
Asset (gains) andOther reserves netwere $6$7 million forin the thirdfirst quarter of 2007 and $12 million for the nine-month period ending September 30, 2007, representing reservesa reserve for a loan guaranty related to the prior sale of Detroit Edison’s steam heating business to Thermal Ventures II, LP (Thermal).LP.
NOTE 2 – NEW ACCOUNTING PRONOUNCEMENTS
Fair Value Accounting
In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. It emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Fair value measurement should be determined based on the assumptions that market participants would use in pricing an asset or liability. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We are currently assessingEffective January 1, 2008, the effectsCompany adopted SFAS No. 157. As permitted by FASB Staff Position FAS No. 157-2, the Company has elected to defer the effective date of this statement,SFAS No. 157 as it pertains to non-financial assets and have not yet determined its impact on our consolidated financial statements.liabilities to January 1, 2009. See also Note 3.
In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115. This standardStatement permits an entity to choose to measure many financial instruments and certain other items at fair value. The fair value option established by SFAS No. 159 permits all entities to choose to measure eligible items at fair value at specified election dates. An entity will report in earnings unrealized gains and losses on items, for which the fair value option has been elected, at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to entire instruments and not to portions of instruments. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. WeAt January 1, 2008, the Company elected not to use the fair value option for financial assets and liabilities held at that date.

15

Business Combinations
In December 2007, the FASB issued SFAS No. 141(R),Business Combinations,to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish this, SFAS No. 141(R) requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information needed to evaluate and understand the nature and financial effect of the business combination. SFAS No. 141(R) is applied prospectively to business combinations entered into by the Company after January 1, 2009, with earlier adoption prohibited. The Company will apply the requirements of SFAS No. 141 (R) to business combinations consummated after January 1, 2009.
Noncontrolling Interests in Consolidated Financial Statements
In December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51.This Statement establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 is effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2008. Earlier adoption is prohibited. This Statement shall be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, except for the presentation and disclosure requirements. The presentation and disclosure requirements shall be applied retrospectively for all periods presented. The Company will adopt SFAS No. 160 as of January 1, 2009 and is currently assessing the effects of SFAS No. 160 on its consolidated financial statements.
Disclosures about Derivative Instruments and Hedging Activities
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133. This Statement requires enhanced disclosures about an entity’s derivative and hedging activities. SFAS No. 161 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 currentlyencouraged but not required. The Company will adopt SFAS No. 161 on January 1, 2009.
Offsetting Amounts Related to Certain Contracts
In April 2007, the FASB issued FSP FIN 39-1,Amendment of FASB Interpretation No. 39. This FSP permits the Company to offset the fair value of derivative instruments with cash collateral received or paid for those derivative instruments executed with the same counterparty under a master netting arrangement. As a result, the Company will be permitted to record one net asset or liability that represents the total net exposure of all derivative positions under a master netting arrangement. The decision to offset derivative positions under master netting arrangements remains an accounting policy choice. The guidance in this FSP is effective for fiscal years beginning after November 15, 2007. It is to be applied retrospectively by adjusting the financial statements for all periods presented. The Company adopted FSP FIN 39-1 as of January 1, 2008. At adoption, the Company chose to offset the collateral amounts against the fair value of derivative assets and liabilities, reducing both the Company’s total assets and total liabilities.
NOTE 3 – FAIR VALUE
Effective January 1, 2008, the Company adopted SFAS No. 157. This Statement defines fair value, establishes a framework for measuring fair value and expands the disclosures about fair value measurements. The Company has elected the option to defer the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009.
SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The Company makes certain assumptions that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.
SFAS No. 157 establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. SFAS No. 157 requires that assets and liabilities be classified in their entirety based on the lowest level of input that is significant to the fair value measurement. 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 by SFAS No.157 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.
The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of March 31, 2008:
                 
              Net Balance at 
(in Millions) Level 1  Level 2  Level 3  March 31, 2008 
Assets:
                
Nuclear decommissioning trusts $474  $323  $—  $797 
Employee benefit trust investments  —   60   —   60 
Derivative assets  —   —   2   2 
             
Total $474  $383  $2  $859 
             
     
Liabilities:
                
Deferred compensation $—  $(2) $—  $(2)
Derivative liabilities  —   —   (1)  (1)
             
Total $—  $(2) $(1) $(3)
             
     
Net Assets at March 31, 2008 $474  $381  $1  $856 
             
Nuclear Decommissioning Funds
The trust fund investments have been established to satisfy Detroit Edison’s nuclear decommissioning obligations. The nuclear decommissioning trust fund investments hold debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued using quoted prices in actively traded markets. Non-exchange traded fixed income securities are valued based upon quotations available from brokers or pricing services.
Employee Benefit Trust Investments
The employee benefit trust investments shown in the fair value table are invested in commingled funds and institutional mutual funds holding equity or fixed income securities. The commingled funds and institutional mutual funds which hold exchange-traded equity securities are valued using quoted prices in actively traded markets. Non-exchange-traded fixed income securities are valued based upon quotations available from brokers or pricing services.
Deferred Compensation Liabilities
Deferred compensation plans allow eligible participants to defer a portion of their compensation. The participant is able to designate the investment of the deferred compensation to investments available under the 401(k) plan offered by the Company, although the Company does not actually purchase the investments. The deferred compensation liability is determined based upon the fair values of the mutual funds and equity securities designated in each participant’s account.
Derivative Assets and Liabilities
Derivative assets and liabilities are comprised of physical and financial derivative contracts, including forwards, options and financial transmission rights. 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. Other derivatives contracts are valued based upon a variety of inputs including commodity market prices, interest rates, credit ratings, default rates, market-based seasonality and basis differential factors. Mathematical valuation models are used for derivatives for which external market data is not readily observable.

