DTE Electric 10-K 2007 FY Annual report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

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

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

For the fiscal year ended December 31, 2007

Commission file number 1-2198

The Detroit Edison Company, a Michigan corporation, meets the conditions set forth in General Instruction I (1) (a) and (b) of Form 10-K and is, therefore, filing this form with the reduced disclosure format.

THE DETROIT EDISON COMPANY

(Exact name of registrant as specified in its charter)

Michigan	38-0478650
(State or other jurisdiction of incorporation or	(I.R.S. Employer
organization)	Identification No.)
2000 2nd Avenue, Detroit, Michigan	48226-1279
(Address of principal executive offices)	(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:
None

Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.Yeso Noþ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.Yeso Noþ

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

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

      Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filero	Accelerated filero	Non-accelerated filerþ	Smaller reporting companyo
	(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yeso Noþ

All of the registrant’s 138,632,324 outstanding shares of common stock, par value $10 per share, are owned by DTE Energy Company.

DOCUMENTS INCORPORATED BY REFERENCE
None

The Detroit Edison Company
Annual Report on Form 10-K
Year Ended December 31, 2007
Table of Contents

		Page
Definitions			1
Forward-Looking Statements			2
Part I
Items 1., 1A., 1B. &2.	Business, Risk Factors, Unresolved Staff Comments and Properties		4
Item 3.	Legal Proceedings		10
Item 4.	Submission of Matters to a Vote of Security Holders		11
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		11
Item 6.	Selected Financial Data		11
Item 7.	Management’s Narrative Analysis of Results of Operations		12
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		15
Item 8.	Financial Statements and Supplementary Data		17
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		61
Item 9A.	Controls and Procedures		61
Item 9B.	Other Information		61
Part III
Item 10.	Directors, Executive Officers and Corporate Governance		61
Item 11.	Executive Compensation		61
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		61
Item 13.	Certain Relationships and Related Transactions, and Director Independence		61
Item 14.	Principal Accountant Fees and Services		61
Part IV
Item 15.	Exhibits and Financial Statement Schedules		62
Signatures			72
Computation of Ratio of Earnings to Fixed Charges
Consent of Deloitte & Touche LLP
Chief Executive Officer Section 302
Chief Financial Officer Section 302
Chief Executive Officer Section 906
Chief Financial Officer Section 906

Definitions

CTA	Costs to achieve, consisting of project management, consultant support and employee severance, related to the Performance Excellence Process
Customer Choice	Statewide initiatives giving customers in Michigan the option to choose alternative suppliers for electricity.
Detroit Edison	The Detroit Edison Company (a direct wholly owned subsidiary of DTE Energy Company) and subsidiary companies
DTE Energy	DTE Energy Company, the parent of Detroit Edison and directly or indirectly the parent company of numerous utility and non-utility subsidiaries
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
ITC	International 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, the Detroit Edison Securitization Funding LLC.
SFAS	Statement of Financial Accounting Standards
Stranded Costs	Costs incurred by utilities in order to serve customers in a regulated environment that absent special regulatory approval would not otherwise be recoverable if customers switch to alternative energy suppliers.
Units of Measurement
kWh	Kilowatthour of electricity
MW	Megawatt of electricity
MWh	Megawatthour of electricity

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Forward-Looking Statements

Certain information presented herein includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve certain risks and uncertainties that may cause actual future results to differ materially from those presently contemplated, projected, estimated or budgeted. Many factors may impact forward-looking statements including, but not limited to, the following:

• the 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 impact of collective bargaining agreements;

• unplanned outages;

• access to capital markets and capital market conditions and the results of other financing efforts which can be affected by credit agency ratings;

• the timing and extent of changes in interest rates;

• the level of borrowings;

• changes in the cost and availability of coal and other raw materials, 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;

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• 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

New factors emerge from time to time. We cannot predict what factors may arise or how such factors may cause our results to differ materially from those contained in any forward-looking statement. Any forward-looking statements refer only as of the date on which such statements are made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.

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Part I

Items 1., 1A. & 2. Business, Company Risk Factors and Properties

General

Detroit Edison is a Michigan corporation organized in 1903 and is a wholly owned subsidiary of DTE Energy. Detroit Edison is a public utility subject to regulation by the MPSC and FERC. Detroit Edison is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.2 million customers in a 7,600 square mile area in southeastern Michigan.

References in this report to “we,” “us,” “our” or “Company” are to Detroit Edison.

Our generating plants are regulated by numerous federal and state governmental agencies, including, but not limited to, the MPSC, the FERC, the NRC, the EPA and the MDEQ. Electricity is generated from our several fossil plants, a hydroelectric pumped storage plant and a nuclear plant, and is purchased from electricity generators, suppliers and wholesalers.

The electricity we produce and purchase is sold to four major classes of customers: residential, commercial, industrial, and wholesale, principally throughout Michigan.

Revenue by Service
(in Millions)	2007		2006		2005
Residential	$	1,739	$	1,671	$	1,517
Commercial		1,723		1,603		1,331
Industrial		854		835		697
Wholesale		125		109		73
Other		259		350		464
Subtotal		4,700		4,568		4,082
Interconnection sales (1)		200		169		380
Total Revenue	$	4,900	$	4,737	$	4,462

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

Weather, economic factors, competition and electricity prices affect sales levels to customers. Our peak load and highest total system sales generally occur during the third quarter of the year, driven by air conditioning and other cooling-related demands.

We occasionally experience various types of storms that damage our electric distribution infrastructure resulting in power outages. Restoration and other costs associated with storm-related power outages can negatively impact earnings.

Our operations are not dependent upon a limited number of customers, and the loss of any one or a few customers would not have a material adverse effect on Detroit Edison.

Fuel Supply and Purchased Power

Our power is generated from a variety of fuels and is supplemented with purchased power. We expect to have an adequate supply of fuel and purchased power to meet our obligation to serve customers. Our generating capability is heavily dependent upon the availability of coal. Coal is purchased from various sources in

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different geographic areas under agreements that vary in both pricing and terms. We expect to obtain the majority of our coal requirements through long-term contracts, with the balance to be obtained through short-term agreements and spot purchases. We have four long-term and eight short-term contracts for a total purchase of approximately 25.7 million tons of low-sulfur western coal to be delivered from 2008 through 2010. We also have 12 contracts for the purchase of approximately 10.3 million tons of Appalachian coal to be delivered from 2008 through 2010. All of these contracts have fixed prices. We have approximately 90% of our 2008 expected coal requirements under contract. Given the geographic diversity of supply, we believe we can meet our expected generation requirements. We lease a fleet of rail cars and have long-term transportation contracts with companies to provide rail and vessel services for delivery of purchased coal to our generating facilities.

Detroit Edison participates in the energy market through MISO. We offer our generation in the market on a day-ahead and real-time basis and bid for power in the market to serve our load. We are a net purchaser of power that supplements our generation capability to meet customer demand during peak cycles.

Properties

Detroit Edison owns generating plants and facilities that are located in the State of Michigan. Substantially all of our property is subject to the lien of a mortgage.

Generating plants owned and in service as of December 31, 2007 are as follows:

	Location by	Summer Net
	Michigan	Rated Capability (1) (2)
Plant Name	County	(MW)		(%)		Year in Service
Fossil-fueled Steam-Electric
Belle River (3)	St. Clair		1,026		9.3	1984 and 1985
Conners Creek	Wayne		230		2.1	1951
Greenwood	St. Clair		785		7.1	1979
Harbor Beach	Huron		103		0.9	1968
Monroe (4)	Monroe		3,115		28.3	1971, 1973 and 1974
River Rouge	Wayne		523		4.8	1957 and 1958
St. Clair	St. Clair		1,368		12.4	1953, 1954, 1959, 1961 and 1969
Trenton Channel	Wayne		730		6.6	1949 and 1968
			7,880		71.5
Oil or Gas-fueled Peaking Units	Various		1,101		10.0	1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric Fermi 2 (5)	Monroe		1,122		10.2	1988
Hydroelectric Pumped Storage Ludington (6)	Mason		917		8.3	1973
			11,020		100.0

(1)	Summer net rated capabilities of generating plants in service are based on periodic load tests and are changed depending on operating experience, the physical condition of units, environmental control limitations and customer requirements for steam, which otherwise would be used for electric generation.
(2)	Excludes one oil-fueled unit, St. Clair Unit No. 5 (250 MW), and one coal-fired unit, Marysville (84 MW), in cold standby status.
(3)	The Belle River capability represents Detroit Edison’s entitlement to 81.39% of the capacity and energy of the plant. See Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
(4)	The Monroe Power Plant provided 39% of Detroit Edison’s total 2007 power plant generation.
(5)	Fermi 2 has a design electrical rating (net) of 1,150 MW.
(6)	Represents Detroit Edison’s 49% interest in Ludington with a total capability of 1,872 MW. See Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.