16

assessing the effects of this statement, and have not yet determined its impact on our consolidated financial statements.
Accounting for Defined Benefit Pension and Other Postretirement Plans
In September 2006, the FASB issued SFAS No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an Amendment of FASB Statements No. 87, 88, 106, and 132(R).SFAS 158 requires companies to (1) recognize the overfunded or underfunded status of defined benefit pension and defined benefit other postretirement plans in its financial statements, (2) recognize as a component of other comprehensive income, net of tax, the actuarial gains or losses and the prior service costs or credits that arise during the period but are not immediately recognized as components of net periodic benefit cost, (3) recognize adjustments to other comprehensive income when the actuarial gains or losses, prior service costs or credits, and transition assets or obligations are recognized as components of net periodic benefit cost, (4) measure postretirement benefit plan assets and plan obligations as of the date of the employer’s statement of financial position, and (5) disclose additional information in the notes to financial statements about certain effects on net periodic benefit cost in the upcoming fiscal year that arise from delayed recognition of the actuarial gains and losses and the prior service costs or credits.
We adopted the requirement to recognize the funded status of a defined benefit pension or defined benefit other postretirement plan and the related disclosure requirements on December 31, 2006. We requested and received agreement from the MPSC to record the additional liability amounts on the Statements of Financial Position as a regulatory asset.
The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. The Statement provides two options for the transition to a fiscal year end measurement date. We have not yet determined which of the available transition measurement options we will use.
NOTE 34 – RESTRUCTURING
Restructuring – Performance Excellence Process
In mid-2005, we2005, the Company initiated a company-wide review of ourits operations called the Performance Excellence Process. WeProcess and began a series of focused improvement initiatives within Detroit Edison and associated corporate support functions. We expect thisinitiatives. This process to continue intocontinued as of March 31, 2008.
We haveThe Company incurred CTAcosts to achieve (CTA) restructuring expense for employee severance and other costs. Other costs include project management and consultant support. Pursuant to MPSC authorization, beginning in the third quarter of 2006, Detroit Edison deferred approximately $102 million of CTA in 2006. WeDuring 2007, Detroit Edison deferred CTA costs of $54 million. Detroit Edison began amortizing deferred 2006 costs in 2007 and 2007 deferred costs in 2008 as the recovery of these costs was provided for by the MPSC. Amortization expense amounted to $3was $4 million and $8$3 million for the three and nine months ended September 30,March 31, 2008 and 2007, respectively. WeDetroit Edison deferred approximately $18$4 million and $39$13 million of CTA duringfor the three and nine months ended September 30,March 31, 2008 and 2007, respectively. See Note 4.5.
Amounts expensed are recorded in the Operation and maintenance line on the Consolidated Statements of Operations. Deferred amounts are recorded in the Regulatory assets line on the Consolidated Statements of Financial Position. ExpensesCosts incurred for the three months ended September 30,March 31, 2008 and 2007 and 2006 are as follows:
                         
  Employee Severance Costs (1)  Other Costs  Total Cost 
(in Millions) 2007  2006  2007  2006  2007  2006 
                   
Costs incurred: $3  $18  $16  $10  $19  $28 
                         
Less amounts deferred or capitalized:  3   36   16   41   19   77 
                   
                         
Amount expensed $—  $(18) $—  $(31) $—  $(49)
                   
(1)Includes corporate allocations.

17

Expenses incurred for the nine months ended September 30, 2007 and 2006 are as follows:
                                                
 Employee Severance Costs (1) Other Costs Total Cost  Employee Severance Costs (1) Other Costs Total Cost 
(in Millions) 2007 2006 2007 2006 2007 2006  2008 2007 2008 2007 2008 2007 
             
Costs incurred: $14 $36 $30 $41 $44 $77 
 
Less amounts deferred or capitalized: 14 36 30 41 44 77 
             
Costs incurred $— $8 $4 $7 $4 $15 
Less amounts deferred or capitalized — 8 4 7 4 15 
              