Detroit Edison owns and operates 678 distribution substations with a capacity of approximately 33,376,000 kilovolt-amperes (kVA) and approximately 427,100 line transformers with a capacity of approximately 26,280,000 kVA.

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Circuit miles of distribution lines owned and in service as of December 31, 2007 are as follows:

Electric Distribution	Circuit Miles
Operating Voltage-Kilovolts (kV)	Overhead		Underground
4.8 kV to 13.2 kV		28,202		13,985
24 kV		99		690
40 kV		2,324		335
120 kV		72		13
		30,697		15,023

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

Regulation

Detroit Edison’s business is subject to the regulatory jurisdiction of various agencies, including, but not limited to, the MPSC, the FERC and the NRC. The MPSC issues orders pertaining to rates, recovery of certain costs, including the costs of generating facilities and regulatory assets, conditions of service, accounting and operating-related matters. Detroit Edison’s MPSC-approved rates charged to customers have historically been designed to allow for the recovery of costs, plus an authorized rate of return on our investments. The FERC regulates Detroit Edison with respect to financing authorization and wholesale electric activities. The NRC has regulatory jurisdiction over all phases of the operation, construction, licensing and decommissioning of Detroit Edison’s nuclear plant operations. We are subject to the requirements of other regulatory agencies with respect to safety, the environment and health.

See Note 4 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Energy Assistance Programs

Energy assistance programs, funded by the federal government and the State of Michigan, remain critical to Detroit Edison’s ability to control its uncollectible accounts receivable and collections expenses. Detroit Edison’s uncollectible accounts receivable expense is directly affected by the level of government funded assistance its qualifying customers receive. We work continuously with the State of Michigan and others to determine whether the share of funding allocated to our customers is representative of the number of low-income individuals in our service territory.

Strategy and Competition

We strive to be the preferred supplier of electrical generation in southeast Michigan. We can accomplish this goal by working with our customers, communities and regulatory agencies to be a reliable, low-cost supplier of electricity. To ensure generation reliability, we continue to invest in our generating plants, which will improve both plant availability and operating efficiencies. We also are making capital investments in areas that have a positive impact on reliability and environmental compliance with the goal of high customer satisfaction.

Our distribution operations focus on improving reliability, restoration time and the quality of customer service. We seek to lower our operating costs by improving operating efficiencies. Revenues from year to year will vary due to weather conditions, economic factors, regulatory events and other risk factors as discussed in the “Risk Factors” in Item 1A of this Report.

The electric Customer Choice program in Michigan allows all of our electric customers to purchase their electricity from alternative electric suppliers of generation services. Customers choosing to purchase power from

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alternative electric suppliers represented approximately 4% of retail sales in 2007, 6% in 2006 and 12% of such sales in 2005. Customers participating in the electric Customer Choice program consist primarily of industrial and commercial customers whose MPSC-authorized full service rates exceed their cost of service. Customers who elect to purchase their electricity from alternative electric suppliers by participating in the electric Customer Choice program have an unfavorable effect on our financial performance. When market conditions are favorable, we sell power into the wholesale market, in order to lower costs to full-service customers.

Competition in the regulated electric distribution business is primarily from the on-site generation of industrial customers and from distributed generation applications by industrial and commercial customers. We do not expect significant competition for distribution to any group of customers in the near term.

ENVIRONMENTAL MATTERS

We are subject to extensive environmental regulation. Additional costs may result as the effects of various substances on the environment are studied and governmental regulations are developed and implemented. We expect to continue recovering environmental costs through rates charged to our customers. The following table summarizes our estimated significant future environmental expenditures based upon current regulations:

(in Millions)
Air	$	2,441
Water		55
Other clean up sites		11
MGP sites		4
Estimated total future expenditures through 2018	$	2,511
Estimated 2008 expenditures	$	288

Air- Detroit Edison is subject to the EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. In March 2005, EPA issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. The cost to address environmental air issues is estimated through 2018.

Water- In response to an EPA regulation, Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of studies to be conducted over the next several years, Detroit Edison may be required to perform some mitigation activities, including the possible installation of additional control technologies to reduce the environmental impact of the intake structures. However, a recent court decision remanded back to the EPA several provisions of the federal regulation, resulting in a delay in complying with the regulation.

Manufactured Gas Plant (MGP) Sites- Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. The facilities, which produced gas for heating and other uses, have been designated as MGP sites. Detroit Edison conducted remedial investigations at contaminated sites, including three MGP sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is expected to be incurred over the next several years. In addition, Detroit Edison will be making capital improvements to the ash landfill in 2008.

Global Climate Change —Proposals for voluntary initiatives and mandatory controls are being discussed in the United States to reduce greenhouse gases such as carbon dioxide, a by-product of burning fossil fuels. There may be legislative action to address the issue of changes in climate that may result from the build up of greenhouse gases, including carbon dioxide, in the atmosphere. We cannot predict the impact any legislative or regulatory action may have on our operations and financial position.

Greater details on environmental issues are provided in Notes 4 and 13 of the Notes to Consolidated Financial Statements in Item 8 of this Report:

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EMPLOYEES

We had 4,674 employees as of December 31, 2007, of which 2,847 were represented by unions. In December 2007, a new three-year agreement was ratified by our represented employees.

Item 1A. Company Risk Factors

There are various risks associated with the operations of Detroit Edison. To provide a framework to understand our operating environment, we are providing a brief explanation of the more significant risks associated with our business. Although we have tried to identify and discuss key risk factors, others could emerge in the future. Each of the following risks could affect our performance.

We are subject to rate regulation. Electric and gas rates for our utilities are set by the MPSC and the FERC and cannot be increased without regulatory authorization. We may be negatively impacted by new regulations or interpretations by the MPSC, the FERC or other regulatory bodies. Our ability to recover costs may be impacted by the time lag between the incurrence of costs and the recovery of the costs in customers’ rates. New legislation, regulations or interpretations could change how our business operates, impact our ability to recover costs through rate increases or require us to incur additional expenses.

Michigan’s electric Customer Choice program could negatively impact our financial performance. The electric Customer Choice program, as originally contemplated in Michigan, anticipated an eventual transition to a totally deregulated and competitive environment where customers would be charged market-based rates for their electricity. The State of Michigan currently experiences a hybrid market, where the MPSC continues to regulate electric rates for our customers, while alternative electric suppliers charge market-based rates. In addition, such regulated electric rates for certain groups of our customers exceed the cost of service to those customers. Due to distorted pricing mechanisms during the initial implementation period of electric Customer Choice, many commercial customers chose alternative electric suppliers. Recent MPSC rate orders have removed some of the pricing disparity. Recent higher wholesale electric prices have also resulted in some former electric Customer Choice customers migrating back to Detroit Edison for electric generation service. Even with the electric Customer Choice-related rate relief received in Detroit Edison’s 2004 and 2005 orders, there continues to be considerable financial risk associated with the electric Customer Choice program. Electric Customer Choice migration is sensitive to market price and bundled electric service price increases. The hybrid market in Michigan also causes uncertainty as it relates to investment in new generating capacity.

Weather significantly affects operations.Deviations from normal hot and cold weather conditions affect our earnings and cash flow. Mild temperatures can result in decreased utilization of our assets, lowering income and cash flow. Ice storms, tornadoes, or high winds can damage the distribution system infrastructure and require us to perform emergency repairs and incur material unplanned expenses. The expenses of storm restoration efforts may not be recoverable through the regulatory process.

Operation of a nuclear facility subjects us to risk.Ownership of an operating nuclear generating plant subjects us to significant additional risks. These risks include, among others, plant security, environmental regulation and remediation, and operational factors that can significantly impact the performance and cost of operating a nuclear facility. While we maintain insurance for various nuclear-related risks, there can be no assurances that such insurance will be sufficient to cover our costs in the event of an accident or business interruption at our nuclear generating plant, which may affect our financial performance.

The supply and price of fuel and other commodities may impact our financial results.We are dependent on coal for much of our electrical generating capacity. Price fluctuations and fuel supply disruptions could have a negative impact on our ability to profitably generate electricity. We have hedging strategies in place to mitigate negative fluctuations in commodity supply prices, but there can be no assurances that our financial performance will not be negatively impacted by price fluctuations.

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Unplanned power plant outages may be costly.Unforeseen maintenance may be required to safely produce electricity or comply with environmental regulations. As a result of unforeseen maintenance, we may be required to make spot market purchases of electricity that exceed our costs of generation. Our financial performance may be negatively affected if we are unable to recover such increased costs.

Regional and national economic conditions can have an unfavorable impact on us.Our businesses follow the economic cycles of the customers we serve. Should national or regional economic conditions decline, reduced volumes of electricity and gas we supply will result in decreased earnings and cash flow. Economic conditions in our service territory also impact our collections of accounts receivable and financial results.