Amount expensed $— $— $— $— $— $—  $— $— $— $— $— $— 
                          
 
(1) Includes corporate allocations.
A liability for future CTA associated with the Performance Excellence Process has not been recognized because we have not met the recognition criteria of SFAS No. 146,Accounting for Costs Associated with Exit or Disposal Activities.
NOTE 4 –5 — REGULATORY MATTERS
Regulation
Detroit Edison is subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to rates and recovery of certain costs. These costs includinginclude the costs of generating facilities, and regulatory assets, conditions of service, accounting, and operating-related matters. Detroit Edison is also regulated by the FERC with respect to financing authorization and wholesale electric activities.
MPSC Show-Cause Order
In March 2006, the MPSC issued an order directing Detroit Edison to show cause by June 1, 2006 why its retail electric rates should not be reduced in 2007. Subsequently, Detroit Edison filed its response explaining why its electric rates should not be reduced in 2007. Theto this order and the MPSC issued an order approving a settlement agreement in this proceeding on August 31, 2006. The order provided for an annualized rate reduction of $53 million for 2006, effective September 5, 2006. Beginning January 1, 2007, and continuing until April 13, 2008, one year from the filing of the general rate case on April 13, 2007, rates were reduced by an additional $26 million, for a total reduction of $79 million annually. The revenue reduction is net of the recovery of the amortization of the costs associated with the implementation of the Performance Excellence Process. The settlement agreement provided for some level of realignment of the existing rate structure by allocating a larger percentage share of the rate reduction to the commercial and industrial customer classes than to the residential customer classes.
As part of the settlement agreement, a Choice Incentive Mechanism (CIM) was established with a base level of electric choice sales set at 3,400 GWh. The CIM prescribes regulatory treatment of changes in non-fuel revenue attributed to increases or decreases in electric Customer Choice sales. The CIM has a deadband of ±200 GWh. If electric Customer Choice sales exceed 3,600 GWh, Detroit Edison will be able to recover 90 percent90% of its reduction in non-fuel revenue from full service customers, up to $71 million. If electric Customer Choice sales fall below 3,200 GWh, Detroit Edison will credit 100 percent100% of the increase in non-fuel revenue to the unrecovered regulatory asset balance. Approximately $27 millionIn March 2008, Detroit Edison filed a reconciliation of its CIM for the year 2007. Detroit Edison’s annual Electric Choice sales for 2007 were 2,239 GWh which was creditedbelow the base level of sales of 3,200 GWh. Accordingly, the Company used the resulting additional non-fuel revenue to thereduce unrecovered regulatory asset balances related to the Regulatory Asset Recovery Surcharge (RARS) mechanism. This reconciliation did not result in the nine months ended September 30, 2007.any rate increase.
2007 Electric Rate Case Filing
Pursuant to the February 2006 MPSC order in Detroit Edison’s rate restructuring case and the August 2006 MPSC order in the settlement of the show cause case, Detroit Edison filed a general rate case on April 13, 2007 based on a 2006 historical test year. The filing with the MPSC requestsrequested a $123 million, or 2.9 percent,2.9%, average increase in Detroit Edison’s annual revenue requirement for 2008.

17

The requested $123 million increase in revenues is required in order to recover significant environmental compliance costs and inflationary increases, partially offset by net savings associated with the Performance Excellence Process. The filing iswas based on a return on equity of 11.25 percent11.25% on an expected 50 percent equity50% capital and 50 percent50% debt capital structure by year-endthe end of 2008.

18

In addition, Detroit Edison’s filing makes,made, among other requests, the following proposals:
 • Make progress toward correcting the existing rate structure to more accurately reflect the actual cost of providing service to customers.business customers;
 
 • Equalize distribution rates between Detroit Edison full service and electric Customer Choice customers.customers;
 
 • Re-establish with modification the CIM originally established in the Detroit Edison 2006 show cause filing. The CIM reconciles changes related to customers moving between Detroit Edison full service and electric Customer Choice.Choice;
 
 • Terminate the Pension Equalization Mechanism.Mechanism;
 
 • Establish an emission allowance pre-purchase plan to ensure that adequate emission allowances will be available for environmental compliance.compliance; and
 