Adverse changes in our credit ratings may negatively affect us.Increased scrutiny of the energy industry and regulatory changes, as well as changes in our economic performance, could result in credit agencies reexamining our credit rating. While credit ratings reflect the opinions of the credit agencies issuing such ratings and may not necessarily reflect actual performance, a downgrade in our credit rating could restrict or discontinue our ability to access capital markets and could increase our borrowing costs. In addition, a reduction in credit rating may require us to post collateral related to various trading contracts, which would impact our liquidity.

Our ability to access capital markets at attractive interest rates is important.Our ability to access capital markets is important to operate our businesses. Heightened concerns about the energy industry, the level of borrowing by other energy companies and the market as a whole could limit our access to capital markets. Changes in interest rates could increase our borrowing costs and negatively impact our financial performance.

Poor investment performance of pension plan holdings and other factors impacting pension plan costs could unfavorably impact our liquidity and results of operations.Our costs of providing non-contributory defined benefit pension plans are dependent upon a number of factors, such as the rates of return on plan assets, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation, and our required or voluntary contributions made to the plans. The performance of the capital markets affects the value of assets that are held in trust to satisfy future obligations under our pension plans. If conditions within the overall credit market continue to deteriorate, the fair value of these plans’ assets may be negatively affected. Additionally, while we complied with the minimum funding requirements as of December 31, 2007, we have certain qualified pension plans with obligations that exceeded the value of plan assets. Without sustained growth in the pension investments over time to increase the value of our plan assets, we could be required to fund our plans with significant amounts of cash. Such cash funding obligations could have a material impact on our cash flows, financial position, or results of operations.

We are exposed to credit risk of counterparties with whom we do business.Adverse economic conditions affecting, or financial difficulties of, counterparties with whom we do business could impair the ability of these counterparties to pay for our services or fulfill their contractual obligations, or cause them to delay such payments or obligations. We depend on these counterparties to remit payments on a timely basis. Any delay or default in payment could adversely affect our cash flows, financial position, or results of operations.

Environmental laws and liability may be costly.We are subject to numerous environmental regulations. These regulations govern air emissions, water quality, wastewater discharge, and disposal of solid and hazardous waste. Compliance with these regulations can significantly increase capital spending, operating expenses and plant down times. These laws and regulations require us to seek a variety of environmental licenses, permits, inspections and other regulatory approvals. Additionally, we may become a responsible party for environmental clean up at sites identified by a regulatory body. We cannot predict with certainty the amount and timing of future expenditures related to environmental matters because of the difficulty of estimating clean up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on potentially responsible parties.

We may also incur liabilities as a result of potential future requirements to address climate change issues. Proposals for voluntary initiatives and mandatory controls are being discussed both in the United States and worldwide to reduce greenhouse gases such as carbon dioxide, a by-product of burning fossil fuels. If

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increased regulation of greenhouse gas emissions are implemented, the operations of our fossil-fuel generation assets may be significantly impacted.

Since there can be no assurances that environmental costs may be recovered through the regulatory process, our financial performance may be negatively impacted as a result of environmental matters.

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

Terrorism could affect our business. Damage to downstream infrastructure or our own assets by terrorism would impact our operations. We have increased security as a result of past events and further security increases are possible.

Benefits of the Performance Excellence Process to us could be less than we have projected.In 2005, we initiated a company-wide review of our operations called the Performance Excellence Process, with the overarching goal to become more competitive by reducing costs, eliminating waste and optimizing business processes while improving customer service. Actual results achieved through this process could be less than our expectations.

A work interruption may adversely affect us.Unions represent a majority of our employees. A union choosing to strike would have an impact on our business. We are unable to predict the effect a work stoppage would have on our costs of operation and financial performance.

Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse effect on our operations.Our business is dependent on our ability to recruit, retain, and motivate employees. Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect our business and future operating results.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

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

We are aware of attempts by an environmental organization known as the Waterkeeper Alliance to initiate a criminal action in Canada against the Company for alleged violations of the Canadian Fisheries Act. Fines under the relevant Canadian statute could be significant. To date, the Company has not been served process in this matter and is not able to predict or assess the outcome of this action at this time.

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

Note		Title
	4	Regulatory Matters
	5	Nuclear Operations
	13	Commitments and Contingencies

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

Omitted per General Instruction I (2) (c) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

All of the 138,632,324 issued and outstanding shares of common stock of Detroit Edison, par value $10 per share, are owned by DTE Energy, and constitute 100% of the voting securities of Detroit Edison. Therefore, no market exists for our common stock.

We paid cash dividends on our common stock of $305 million in 2007, 2006, and 2005.

Item 6. Selected Financial Data

Omitted per General Instruction I (2) (a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

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Item 7. Management’s Narrative Analysis of Results of Operations

The Management’s Narrative Analysis of Results of Operations discussion for Detroit Edison is presented in accordance with General Instruction I (2) (a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Factors impacting income:Our net income decreased $4 million to $317 million in 2007 from $321 million in 2006. The 2007 decrease reflects higher operation and maintenance expenses, partially offset by higher gross margins and lower depreciation and amortization expenses. The 2006 increase primarily reflects higher gross margins, partially offset by increased depreciation and amortization expenses.

Increase (Decrease) in Income Statement Components Compared to Prior Year	2007			2006
(in Millions)
Operating revenues	$	163		$	275
Fuel and purchased power		120			(24	)
Gross margin		43			299
Operation and maintenance		85			29
Depreciation and amortization		(48	)		172
Taxes other than income		25			11
Gains on sales of assets		14			20
Operating income		(33	)		67
Other (income) and deductions		(17	)		11
Income tax provision		(13	)		13
Net income before accounting change		(3	)		43
Cumulative effect of accounting change		(1	)		4
Net Income	$	(4	)	$	47

Gross marginincreased $43 million during 2007 and $299 million in 2006. The increase in 2007 was attributed to higher margins due to returning sales from electric Customer Choice, the favorable impact of a May 2007 MPSC order related to the 2005 PSCR reconciliation, and weather related impacts, partially offset by lower rates resulting primarily from the August 2006 settlement in the MPSC show cause proceeding and the unfavorable impact of a September 2006 MPSC order related to the 2004 PSCR reconciliation. The 2006 improvement was primarily due to increased rates due to the expiration of the residential rate cap on January 1, 2006 and returning sales from electric Customer Choice, partially offset by milder weather. Revenues include a component for the cost of power sold that is recoverable through the PSCR mechanism.

The following table displays changes in various gross margin components relative to the comparable prior period:

Increase (Decrease) in Gross Margin Components Compared to Prior Year	2007			2006
(in Millions)
Weather-related margin impacts	$	31		$	(81	)
Removal of residential rate caps effective January 1, 2006		—			186
Return of customers from electric Customer Choice		43			156
Service territory economic performance		28			(16	)
Impact of 2006 MPSC show cause order		(64	)		—
Impact of 2005 MPSC PSCR reconciliation order		38			—
Impact of 2004 MPSC PSCR reconciliation order		(39	)		26
Other, net		6			28
Increase in gross margin	$	43		$	299

12

Power Generated and Purchased
(in Thousands of MWh)	2007					2006					2005
Power Plant Generation
Fossil		42,359		72	%		39,686		70	%		40,756		73	%
Nuclear		8,314		14			7,477		13			8,754		16
		50,673		86			47,163		83			49,510		89
Purchased Power		8,422		14			9,861		17			6,378		11
System Output		59,095		100	%		57,024		100	%		55,888		100	%
Less Line Loss and Internal Use		(3,391	)				(3,603	)				(3,205	)
Net System Output		55,704					53,421					52,683
Average Unit Cost ($/MWh)
Generation (1)	$	15.83				$	15.61				$	15.47
Purchased Power (2)	$	62.40				$	53.71				$	89.37
Overall Average Unit Cost	$	22.47				$	22.20				$	23.90

(1)	Represents fuel costs associated with power plants.
(2)	The change in purchased power costs were driven primarily by seasonal demand and coal and gas prices.

(in Thousands of MWh)	2007		2006		2005
Electric Sales
Residential		16,147		15,769		16,812
Commercial		19,332		17,948		15,618
Industrial		13,338		13,235		12,317
Wholesale		2,902		2,826		2,329
Other		398		402		390
		52,117		50,180		47,466
Interconnection sales (1)		3,587		3,241		5,217
Total Electric Sales		55,704		53,421		52,683
Electric Deliveries
Retail and Wholesale		52,117		50,180		47,466
Electric Customer Choice		1,690		2,694		6,760
Electric Customer Choice-Self Generators (2)		549		909		518
Total Electric Sales and Deliveries		54,356		53,783		54,744

(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 $85 million in 2007 and $29 million in 2006. The increase in 2007 is primarily due to EBS implementation costs of $30 million, higher storm expenses of $22 million, increased uncollectible expense of $22 million and higher corporate support expenses of $20 million. The 2006 increase was primarily due to increased distribution system maintenance of $35 million and increased plant outages of $33 million that was partially offset by $36 million of lower storm expenses.