 • Establish a methodology for recovery of the costs associated with preparation of an application for a new nuclear generation facility.
Also in the filing, in conjunctionconnection with Michigan’s 21st21st Century Energy Plan, Detroit Edison has reinstated a long-term integrated resource planning (IRP) process with the purpose of developing the least overall cost plan to serve customers’ generation needs over the next 20 years. Based on the IRP, new base load capacity may be required for Detroit Edison. To protect tax credits available under Federalfederal law, Detroit Edison determined it would be prudent to initiate the application process for a new nuclear unit. Detroit Edison has not made a final decision to build a new nuclear unit. Detroit Edison is preservingunit; however, it has elected to preserve its option to build at some point in the future by beginning the complex nuclear licensing process in 2007. Also,Additionally, beginning the licensing process at the present time positions Detroit Edison to potentially to take advantage of tax incentives of up to $320 million derived from provisions in the 2005 Federal Energy Policy Act, thatwhich will benefit customers. To qualify for these substantial tax credits, a combined operating license application for construction and operation of an advanced nuclear generating plant must be docketed by the Nuclear Regulatory Commission no later than December 31, 2008. Preparation and approval of a combined operating license can take up to 4 years and is estimated to cost at least $60 million. Costs of $13 million related to preparing the combined licensing application have been deferred and included in Other assets as of March 31, 2008.
On August 31, 2007, Detroit Edison filed a supplement to its April 2007 rate case filing. A July 2007 decision by the State of Michigan Court of Appeals of the State of Michigan remanded back to the MPSC the November 2004 order in a prior Detroit Edison rate case that denied recovery of merger control premium costs. The supplemental filing addressed recovery of approximately $61 million related to the merger control premium. The filing also included the impact of the July 2007 enactment of the Michigan Business Tax (MBT), effective in 2008, of approximately $5 million. In addition, Detroit Edison has included the financial impact of the MBT related to its securitization bonds (Fermi nuclear plant assets) of approximately $12 million, partially offset byand other adjustments to the original April 2007 rate case filing of $2 million.adjustments. The net impact of the supplemental changes resultsfiling resulted in an additional revenue requirement of approximately $76 million annually.average increase in Detroit Edison’s annual revenue requirement for 2008.
On February 20, 2008, Detroit Edison filed an update to its April 2007 rate case filing. The update reflected the use of 2009 as the projected test year and included a revised 2009 load forecast; 2009 revised estimates on environmental and advanced metering infrastructure capital expenditures; and adjustments to the calculation of the MBT. The update also included the August 2007 supplemental filing adjustments for the merger control premium, the new MBT and environmental operating and maintenance adjustments. The net impact of the updated filing resulted in an approximately $85 million average increase in Detroit Edison’s annual revenue requirement for 2009. The total filing requested a $284 million increase in Detroit Edison’s annual revenue for 2009. An MPSC order related to this filing is expected in 2008.by early 2009.
Regulatory Accounting Treatment for Performance Excellence Process
In May 2006, weDetroit Edison filed an application with the MPSC to allow deferral of costs associated with the implementation of the Performance Excellence Process, a company-wideCompany-wide cost-savings and performance improvement program. Implementation costs include project management, consultant support and employee severance expenses. WeDetroit Edison sought MPSC authorization to defer and amortize Performance Excellence Process implementation costs for accounting purposes to match the expected savings from the Performance Excellence Process program with the related CTA. We anticipate the

18

The Performance Excellence Process to continue intocontinued as of March 31, 2008. Our CTA is estimated to total approximately $150 million. In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison, commencing in 2006, to defer the incremental CTA.CTA, subject to the MPSC establishing a recovery mechanism in a future rate proceeding. Further, the order providesprovided for Detroit Edison to amortize the CTA deferrals over a ten-year10-year period beginning with the year subsequent to the year the CTA was deferred. At year-end 2006, Detroit Edison recorded deferred CTA costs ofapproximately $102 million and $54 million of CTA in 2006 and 2007, respectively, as a regulatory asset and began amortizing deferred 2006 costs in 2007 as the recovery of these costs was provided for by the MPSC in itsthe order approving the settlement ofin the show cause proceeding. During the three and nine months ended September 30, 2007, Detroit Edison deferred CTA costs of $18 million and $39 million, respectively. Amortization of prior