Depreciation and amortizationexpense decreased $48 million in 2007 and increased $172 million in 2006. The 2007 decrease was due primarily to a 2006 net stranded cost write-off of $112 million related to the September 2006 MPSC order regarding stranded costs and a $13 million decrease in our asset retirement obligation at our Fermi 1 nuclear facility, partially offset by $58 million of increased amortization of regulatory assets and $13 million of higher depreciation expense due to increased levels of depreciable plant assets. Amortization of prior year deferred CTA costs amounted to $10 million in 2007. The 2006 increase was due to a $112 million net stranded cost write-off related to the September 2006 MPSC order regarding stranded costs and a $19 million increase in our asset retirement obligation at our Fermi 1 nuclear facility. In 2006, we also had increased amortization of regulatory assets of $19 million related to electric Customer Choice and $8 million related to our securitized assets.

13

Asset (gains) and losses, netgain decreased $14 million in 2007 due to a $13 million reserve for a loan guaranty related to Detroit Edison’s former ownership of a steam heating business now owned by Thermal Ventures II, LP (Thermal). The 2006 decrease resulted primarily from our 2005 sale of land near our headquarters in Detroit, Michigan.

Other (income) and deductionsexpense decreased $17 million in 2007 and increased $11 million in 2006. The 2007 decrease is attributable to a $10 million contribution to the DTE Energy Foundation in 2006 that did not re-occur in 2007, $3 million of higher interest income and $17 million of increased miscellaneous utility related services, partially offset by $16 million of higher interest expense. The 2006 increase is primarily attributable to higher interest expense due to increased long-term debt.

Outlook- We will move forward in our efforts to continue to improve operating performance. 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 are also seeking regulatory reform to insure more timely cost recovery and resolution of rate cases. Looking forward, additional issues, such as rising prices for coal, health care and higher levels of capital spending, will result in us taking meaningful action to address our costs while continuing to provide quality customer service. We will utilize the DTE Energy Operating System and the Performance Excellence Process to seek opportunities to improve productivity, remove waste and decrease our costs while improving customer satisfaction.

Long term, we will be required to invest an estimated $2.4 billion on emission controls through 2018. We intend to seek recovery of these investments in future rate cases.

Additionally, our service territory may require additional generation capacity. A new base-load generating plant has not been built within the State of Michigan in over 20 years. Should our regulatory environment be conducive to such a significant capital expenditure, we may build, upgrade or co-invest in a base-load coal facility or a new nuclear plant. While we have not decided on construction of a new base-load nuclear plant, in February 2007, we announced that we will prepare a license application for construction and operation of a new nuclear power plant on the site of Fermi 2. By completing the license application before the end of 2008, we may qualify for financial incentives under the Federal Energy Policy Act of 2005. We are also studying the possible transfer of a gas-fired peaking electric generating plant from our non-utility operations to our electric utility to support future power generation requirements.

The following variables, either in combination or acting alone, could impact our future results:

• amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals, or new legislation;

• our ability to reduce costs and maximize plant and distribution system performance;

• variations in market prices of power, coal and gas;

• economic conditions within the State of Michigan;

• weather, including the severity and frequency of storms;

• levels of customer participation in the electric Customer Choice program; and

• potential new federal and state environmental, renewable energy and energy efficiency requirements.

We expect cash flows and operating performance will continue to be at risk due to the electric Customer Choice program until the issues associated with this program are adequately addressed. We will accrue as regulatory assets any future unrecovered generation-related fixed costs (stranded costs) due to electric Customer Choice that we

14

believe are recoverable under Michigan legislation and MPSC orders. We cannot predict the outcome of these matters. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.

In January 2007, the MPSC submitted the State of Michigan’s 21st Century Energy Plan to the Governor of Michigan. The plan recommends that Michigan’s future energy needs be met through a combination of renewable resources and cleanest generating technology, with significant energy savings achieved by increased energy efficiency. The plan also recommends:

• a requirement that all retail electric suppliers obtain at least 10 percent of their energy supplies from renewable resources by 2015;

• an opportunity for utility-built generation, contingent upon the granting of a certificate of need and competitive bidding of engineering, procurement and construction services;

• investigating the cost of a requirement to bury certain power lines; and

• creation of a Michigan Energy Efficiency Program, administered by a third party under the direction of the MPSC with initial funding estimated at $68 million.

In December 2007, a package of bills to reform Michigan’s electric market was introduced in the Michigan legislature. Key elements of the package would modify Michigan’s electric Customer Choice program, begin the process of “de-skewing” regulated electric rates, provide for the creation of economic development rates, establish a process for authorizing the construction of new baseload power plants, provide for regulatory reform to insure more timely cost recovery and resolution of rate cases, establish renewable energy standards and create an energy efficiency program.

We continue to review the energy plan and monitor legislative action on some of its components. Without knowing how or if the plan will be fully implemented, we are unable to predict the impact on the Company of the implementation of the plan.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES

Effective January 1, 2007, we adopted FASB Interpretation No. (FIN 48),Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109. The cumulative effect of the adoption of FIN 48 represented a $0.7 million increase to the January 1, 2007 balance of retained earnings.

Effective January 1, 2006, we adopted SFAS No. 123(R),Share-Based Payment,using the modified prospective transition method. The cumulative effect of the adoption of SFAS 123(R) was an increase in net income of $1 million as a result of estimating forfeitures for previously granted stock awards and performance shares.

In the fourth quarter of 2005, we adopted FIN No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS No. 143that required additional new accounting rules for asset retirement obligations. The cumulative effect of adopting these new accounting rules reduced 2005 earnings by $3 million.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

We have commodity price risk arising from market price fluctuations. We have risks in conjunction with the anticipated purchases of coal, natural gas, uranium, and electricity to meet our service obligations. Further, changes in the price of electricity can impact the level of exposure of the electric Customer Choice program and uncollectible expenses.

To limit our exposure to commodity price fluctuations, we have applied various approaches including forward energy, capacity, storage and futures contracts, as well as regulatory rate-recovery mechanisms. Regulatory rate-

15

recovery occurs in the form of the PSCR mechanism (see Note 1 of the Notes to Consolidated Financial Statements) and a tracking mechanism to mitigate some losses from customer migration due to electric Customer Choice programs.

Credit Risk

Bankruptcies

We purchase and sell electricity from and to numerous companies operating in the steel, automotive, energy, retail and other industries. Certain of our customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We regularly review contingent matters relating to these customers and our purchase and sale contracts and we record provisions for amounts considered at risk of probable loss. We believe our previously accrued amounts are adequate for probable loss. The final resolution of these matters is not expected to have a material effect on our financial statements.

Other

We engage in business with customers that are non-investment grade. We closely monitor the credit ratings of these customers and, when deemed necessary, we request collateral or guarantees from such customers to secure their obligations.

Interest Rate Risk

Detroit Edison is subject to interest rate risk in connection with the issuance of debt securities. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). We estimate that if interest rates were 10% higher or lower, the fair value of long-term debt at December 31, 2007 would decrease $178 million and increase $194 million, respectively.

16

Item 8. Financial Statements and Supplementary Data

	Page
Controls and Procedures		18
Report of Independent Registered Public Accounting Firm		20
Consolidated Statements of Operations		21
Consolidated Statements of Financial Position		22
Consolidated Statements of Cash Flows		24
Consolidated Statements of Changes in Shareholder’s Equity and Comprehensive Income		25
Notes to Consolidated Financial Statements		26
Schedule II — Valuation and Qualifying Accounts		71

17

Controls and Procedures

(a) Evaluation of disclosure controls and procedures

Management of the Company carried out an evaluation, under the supervision and with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2007, which is the end of the period covered by this report. Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that such controls and procedures are effective in ensuring that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.

(b) Management’s report on internal control over financial reporting

The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control system was designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of the effectiveness to future periods are subject to the risks that control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control—Integrated Framework.Based on our assessment, management believes that, as of December 31, 2007, the Company’s internal control over financial reporting was effective based on those criteria.

This annual report does not include an audit report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to audit by the Company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

(c) Changes in internal control over financial reporting

The Company has established a formal assessment process and related procedures to evaluate the effectiveness of internal control over financial reporting using criteria specified by COSO. The assessment process is comprehensive in scope, utilizes internal and external resources and involves many individuals at various levels of the Company in the design, testing and evaluation of internal control.

As part of the evaluation and assessment process, the Company has been improving the design and operating effectiveness of many entity-level and process-level controls. Control testing and remediation activities provide reasonable, but not absolute, assurance that a material weakness in internal control over financial reporting will be avoided. The inherent limitations of our current internal controls, a portion of which are manual by their nature, contribute to the potential for control deficiencies. Management does not believe any areas requiring further improvement constitute a material weakness in internal control over financial reporting as of December 31, 2007.

In April 2007, we began implementing the second phase of our Enterprise Business Systems (EBS) project. EBS is an enterprise resource planning system initiative to improve existing processes and to implement new core information systems, relating to finance, human resources, supply chain and work management. Changes have been made to many aspects of our internal control over financial reporting to adapt to EBS. Management continues to support, sustain and monitor our ongoing continuous improvement efforts in connection with the transition to EBS to ensure that the transition to EBS does not have a material negative impact on our internal control over financial reporting.

18

There have been no other changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2007 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

19

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
The Detroit Edison Company

We have audited the consolidated statement of financial position of The Detroit Edison Company
and subsidiaries (the “Company”) as of December 31, 2007 and 2006 and the related consolidated statements of operations, cash flows, and changes in shareholder’s equity and comprehensive income for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of The Detroit Edison Company and subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements of the Company taken as a whole, present fairly, in all material respects, the information set forth therein.

As discussed in Note 7 to the consolidated financial statements, in connection with the required adoption of a new accounting standard, the Company changed its method of accounting for uncertainty in income taxes on January 1, 2007. As discussed in Notes 2 and 14 to the consolidated financial statements, in connection with the required adoption of new accounting standards, in 2006 the Company changed its method of accounting for share based payments and defined benefit pension and other postretirement plans, respectively. As discussed in Note 1 to the consolidated financial statements, in connection with the required adoption of new accounting standards, in 2005 the Company changed its method of accounting for asset retirement obligations.

/S/ DELOITTE & TOUCHE LLP

Detroit, Michigan
March 7, 2008

20

The Detroit Edison Company

Consolidated Statements of Operations

	Year Ended December 31
(in Millions)	2007			2006			2005
Operating Revenues	$	4,900		$	4,737		$	4,462
Operating Expenses
Fuel and purchased power		1,686			1,566			1,590
Operation and maintenance		1,422			1,337			1,308
Depreciation and amortization		764			812			640
Taxes other than income		277			252			241
Asset (gains) and reserves, net		8			(6	)		(26	)
		4,157			3,961			3,753
Operating Income		743			776			709
Other (Income) and Deductions
Interest expense		294			278			267
Interest income		(7	)		(4	)		(3	)
Other income		(40	)		(35	)		(27	)
Other expenses		30			55			46
		277			294			283
Income Before Income Taxes		466			482			426
Income Tax Provision		149			162			149
Income Before Accounting Change		317			320			277
Cumulative Effect of Accounting Change, net of tax		—			1			(3	)
Net Income	$	317		$	321		$	274

See Notes to Consolidated Financial Statements

21

The Detroit Edison Company

Consolidated Statements of Financial Position

	December 31
(in Millions)	2007			2006
Assets
Current Assets
Cash and cash equivalents	$	47		$	27
Restricted cash		135			132
Accounts receivable (less allowance for doubtful accounts of $93 and $72, respectively)
Customer		727			601
Collateral held by others		32			—
Affiliates		3			19
Other		58			51
Accrued power supply cost recovery revenue		75			116
Inventories
Fuel		150			136
Materials and supplies		165			130
Other		60			54
		1,452			1,266
Investments
Nuclear decommissioning trust funds		824			740
Other		111			89
		935			829
Property
Property, plant and equipment		14,372			13,916
Less accumulated depreciation		(5,640	)		(5,580	)
		8,732			8,336
Other Assets
Regulatory assets		2,511			2,862
Securitized regulatory assets		1,124			1,235
Intangible assets		9			9
Other		122			74
		3,766			4,180
Total Assets	$	14,885		$	14,611

See Notes to Consolidated Financial Statements

22

The Detroit Edison Company
Consolidated Statements of Financial Position

	December 31
(in Millions, Except Shares)	2007		2006
Liabilities and Shareholder’s Equity
Current Liabilities
Accounts payable
Affiliates	$	138	$	84
Other		396		327
Accrued interest		77		79
Dividends payable		76		76
Accrued vacations		52		77
Short-term borrowings
Affiliates		277		—
Other		406		277
Current portion long-term debt, including capital leases		174		142
Other		243		288
		1,839		1,350
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other		3,473		3,515
Securitization bonds		1,065		1,184
Capital lease obligations		42		50
		4,580		4,749
Other Liabilities
Deferred income taxes		1,825		1,928
Regulatory liabilities		583		255
Asset retirement obligations		1,160		1,069
Unamortized investment tax credit		95		105
Nuclear decommissioning		134		119
Accrued pension liability		47		364
Accrued postretirement liability		816		1,055
Other		503		502
		5,163		5,397
Commitments and Contingencies (Notes 4, 5 and 13)
Shareholder’s Equity
Common stock, $10 par value, 400,000,000 shares authorized, and 138,632,324 shares issued and outstanding		2,771		2,596
Retained earnings		528		516
Accumulated other comprehensive income		4		3
		3,303		3,115
Total Liabilities and Shareholder’s Equity	$	14,885	$	14,611

See Notes to Consolidated Financial Statements

23

The Detroit Edison Company

Consolidated Statements of Cash Flows

	Year Ended December 31
(in Millions)	2007			2006			2005
Operating Activities
Net income	$	317		$	321		$	274
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		764			812			640
Deferred income taxes		(111	)		2			40
Asset (gains) and reserves, net		8			(6	)		(26	)
Cumulative effect of accounting change		—			(1	)		3
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		(213	)		(213	)		98
Net cash from operating activities		765			915			1,029
Investing Activities
Plant and equipment expenditures		(809	)		(972	)		(722	)
Proceeds from sale of assets, net		3			28			30
Restricted cash for debt redemptions		(3	)		(48	)		(9	)
Notes receivable from affiliate		—			—			85
Proceeds from sale of nuclear decommissioning trust fund assets		286			253			201
Investment in nuclear decommissioning trust funds		(323	)		(284	)		(235	)
Other investments		(33	)		(29	)		(71	)
Net cash used for investing activities		(879	)		(1,052	)		(721	)
Financing Activities
Issuance of long-term debt		50			314			857
Redemption of long-term debt		(185	)		(126	)		(997	)
Short-term borrowings, net		129			114			163
Short-term borrowings from affiliate		277			—			—
Capital contribution by parent company		175			150			—
Dividends on common stock		(305	)		(305	)		(305	)
Other		(7	)		(9	)		(6	)
Net cash from (used for) financing activities		134			138			(288	)
Net Increase in Cash and Cash Equivalents		20			1			20
Cash and Cash Equivalents at Beginning of the Period		27			26			6
Cash and Cash Equivalents at End of the Period	$	47		$	27		$	26

See Notes to Consolidated Financial Statements

24

The Detroit Edison Company

Consolidated Statements of Changes in Shareholder’s Equity and Comprehensive income

										Accumulated
					Additional					Other
	Common Stock				Paid in		Retained			Comprehensive
	Shares		Amount		Capital		Earnings			Income		Total
(Dollars in Millions,
Shares in Thousands)
Balance, December 31, 2004		138,632	$	1,386	$	1,060	$	531		$	2	$	2,979
Net income		—		—		—		274			—		274
Dividends declared on common stock		—		—		—		(305	)		—		(305	)
Balance, December 31, 2005		138,632		1,386		1,060		500			2		2,948
Net income		—		—		—		321			—		321
Dividends declared on common stock		—		—		—		(305	)		—		(305	)
Net change in unrealized gains on investments, net of tax		—		—		—		—			1		1
Capital contribution by parent company		—		—		150		—			—		150
Balance, December 31, 2006		138,632		1,386		1,210		516		$	3		3,115
Net income		—		—		—		317			—		317
Dividends declared on Common stock		—		—		—		(305	)		—		(305	)
Net change in unrealized gains on investments, net of tax		—		—		—		—			1		1
Capital contribution by parent company		—		—		175		—			—		175
Balance, December 31, 2007		138,632	$	1,386	$	1,385	$	528		$	4	$	3,303

The following table displays comprehensive income:

(in Millions)	2007		2006		2005
Net income	$	317	$	321	$	274
Other comprehensive income:
Net change in unrealized gain on investments, net of tax		1		1		—
Comprehensive income	$	318	$	322	$	274

See Notes to Consolidated Financial Statements

25

The Detroit Edison Company

Notes to Consolidated Financial Statements

NOTE 1 — SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure

The Detroit Edison Company (Detroit Edison) is a Michigan public utility engaged in the generation, purchase, distribution and sale of electric energy to approximately 2.2 million customers in southeastern Michigan. Detroit Edison is regulated by the MPSC and FERC. In addition, we are regulated by other federal and state regulatory agencies including the NRC, the EPA and MDEQ.