19

year deferred CTA costs amounted towas $4 million and $3 million and $8 million duringfor the three and nine months ended September 30,March 31, 2008 and 2007, respectively. Detroit Edison deferred approximately $4 million and $13 million of CTA for the three months ended March 31, 2008 and 2007, respectively.
Accounting for Costs Related to Enterprise Business Systems (EBS)
In July 2004, weDetroit Edison filed an accounting application with the MPSC requesting authority to capitalize and amortize costs related to EBS, consisting of computer equipment, software and development costs, as well as related training, maintenance and overhead costs. In April 2005, the MPSC approved a settlement agreement providing for the deferral of up to $60 million of certain EBS costs, thatwhich would otherwise be expensed, as a regulatory asset for future rate recovery starting January 1, 2006. At September 30, 2007,March 31, 2008, approximately $25$26 million of EBS costs have been deferred as a regulatory asset. In addition, EBS costs recorded as plant assets will be amortized over a 15-year period, pursuant to MPSC authorization.
Fermi 2 Enhanced Security Costs Settlement
The Customer Choice and Electricity Reliability Act, as amended in 2003, allows for the recovery of reasonable and prudent costs of new and enhanced security measures required by state or federal law, including providing for reasonable security from an act of terrorism. In December 2006, weDetroit Edison filed an application with the MPSC for recovery of $11.4 million of Fermi 2 Enhanced Security Costs (ESC), discounted back to September 11, 2001 plus carrying costs from that date. In April 2007, the MPSC approved a settlement agreement that authorizes Detroit Edison to recover Fermi-2Fermi 2 ESC incurred during the period of September 11, 2001 through December 31, 2005. The settlement defined Detroit Edison’s ESC, discounted back to September 11, 2001, as $9.1 million plus carrying charges. A total of $13 million, including carrying charges, has been deferred as a regulatory asset. Detroit Edison is authorized to incorporate into its rates an enhanced security factor over a period not to exceed five years. Amortization ofexpense related to this regulatory asset was approximately $2$1 million infor the ninethree months ended September 30, 2007.March 31, 2008.
Reconciliation of Regulatory Asset Recovery Surcharge
In December 2006, Detroit Edison filed a reconciliation of costs underlying its existing Regulatory Asset Recovery Surcharge (“RARS”). In this filing, Detroit Edison replaced estimated costs for 2003–2005 included in the last general rate case with actual costs incurred. Also reflected in the filing was the replacement of estimated revenues with actual revenues collected.RARS. This true-up filing was made to maximize the remaining time for recovery of significant cost increases prior to expiration of the RARS five-year5-year recovery limit under PA 141. Detroit Edison requested a reconciliation of the regulatory asset surcharge to ensure proper recovery by the end of the five year5-year period of: (1) Clean Air Act Expenditures, (2) Capital in Excess of Base Depreciation, (3) MISO Costs and (4) the regulatory liability for the 1997 Storm Charge. In July 2007, the MPSC approved a negotiated RARS deficiency settlement that resulted in a $10 million write downwrite-down of RARS-related costs in 2007. As previously discussed above, the CIM in the MPSC Show-Cause Order will reduce the regulatory asset. Approximately $27$11 million and $2 million was credited to the unrecovered regulatory asset inbalance during the ninethree months ended September 30, 2007.March 31, 2008 and 2007, respectively.
Power Supply Costs Recovery Proceedings
2005 Plan Year– In September 2004, Detroit Edison filed its 2005 PSCR plan case seeking approval of a levelized PSCR factor of 1.82 mills per kWh above the amount included in base rates. In December 2004, Detroit Edison filed revisions to its 2005 PSCR plan case in accordance with the November 2004 MPSC rate order. Included in the factor were power supply costs, transmission expenses and nitrogen oxide (NOx) emission allowance costs. In September 2005, the MPSC approved Detroit Edison’s 2005 PSCR plan case. At December 31, 2005, Detroit Edison recorded an under-recovery of approximately $144 million related to the 2005 plan year. In March 2006, Detroit Edison filed its 2005 PSCR reconciliation. The filingreconciliation that sought approval for recovery of an under-recovery of approximately $144 million at December 31, 2005 from its commercial and industrial customers. The filing included a motion for entry of an order to implement immediately a reconciliation surcharge of 4.96 mills per kWh on the bills of its commercial and industrial customers. The under-collected PSCR expense allocated to residential customers could not be recovered due to the PA 141 rate cap for residential customers, which expired January 1, 2006. In addition to the 2005 PSCR Plan Year Reconciliation,plan year reconciliation, the filing included a reconciliation for the Pension Equalization Mechanism (PEM) for the periods from November 24, 2004 through December 31, 2004 and from January 1, 2005 through December 31, 2005. The PEM reconciliation seeks to allocate and refund approximately $12 million to customers based uponon their contributions to pension expense during the subject periods. In September 2006, the MPSC ordered the Company to roll the entire 2004 PSCR over-collection amount to the Company’sits 2005 PSCR Reconciliation. An order was

20

issued on May 22, 2007 approving a 2005 PSCR undercollectionunder-collection amount of $94 million and the recovery of this amount through a surcharge of 3.50 mills/kWh for 12 months beginning in June 2007. In addition, the order approved Detroit Edison’s proposed PEM reconciliation whichthat was refunded to customers on a bills-rendered basis during June 2007.

19

2006 Plan Year —In September 2005,March 2007, Detroit Edison filed its 2006 PSCR plan case seekingreconciliation that sought approval for recovery of a levelized PSCR factoran under-collection of 4.99 mills per kWh above the amount included in base rates for residential customers and 8.29 mills per kWh above the amount included in base rates for commercial and industrial customers.approximately $51 million. Included in the factor for all customers are fuel2006 PSCR reconciliation filing was the Company’s PEM reconciliation that reflects a $21 million over-collection which is subject to refund to customers. An MPSC order was issued on April 22, 2008 approving the 2006 PSCR under-collection amount of $51 million and power supply costs, including transmission expenses, Midwest Independent Transmission System Operator (MISO) market participation costs, and NOx emission allowance costs. The Company’s PSCR Plan included a matrix which provided for different maximum PSCR factors contingent on varying electric Customer Choice sales levels. The plan also included $97 million forthe recovery of its projected 2005 PSCR under-collection associated with commercial and industrial customers. Additionally, the PSCR plan requested MPSC approval of expense associated with sulfur dioxide emission allowances, mercury emission allowances, and a fuel additive. In conjunction with DTE Energy’s sale of its transmission assets to ITC Transmission in February 2003, the FERC froze ITC Transmission’s rates through December 2004. In approving the sale, FERC authorized ITC Transmission’s recoverythis amount as part of the difference between2007 PSCR factor. In addition, the revenue it would have collected and the actual revenue collected during the rate freeze period. This amount is estimated to be $66 million which is to be included in ITC Transmission’s rates over a five-year period beginning June 1, 2006. This increasedorder approved Detroit Edison’s transmission expense in 2006 by approximately $7 million. The MPSCPEM reconciliation and authorized Detroit Edison in 2004 to recover transmission expenses through the PSCR mechanism.
In December 2005, the MPSC issued a temporary order authorizing the Company to begin implementation of maximum quarterly PSCR factors on January 1, 2006. The quarterly factors reflect a downward adjustmentrefund the $22 million over-recovery, including interest, to customers in the Company’s total power supply costs of approximately 2 percent to reflect the potential variability in cost projections. The quarterly factors allowed the Company to more closely track the costs of providing electric service to our customers and, because the non-summer factors are well below those ordered for the summer months, effectively delay the higher power supply costs to the summer months at which time our customers will not be experiencing large expenditures for home heating. The MPSC did not adopt the Company’s request to recover its projected 2005 PSCR under- collection associated with commercial and industrial customers nor did it adopt the Company’s request to implement contingency factors based upon the Company’s increased costs associated with providing electric service to returning electric Customer Choice customers. The MPSC deferred both of those Company proposals to the final order on the Company’s entire 2006 PSCR Plan. In September 2006, the MPSC issued an order in this case that approved the inclusion of sulfur dioxide emission allowance expense in the PSCR, determined that fuel additive expense should not be included in the PSCR based upon its impact on maintenance expense, found the Company’s determination of third party sales revenues to be correct, and allowed the Company to increase its PSCR factor for the balance of the year in an effort to reverse the effects of the previously ordered temporary reduction. The MPSC declined to rule on the Company’s requests to include mercury emission allowance expense in the PSCR or its request to include prior PSCR over/(under) recoveries in future year PSCR plans. The Company filed its 2006 PSCR reconciliation case in March 2007. The $51 million under-collection amount reflected in that filing is being collected in the 2007 PSCR plan. An MPSC order in this case is expected inMay 2008.
2007 Plan Year —In September 2006, Detroit Edison filed its 2007 PSCR plan case seeking approval of a levelized PSCR factor of 6.98 mills per kWh above the amount included in base rates for all PSCR customers. The Company’s PSCR plan filing included $130 million for the recovery of its projected 2006 PSCR under-collection, bringing the total requested PSCR factor to 9.73 mills/kWh. The Company’s application included a request for an early hearing and temporary order granting such ratemaking authority. The Company’s 2007 PSCR Plan includesplan included fuel and power supply costs, including NOx and sulfur dioxideSO2 emission allowance costs, transmission costs and MISO costs. The Company filed supplemental testimony and briefs in December 2006 supporting its updated request to include approximately $81 million for the recovery of its projected 2006 PSCR under-collection. The MPSC issued a temporary order in December 2006 approving the Company’s request. In addition, Detroit Edison was granted the authority to include all PSCR over/(under) collections in future PSCR plans, thereby reducing the time between refund or recovery of PSCR reconciliation amounts. The Company began to collect its 2007 power supply costs, including the 2006 rollover amount, through a PSCR factor of 8.69 mills/kWh on January 1, 2007. The Company reduced the PSCR factor to 6.69 mills/kWh on July 1, 2007 based on the updated 2007 plan year projections and increased the PSCR Plan year

21

projections.factor to 8.69 mills/kWh on December 1, 2007. In August 2007, the MPSC approved Detroit Edison’s 2007 PSCR plan case and authorized the Company to charge a maximum power supply cost recovery factor of 8.69 mills/kWh in 2007. The Company filed its 2007 PSCR reconciliation case in March 2008. The filing requests recovery of a $44 million PSCR under-collection through its 2008 PSCR plan. Included in the 2007 PSCR reconciliation filing was the Company’s 2007 PEM reconciliation that reflects a $21 million over-collection, including interest and prior year refunds.
2008 Plan Year —In September 2007, Detroit Edison filed its 2008 PSCR plan case seeking approval of a levelized PSCR factor of 9.23 mills/kWh above the amount included in base rates for all PSCR customers. The Company is supporting a total 2008 power supply expense forecast of $1.3 billion whichthat includes $1million$1 million for the recovery of its projected 2007 PSCR undercollection.under-collection. The Company’s PSCR Plan will allow the Company to recover its reasonably and prudently incurred power supply expense including;including fuel costs, purchased and net interchange power costs, NOx and SO2SO2 emission allowance costs, transmission costs and Midwest Independent Transmission System Operator (MISO)MISO costs. Also included in the filing iswas a request for approval of the Company’s emission compliance strategy which includesincluded pre-purchases of emission allowances as well as a request for pre-approval of a contract for capacity and energy associated with a renewable (wind energy)wind energy project. On January 31, 2008, Detroit Edison filed a revised PSCR plan case seeking approval of a levelized PSCR factor of 11.22 mills/kWh above the amount included in base rates for all PSCR customers. The revised filing supports a 2008 power supply expense forecast of $1.4 billion and includes $43 million for the recovery of a projected 2007 PSCR under-collection. On March 11, 2008, the MPSC ordered that Detroit Edison shall not self-implement the 11.22 mills/kWh power supply cost recovery factor proposed in its January 2008 filing. Detroit Edison will continue discussions with the MPSC and other participants in this proceeding in an effort to minimize a potential under-recovery.
Other
OnIn July 3, 2007, the Court of Appeals of the State of Michigan Court of Appeals published its decision with respect to an appeal by among others, The Detroit Edison Companyand others of certain provisions of a November 23, 2004 MPSC order, including reversing the MPSC’s denial of recovery of merger control premium costs. In its published decision, the Court of Appeals held that Detroit Edison is entitled to recover its allocated share of the merger control premium and remanded this matter to the MPSC for further proceedings to establish the precise amount and timing of this recovery. As discussed above, Detroit Edison has filed a supplement to its April 2007 rate case to address the recovery of the merger control premium costs. Other parties have filed requests for leave to appeal to the Michigan Supreme Court from the Court of Appeals decision. Detroit Edison is unable to predict the financial or other outcome of any legal or regulatory proceeding at this time.
We areThe Company is unable to predict the outcome of the regulatory matters discussed herein. Resolution of these matters is dependent upon future MPSC orders and appeals, which may materially impact the financial position, results of operations and cash flows of the Company.