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

Principles of Consolidation

We consolidate all majority owned subsidiaries and investments in entities in which we have controlling influence. Non-majority owned investments are accounted for using the equity method when the company is able to influence the operating policies of the investee. Non-majority owned investments include investments in limited liability companies, partnerships or joint ventures. When we do not influence the operating policies of an investee, the cost method is used. These consolidated financial statements also reflect the Company’s proportionate interests in certain jointly owned utility plant. We eliminate all inter-company balances and transactions.

For entities that are considered variable interest entities we apply the provisions of FASB Interpretation No. (FIN) 46-R,Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51.

Basis of Presentation

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

Revenues

Revenues from the sale and delivery of electricity are recognized as services are provided. We record revenues for electric services provided but unbilled at the end of each month. Detroit Edison’s accrued revenues include a component for the cost of power sold that is recoverable through the PSCR mechanism. Annual PSCR proceedings before the MPSC permit Detroit Edison to recover prudent and reasonable supply costs. Any overcollection or undercollection of costs, including interest, will be reflected in future rates. See Note 4.

26

Comprehensive Income

Comprehensive income is the change in common shareholder’s equity during a period from transactions and events from non-owner sources, including net income. As shown in the following table, amounts recorded to other comprehensive income at December 31, 2007 include: unrealized gains and losses from derivatives accounted for as cash flow hedges and unrealized gains and losses on available for sale securities.

	Net		Net		Accumulated
	Unrealized		Unrealized		Other
	Gains on		Gains on		Comprehensive
(in Millions)	Derivatives		Investments		Income
Beginning balance	$	1	$	2	$	3
Current period change		—		1		1
Ending balance	$	1	$	3	$	4

Cash Equivalents and Restricted Cash

Cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with remaining maturities of three months or less. Restricted cash consists of funds held to satisfy requirements of certain debt agreements. Restricted cash designated for interest and principal payments within one year is classified as a current asset.

Inventories

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

Property, Retirement and Maintenance, and Depreciation and Depletion

Summary of property by classification as of December 31:

(in Millions)	2007			2006
Property, Plant and Equipment
Generation	$	8,100		$	7,667
Distribution		6,272			6,249
Total		14,372			13,916
Less Accumulated Depreciation and Depletion
Generation		(3,539	)		(3,410	)
Distribution		(2,101	)		(2,170	)
Total		(5,640	)		(5,580	)
Net Property, Plant and Equipment	$	8,732		$	8,336

Property is stated at cost and includes construction-related labor, materials, overheads and an allowance for funds used during construction (AFUDC). AFUDC capitalized during 2007 and 2006 was approximately $24 million and $18 million, respectively. The cost of properties retired, less salvage value, is charged to accumulated depreciation.

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Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2. Approximately $4 million of expenses related to the anticipated Fermi 2 refueling outage scheduled for 2009 were accrued at December 31, 2007. Amounts are being accrued on a pro-rata basis over an 18-month period that began in November 2007. This accrual of outage costs matches the regulatory recovery of these costs in rates set by the MPSC.

We base depreciation provisions for utility property on straight-line rates approved by the MPSC. The composite depreciation rate for Detroit Edison was 3.3% in 2007 and 2006, and 3.4% in 2005.

The average estimated useful life for our generation and distribution property was 40 years and 37 years, respectively, at December 31, 2007.

We credit depreciation, depletion and amortization expense when we establish regulatory assets for stranded costs related to the electric Customer Choice program and deferred environmental expenditures. We charge depreciation, depletion and amortization expense when we amortize the regulatory assets. We credit interest expense to reflect the accretion income on certain regulatory assets.

Intangible assets relating to capitalized software are classified as Property, plant and equipment and the related amortization is included in Accumulated depreciation on the Consolidated Statements of Financial Position. We capitalize the costs associated with computer software we develop or obtain for use in our business. We amortize intangible assets on a straight-line basis over the expected period of benefit, ranging from 5 or 15 years. Intangible assets amortization expense was $31 million in 2007, $28 million in 2006, and $33 million in 2005. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2007 were $376 million and $83 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2006 were $373 million and $52 million, respectively. Amortization expense of intangible assets is estimated to be $36 million annually for 2008 through 2012.

Asset Retirement Obligations

We have recorded asset retirement obligations in accordance with SFAS No. 143,Accounting for Asset Retirement Obligationsand FIN No. 47,Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. We have a legal retirement obligation for the decommissioning costs for our Fermi 1 and Fermi 2 nuclear plants. We have conditional retirement obligations for disposal of asbestos at certain of our power plants. To a lesser extent, we have conditional retirement obligations at certain service centers, and disposal costs for PCB contained within transformers and circuit breakers.

Timing differences arise in the expense recognition of legal asset retirement costs that we are currently recovering in rates. We defer such differences under SFAS No. 71,Accounting for the Effects of Certain Types of Regulation.

As a result of adopting FIN 47 on December 31, 2005, we recorded a plant asset of $13 million with offsetting accumulated depreciation of $10 million, and an asset retirement obligation liability of $32 million. We also recorded a cumulative effect amount as a reduction to a regulatory liability of $24 million and a cumulative effect charge against earnings of $3 million, after-tax in 2005.

No liability has been recorded with respect to lead-based paint, as the quantities of lead-based paint in our facilities are unknown. In addition, there is no incremental cost to demolitions of lead-based paint facilities vs. non-lead based paint facilities and no regulations currently exist requiring any type of special disposal of items containing lead-based paint.

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Ludington Hydroelectric Power Plant (a jointly owned plant) has an indeterminate life and no legal obligation currently exists to decommission the plant at some future date. Substations, manholes and certain other distribution assets within Detroit Edison have an indeterminate life. Therefore, no liability has been recorded for this asset.

A reconciliation of the asset retirement obligation for 2007 follows:

(in Millions)
Asset retirement obligations at January 1, 2007	$	1,069
Accretion		71
Liabilities settled		(7	)
Revision in estimated cash flows		37
Asset retirement obligations at December 31, 2007		1,170
Less amount included in current liabilities		(10	)
	$	1,160

Approximately $1.1 billion of the asset retirement obligations represents nuclear decommissioning liabilities that are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear plant.

Long-Lived Assets

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. If the carrying amount of the asset exceeds the expected future cash flows generated by the asset, an impairment loss is recognized resulting in the asset being written down to its estimated fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less cost to sell.

Intangible Assets

We have certain intangible assets relating to emission allowances.

Excise and Sales Taxes

We record the billing of excise and sales taxes as a receivable with an offsetting payable to the applicable taxing authority, with no impact on the Consolidated Statements of Operations.

Deferred Debt Costs

The costs related to the issuance of long-term debt are deferred and amortized over the life of each debt issue. In accordance with MPSC regulations, the unamortized discount, premium and expense related to debt redeemed with a refinancing are amortized over the life of the replacement issue.

Insured and Uninsured Risks

Our comprehensive insurance program provides coverage for various types of risks. Our insurance policies cover risk of loss from property damage, general liability, workers’ compensation, auto liability and directors’ and officers’ liability. Under our risk management policy, we self-insure portions of certain risks up to specified limits, depending on the type of exposure. We have an actuarially determined estimate of our incurred but not reported liability prepared annually and adjust our reserves for self-insured risks as appropriate.

Investments in Debt and Equity Securities

We generally classify investments in debt and equity securities as trading or available-for-sale and have recorded such investments at market value with unrealized gains or losses included in earnings or in other comprehensive income or loss, respectively. Changes in the fair value of Fermi 2 nuclear decommissioning-related investments are recorded as adjustments to regulatory

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assets or liabilities, due to a recovery mechanism from customers. Our investments are reviewed for impairment each reporting period. If the assessment indicates that the impairment is other than temporary, a loss is recognized resulting in the investment being written down to its estimated fair value. See Note 5.

Consolidated Statement of Cash Flows

A detailed analysis of the changes in assets and liabilities that are reported in the consolidated statement of cash flows follows:

(in Millions)	2007			2006			2005
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	(163	)	$	(36	)	$	(45	)
Inventories		(47	)		(28	)		(21	)
Recoverable pension and postretirement costs		594			(925	)		61
Accrued pensions		(330	)		125			41
Accounts payable		73			7			46
Accrued power supply cost recovery revenue		41			(101	)		(127	)
Accrued payroll		(50	)		47			—
Income taxes payable		10			16			(10	)
General taxes		4			13			(1	)
Risk management and trading activities		(4	)		—			—
Postretirement obligation		(239	)		803			110
Other assets		(387	)		(114	)		(3	)
Other liabilities		285			(20	)		47
	$	(213	)	$	(213	)	$	98

Supplementary cash and non-cash information for the years ended December 31 were as follows:

(in Millions)	2007		2006		2005
Cash Paid For
Interest (excluding interest capitalized)	$	295	$	278	$	267
Income taxes		280		141		118
Non-cash Financing Activity
Sale of assets		—		—		13

Asset (gains) and losses, net

In 2007, we recorded a $13 million reserve for a loan guaranty related to Detroit Edison’s former ownership of a steam heating business now owned by Thermal Ventures II, LP (Thermal) resulting in a loss which was partially offset by approximately $5 million in gains on land and other sales. In 2006, we sold excess land near one of our power plants for a $6 million pre-tax gain. In 2005, we sold land near our headquarters in Detroit, Michigan for a pre-tax gain of $26 million.

See the following notes for other accounting policies impacting our financial statements:

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

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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. The Company adopted SFAS No. 157 effective January 1, 2008. The FASB deferred the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009. The adoption of SFAS No. 157 will not have a material impact to the January 1, 2008 balance of retained earnings.

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 standard permits an entity to choose to measure many financial instruments and certain other items at fair value. The fair value option established by SFAS 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. The adoption of SFAS No. 159 is not expected to have a material impact to the Company’s financial statements. At January 1, 2008, the Company has not elected to use the fair value option for financial assets and liabilities held at that date.

Offsetting Amounts Related to Certain Contracts

In April 2007, the FASB issued FSP FIN 39-1,Amendment of FASB Interpretation No. 39. This standard will permit 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, with early application permitted. The FSP is to be applied retrospectively by adjusting the financial statements for all periods presented. The company adopted the FSP as of January 1, 2008.

Business Combinations

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.”The objective of this Statement is to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish that, this Statement establishes principles and requirements for how the acquirer:

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• Recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree;

• Recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and

• Determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.

SFAS No. 141(R) shall be applied prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Earlier adoption is prohibited. The Company is currently assessing the effects of this statement, and has not yet determined its impact on its consolidated financial statements.

Noncontrolling Interests in Consolidated Financial Statements

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51.”The standard requires:

• The ownership interests in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated statement of financial position within equity, but separate from the parent’s equity;

• The amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of income;

• Changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for as equity transactions;

• When a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary be initially measured at fair value. The gain or loss on the deconsolidation of the subsidiary is measured using the fair value of any noncontrolling equity investment rather than the carrying amount of that retained investment; and

• Entities provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.

SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. This Statement shall be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, except for the presentation and disclosure requirements. The presentation and disclosure requirements shall be applied retrospectively for all periods presented. The Company is currently assessing the effects of this statement, and has not yet determined its impact on its consolidated financial statements.

Stock-Based Compensation

Effective January 1, 2006, our parent company, DTE Energy, adopted SFAS No. 123(R),Share-Based Payment,using the modified prospective transition method. We receive an allocation of costs associated with stock compensation and the related impact of cumulative accounting adjustments. Our allocation for 2007 and 2006 for stock-based compensation expense was approximately $13 million and $14 million, respectively. The cumulative effect of the adoption of SFAS 123(R) was a decrease in expense of $1 million in the first quarter of 2006. The cumulative effect adjustment was due to the estimation and subsequent allocation of forfeitures for previously granted stock awards and performance shares. We have not restated any prior periods as a result of the adoption of SFAS 123(R).

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NOTE 3 — RESTRUCTURING

Performance Excellence Process

In mid-2005, the Company initiated a company-wide review of its operations called the Performance Excellence Process.  Specifically, the Company began a series of focused improvement initiatives within Detroit Edison and associated corporate support functions. The Company expects this process to continue into 2008.

The Company incurred CTA for employee severance and other costs. Other costs include project management and consultant support. Pursuant to MPSC authorization, beginning in the third quarter of 2006, Detroit Edison deferred approximately $102 million of CTA in 2006. Detroit Edison began amortizing deferred 2006 costs in 2007 as the recovery of these costs was provided for by the MPSC. Amortization expense amounted to $10 million in 2007. Detroit Edison deferred $54 million of CTA during 2007. See Note 4.

Amounts expensed are recorded in the Operation and maintenance line on the Consolidated Statement of Operations. Deferred amounts are recorded in the Regulatory asset line on the Consolidated Statement of Financial Position.

Costs incurred in 2007 and 2006 are as follows:

	Employee Severance Costs(1)				Other Costs				Total Cost
(in Millions)	2007		2006		2007		2006		2007		2006
Costs incurred:	$	15	$	51	$	50	$	56	$	65	$	107
Less amounts deferred or capitalized:		15		51		50		56		65		107
Amount expensed	$	—	$	—	$	—	$	—	$	—	$	—

(1) Includes corporate allocations

A liability for future CTA associated with the Performance Excellence Process has not been recognized because the Company has not met the recognition criteria of SFAS No. 146,Accounting for Costs Associated with Exit or Disposal Activities.

NOTE 4 — REGULATORY MATTERS

Regulation

Detroit Edison is subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to rates, recovery of certain costs, including the costs of generating facilities and regulatory assets, conditions of service, accounting and operating-related matters. Detroit Edison is also regulated by the FERC with respect to financing authorization and wholesale electric activities.

Regulatory Assets and Liabilities

Detroit Edison applies the provisions of SFAS No. 71,Accounting for the Effects of Certain Types of Regulation,to its operations. SFAS No. 71 requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as revenue and expense in non-regulated businesses.

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Continued applicability of SFAS No. 71 requires that rates be designed to recover specific costs of providing regulated services and be charged to and collected from customers. Future regulatory changes or changes in the competitive environment could result in the Company discontinuing the application of SFAS No. 71 for some or all of its business and may require the write-off of the portion of any regulatory asset or liability that was no longer probable of recovery through regulated rates. Management believes that currently available facts support the continued application of SFAS No. 71.

The following are balances and a brief description of the regulatory assets and liabilities at December 31:

(in Millions)	2007			2006
Assets
Securitized regulatory assets	$	1,124		$	1,235
Recoverable income taxes related to securitized regulatory assets		616			677
Recoverable pension and postretirement costs		874			1,469
Asset retirement obligation		266			236
Other recoverable income taxes		94			100
Recoverable costs under PA 141
Excess capital expenditures		11			22
Deferred Clean Air Act expenditures		28			67
Midwest Independent System Operator charges		23			48
Electric Customer Choice implementation costs		58			78
Enhanced security costs		10			13
Unamortized loss on reacquired debt		38			38
Accrued PSCR revenue		75			116
Costs to achieve Performance Excellence Process		146			102
Enterprise Business Systems costs		26			9
Deferred income taxes – Michigan Business Tax		318			—
Other		3			3
		2,586			2,978
Less amount included in current assets		(75	)		(116	)
	$	2,511		$	2,862
Liabilities
Asset removal costs	$	218		$	222
Accrued pension		43			33
Fermi 2 refueling outage		4			16
Deferred income taxes — Michigan Business Tax		318			—
Other		5			2
		588			273
Less amount included in current liabilities		(5	)		(18	)
	$	583		$	255

ASSETS

• Securitized regulatory assets— The net book balance of the Fermi 2 nuclear plant was written off in 1998 and an equivalent regulatory asset was established. In 2001, the Fermi 2 regulatory asset and certain other regulatory assets were securitized pursuant to PA 142 and an MPSC order. A non-bypassable securitization bond surcharge recovers the securitized regulatory asset over a fourteen-year period ending in 2015.

• Recoverable income taxes related to securitized regulatory assets— Receivable for the recovery of income taxes to be paid on the non-bypassable securitization bond surcharge. A non-bypassable securitization tax surcharge recovers the income tax over a fourteen-year period ending 2015.

• Recoverable pension and postretirement costs— The traditional rate setting process allows for the recovery of pension and postretirement costs as measured by generally accepted accounting principles.

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• Asset retirement obligation— Asset retirement obligations were recorded pursuant to adoption of SFAS No. 143 and FIN 47. These obligations are primarily for Fermi 2 decommissioning costs that are recovered in rates.

• Other recoverable income taxes— Income taxes receivable from Detroit Edison’s customers representing the difference in property-related deferred income taxes receivable and amounts previously reflected in Detroit Edison’s rates.

• Excess capital expenditures— PA 141 permits, after MPSC authorization, the recovery of and a return on capital expenditures that exceed a base level of depreciation expense.

• Deferred Clean Air Act expenditures— PA 141 permits, after MPSC authorization, the recovery of and a return on Clean Air Act expenditures.

• Midwest Independent System Operator charges— PA 141 permits, after MPSC authorization, the recovery of and a return on charges from a regional transmission operator such as the Midwest Independent System Operator.

• Electric Customer Choice implementation costs— PA 141 permits, after MPSC authorization, the recovery of and a return on costs incurred associated with the implementation of the electric Customer Choice program.

• Enhanced security costs— PA 609 of 2002 permits, after MPSC authorization, the recovery of enhanced security costs for an electric generating facility.

• Unamortized loss on reacquired debt— The unamortized discount, premium and expense related to debt redeemed with a refinancing are deferred, amortized and recovered over the life of the replacement issue.