20

NOTE 56 – SHAREHOLDER’S EQUITY
In March 2007,2008, DTE Energy made a capital contribution of $175 million to the Company.
NOTE 7 – LONG-TERM DEBT
Detroit Edison converted $238 million of tax-exempt bonds from an auction rate mode to a weekly rate mode in March 2008 due to a loss of liquidity in the auction rate markets. Detroit Edison then repurchased these bonds and plans to hold them until such time as it can either redeem and reissue the bonds or remarket the bonds in a longer-term mode. In April 2008, $69 million of the tax-exempt bonds were reissued in a weekly rate mode. The reissued bonds are uninsured.
NOTE 68 – COMMITMENTS AND CONTINGENCIES
Environmental
Air-— Detroit Edison is subject to EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. In March 2005, the EPA issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, Detroit Edison has spent approximately $875 million$1.1 billion through 2006. We estimate2007. The Company estimates Detroit Edison future capital expenditures at up to $222$282 million in 20072008 and up to $2$2.4 billion of additional capital expenditures through 2018 to satisfy both the existing and proposed new control requirements.requirements.
Water–— In response to an EPA regulation, Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of the studies to be conducted over the next several years, Detroit Edison may be required to install additional control technologies to reduce the impacts of the water intakes. Initially, it was estimated that Detroit Edison could incur up to approximately $53$55 million over the three4 to five6 years subsequent to 20062007 in additional capital expenditures to comply with these requirements. However, a recent court decision remanded back to the EPA several provisions of the federal regulation whichthat 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.

22

Contaminated Sites-— Detroit Edison conducted remedial investigations at contaminated sites, including twothree former manufactured gas plant (MGP) sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is approximately $11$15 million whichthat was accrued in 20062007 and is expected to be incurred over the next several years. In addition, Detroit Edison expects to make approximately $5$6 million of capital improvements to the ash landfill in 2007.2008.
Labor Contracts
There are several bargaining units for our represented employees. A July 2007 tentative agreement was not ratified by approximately 3,100 of ourthe Company’s represented employees. In OctoberDecember 2007, a new tentativethree-year agreement was reached, subject to ratificationratified by such bargaining unit members. The contracts of the remainingour represented employees expire at various dates in 2008.employees.
Purchase Commitments
Detroit Edison has an Energy Purchase Agreement to purchase steam and electricity from the Greater Detroit Resource Recovery Authority (GDRRA). Under the Agreement, Detroit Edison will purchase steam through 2008 and electricity through June 2024. In 1996, a charge to income was recorded that included a reserve for steam purchase commitments in excess of replacement costs from 1997 through 2008. The reserve for steam purchase commitments totaling $24totals $16 million at September 30, 2007as of March 31, 2008 and is being amortized to fuelFuel, purchased power and purchased powergas expense with non-cash accretion expense being recorded through 2008. We estimateThe Company estimates steam and electric purchase commitments from 20072008 through 2024 will not exceed $386$343 million. In January 2003, wethe Company sold the steam heating business of Detroit Edison to Thermal Ventures II, LP. Due toUnder the terms of the sale, Detroit Edison remains contractually obligated to buy steam from GDRRA until 2008 and recorded an additional liability of $63 million for future commitments.through December 2008. Also, wethe Company guaranteed bank loans of $13 million that Thermal Ventures II, LP may use for capital improvements to the steam heating system. During the threesystem and nine months ended September 30,during 2007 we recorded reserves of $6 million and $13 million respectively, related to the bank loan guarantee.

21

As of September 30, 2007, we wereMarch 31, 2008, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for ourthe Company’s business. These agreements primarily consist of fuel supply commitments. We estimatecommitments and energy trading contracts. The Company estimates that these commitments will be approximately $1.3$1.4 billion from 20072008 through 2020. We2024. The Company also estimateestimates that 20072008 capital expenditures will be $875 million. We haveapproximately $1 billion. The Company has made certain commitments in connection with expected capital expenditures.expenditures.
Bankruptcies
We purchaseThe Company purchases and sellsells electricity from and to numerous companies operating in the steel, automotive, energy, retail and other industries. Certain of ourthe Company’s customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. WeThe Company regularly reviewreviews contingent matters relating to these customers and ourits purchase and sale contracts, and we recordrecords provisions for amounts that we can estimate and are considered at risk of probable loss. We believe ourManagement believes the Company’s previously accrued amounts are adequate for probable losses. The final resolution of these matters is not expected to have a material effect on ourthe Company’s consolidated financial statements.
Other Contingencies
Detroit EdisonThe Company is involved in a contract dispute with BNSF Railway Company that was referred to arbitration. Under this contract, BNSF transports western coals east for Detroit Edison. We filed a breach of contract claim against BNSF for the failure to provide certain services that we believe are required by the contract. We received an award from the arbitration panel in September 2007 which held that BNSF is required to provide such services under the contract and awarded damages to us. The award is subject to appeal. While we believe that the arbitration panel’s award will be upheld if it is appealed, a negative decision on appeal could have an adverse effect on our business.
We are involved in certain 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 it can estimate and which 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 5 for a discussion of contingencies related to regulatory matters.

2322

Part II
Item 1. – 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 we can estimate andthat are considered probable of loss. The resolution of these pending proceedings is not expected to have a material effect on our operations or financial statements in the periodsperiod they are resolved.
See Note 4We are aware of attempts by an environmental organization known as the Waterkeeper Alliance to initiate a criminal action in Canada against the Company for a discussionalleged violations of contingencies relatedthe Canadian Fisheries Act. Fines under the relevant Canadian statute could be significant. To date, the Company has not been served process in this matter and is not able to regulatory matters.

24

Other Informationpredict or assess the outcome of this action at this time.
Item 1A. – Risk Factors
In addition to the risk factors discussed below and other information set forth in this report, the risk factors discussed in Part 1, Item 1A. Company Risk Factors in The Detroit Edisonthe Company’s 20062007 Form 10-K, which could materially affect the Company’s businesses, financial condition, future operating results and/or cash flows should be carefully considered. Additional risks and uncertainties not currently known to the Company, or that are currently deemed to be immaterial, also may materially adversely affect the Company’s business, financial condition, and/or future operating results.
A work interruption may adversely affect us.Item 5. – Other InformationUnions represent a majority
On May 8, 2008, Detroit Edison amended its (i) Amended and Restated Trade Receivables Purchase and Sale Agreement among Detroit Edison, CAFCO, LLC (as successor to Corporate Asset Funding Company, Inc.) (“CAFCO”), Citibank, N.A. (“Citibank”) and Citicorp North America, Inc. (“Citicorp”), individually and as Agent (the “CAFCO Trade Receivables Agreement”), dated as of our employees. A union choosingMarch 9, 2001, as amended, and (ii) its Amended and Restated Trade Receivables Purchase and Sale Agreement among Detroit Edison, Citibank and Citicorp, as Agent (the “Citibank Trade Receivables Agreement”), dated as of October 1, 1991, as amended (collectively the “Agreements”), to strike as a negotiating tactic would have an impact on our business. There are several bargaining units for our represented employees. A July 2007 tentative agreement was not ratified by approximately 3,100 of our represented employees. In October 2007, a new tentative agreement was reached, subjectincrease the Assignee Rate from 1.25% to ratification by such bargaining unit members. We can provide no assurance that2.25%, amend the new tentative agreement will be ratified. The contracts of the remaining represented employees expire at various dates in 2008. We are unable to predict the effects a work stoppage would have on our costs of operation and financial performance.
Failure to successfully implement new processes and information systems could interrupt our operations.Our businesses depend on numerous information systems for operations and financial information and billings. We are“increased costs” provision in the midst of a multi-year Company-wide initiativeagreements to improve existing processesprovide for an Accounting Based Consolidation Event, increase the Administration Fee rate from “20/100” to “25/100”, and implement new core information systems. We launchedincrease the first phase of our Enterprise Business Systems project in 2005. The second phase of implementation began in April 2007 and continues throughout 2007. FailureProgram Fee rate from “17.5/100” to successfully implement new processes and new core information systems could interrupt our operations.“50/100”.
Item 6. — Exhibits
   
Exhibit  
Number Description
Filed:
  
31-35Exhibits filed herewith:
4-251Supplemental Indenture, dated as of April 1, 2008 to Mortgage and Deed of Trust dated as of October 1, 1924 between the Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee, providing for General and Refunding Mortgage Bonds, 2008 Series DT.
4-252Twenty-Third Supplemental Indenture, dated as of April 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee, providing for 2008 Series DT Variable Rate Senior Notes due 2036.
10-43Amendment No. 8 dated as of May 8, 2008 to the Amended and Restated Trade Receivables Purchase and Sale Agreement among Detroit Edison, CAFCO, Citibank and Citicorp, individually and as Agent dated March 9, 2001, as amended.
12-29Computation of Ratio of Earnings to Fixed Charges
31-39 Chief Executive Officer Section 302 Form 10-Q Certification
31-36
31-40 Chief Financial Officer Section 302 Form 10-Q Certification
   
Furnished:
Exhibits furnished herewith:
  
32-3532-39 Chief Executive Officer Section 906 Form 10-Q Certification
32-36
32-40 Chief Financial Officer Section 906 Form 10-Q Certification

2523

SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
     
 THE DETROIT EDISON COMPANY
(Registrant)
  
Date: November 9, 2007May 12, 2008 /s/ PETER B. OLEKSIAK
Peter B. Oleksiak		  
 Peter B. Oleksiak 
 Vice President, Controller and
Chief Accounting Officer		  
 Chief Accounting Officer

2624