• Accrued PSCR revenue— Receivable for the temporary under-recovery of and a return on fuel and purchased power costs incurred by Detroit Edison which are recoverable through the PSCR mechanism.

• Cost to achieve Performance Excellence Process (PEP)– The MPSC authorized the deferral of costs to implement the PEP. These costs consist of employee severance, project management and consultant support. These costs will be amortized over a ten-year period beginning with the year subsequent to the year the costs were deferred. See Note 3.

• Enterprise Business Systems (EBS) costs– Starting in 2006, the MPSC approved the deferral of up to $60 million of certain EBS costs that would otherwise be expensed.

• Deferred income taxes — Michigan Business Tax (MBT) –In July 2007, the MBT was enacted by the State of Michigan. State deferred tax liabilities were established and offsetting regulatory assets were recorded as the impacts of the deferred tax liabilities will be reflected in rates.

LIABILITIES

• Asset removal costs— The amount collected from customers for the funding of future asset removal activities.

• Accrued pension— Pension expense refundable to customers representing the difference created from volatility in the pension obligation and amounts recognized pursuant to MPSC authorization.

• Fermi 2 refueling outage– Accrued liability for refueling outage at Fermi 2 pursuant to MPSC authorization.

• Deferred income taxes — Michigan Business Tax (MBT) –In July 2007, the MBT was enacted by the State of Michigan. State deferred tax assets were established and offsetting regulatory liabilities were recorded as the impacts of the deferred tax assets will be reflected in rates.

MPSC Show-Cause Order

In March 2006, the MPSC issued an order directing Detroit Edison to show cause by June 1, 2006 why its rates should not be reduced in 2007. Detroit Edison filed its response explaining why its rates should not be reduced in 2007. The MPSC issued an order approving a settlement agreement in this proceeding on August 31, 2006. The order provided for an annualized rate reduction of $53 million for 2006, effective September 5, 2006. Beginning January 1, 2007, and continuing until April 13, 2008, one year from the

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filing of the general rate case on April 13, 2007, rates were reduced by an additional $26 million, for a total reduction of $79 million annually. The revenue reduction is net of the recovery of the amortization of the costs associated with the implementation of the Performance Excellence Process. The settlement agreement provided for some level of realignment of the existing rate structure by allocating a larger percentage share of the rate reduction to the commercial and industrial customer classes than to the residential customer classes.

As part of the settlement agreement, a Choice Incentive Mechanism (CIM) was established with a base level of electric choice sales set at 3,400 GWh. The CIM prescribes regulatory treatment of changes in non-fuel revenue attributed to increases or decreases in electric Customer Choice sales. If electric Customer Choice sales exceed 3,600 GWh, Detroit Edison will be able to recover 90 percent of its reduction in non-fuel revenue from full service customers up to $71 million. If electric Customer Choice sales fall below 3,200 GWh, Detroit Edison will credit 100 percent of the increase in non-fuel revenue to the unrecovered regulatory asset balance. Approximately $28 million was credited to the unrecovered regulatory asset in 2007.

2007 Electric Rate Case Filing

Pursuant to the February 2006 MPSC order in Detroit Edison’s rate restructuring case and the August 2006 MPSC 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 requested a $123 million, or 2.9 percent, average increase in Detroit Edison’s annual revenue requirement for 2008.

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

In addition, Detroit Edison’s filing makes, among other requests, the following proposals:

•   Make progress toward correcting the existing rate structure to more accurately reflect the actual cost of providing service to customers.

•   Equalize distribution rates between Detroit Edison full service and electric Customer Choice customers.

•   Re-establish with modification the CIM originally established in the Detroit Edison 2006 show cause filing. The CIM reconciles changes related to customers moving between Detroit Edison full service and electric Customer Choice.

•   Terminate the Pension Equalization Mechanism.

•   Establish an emission allowance pre-purchase plan to ensure that adequate emission allowances will be available for environmental compliance.

•   Establish a methodology for recovery of the costs associated with preparation of an application for a new nuclear generation facility.

Also, in the filing, in conjunction with Michigan’s 21st Century Energy Plan, Detroit Edison has reinstated a long-term integrated resource planning (IRP) process with the purpose of developing the least overall cost plan to serve customers’ generation needs over the next 20 years. Based on the IRP, new base load capacity may be required for Detroit Edison. To protect tax credits available under Federal law,

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Detroit Edison determined it would be prudent to initiate the application process for a new nuclear unit. Detroit Edison has not made a final decision to build a new nuclear unit. Detroit Edison is preserving its option to build at some point in the future by beginning the complex nuclear licensing process in 2007. Also, beginning the licensing process at the present time positions Detroit Edison, potentially, to take advantage of tax incentives of up to $320 million derived from provisions in the 2005 Federal Energy Policy Act that will benefit customers. To qualify for these substantial tax credits, a combined operating license application for construction and operation of an advanced nuclear generating plant must be docketed by the Nuclear Regulatory Commission no later than December 31, 2008. Preparation and approval of a combined operating license can take up to 4 years and is estimated to cost at least $60 million. At December 31, 2007, costs related to preparing the combined licensing application totaling $10 million have been deferred and included in Other assets.

On August 31, 2007, Detroit Edison filed a supplement to its April 2007 rate case filing. A July 2007 decision by the Court of Appeals of the State of Michigan remanded back to the MPSC the November 2004 order in a prior Detroit Edison rate case that denied recovery of merger control premium costs. The supplemental filing addressed recovery of approximately $61 million related to the merger control premium. The filing also included the impact of the July 2007 enactment of the MBT, and other adjustments. The net impact of the supplemental changes results in an additional revenue requirement of approximately $76 million average increase in Detroit Edison’s annual revenue requirement for 2008.

On February 20, 2008, Detroit Edison filed an update to its April 2007 rate case filing. The update reflects the use of 2009 as the projected test year and includes a revised 2009 load forecast, and 2009 estimates on environmental and advanced metering infrastructure capital expenditures, and adjustments to the calculation of the MBT. In addition the update also includes the August 2007 supplemental filing adjustments for the merger control premium, the new MBT, and environmental operating and maintenance adjustments. The net impact of the updated filing results in an additional revenue requirement of approximately $85 million average increase in Detroit Edison’s annual revenue requirement for 2009. The total filing requests a $284 million increase in Detroit Edison’s annual revenue for 2009. An MPSC order related to this filing is expected in 2009.

Regulatory Accounting Treatment for Performance Excellence Process

In May 2006, Detroit Edison filed an application with the MPSC to allow deferral of costs associated with the implementation of the Performance Excellence Process, a company-wide cost-savings and performance improvement program. Detroit Edison sought MPSC authorization to defer and amortize Performance Excellence Process implementation costs for accounting purposes to match the expected savings from the Performance Excellence Process program with the related CTA. Detroit Edison anticipates the Performance Excellence Process to continue into 2008. In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison commencing in 2006, to defer the incremental CTA. Further, the order provides for Detroit Edison to amortize the CTA deferrals over a ten-year period beginning with the year subsequent to the year the CTA was deferred. At year-end 2006, Detroit Edison recorded deferred CTA costs of $102 million as a regulatory asset and began amortizing deferred 2006 costs in 2007, as the recovery of these costs was provided for by the MPSC in its order approving the settlement of the show cause proceeding. During 2007, Detroit Edison deferred CTA costs of $54 million. Amortization of prior year deferred CTA costs amounted to $10 million during 2007.

Accounting for Costs Related to Enterprise Business Systems (EBS)

In July 2004, Detroit Edison filed an accounting application with the MPSC requesting authority to capitalize and amortize costs related to EBS, consisting of computer equipment, software and development costs, as well as related training, maintenance and overhead costs. In April 2005, the MPSC

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approved a settlement agreement providing for the deferral of up to $60 million of certain EBS costs, which would otherwise be expensed, as a regulatory asset for future rate recovery starting January 1, 2006. At December 31, 2007, approximately $26 million of EBS costs have been deferred as a regulatory asset. In addition, EBS costs recorded as plant assets will be amortized over a 15-year period, pursuant to MPSC authorization.

Fermi 2 Enhanced Security Costs Settlement

The Customer Choice and Electricity Reliability Act, as amended in 2003, allows for the recovery of reasonable and prudent costs of new and enhanced security measures required by state or federal law, including providing for reasonable security from an act of terrorism. In December 2006, Detroit Edison filed an application with the MPSC for recovery of $11.4 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 2 ESC incurred during the period of September 11, 2001 through December 31, 2005. The settlement defined Detroit Edison’s ESC, discounted back to September 11, 2001, as $9.1 million, plus carrying charges. A total of $13 million, including carrying charges, has been deferred as a regulatory asset. Detroit Edison is authorized to incorporate into its rates an enhanced security factor over a period not to exceed five years. Amortization of this regulatory asset was approximately $3 million in 2007.

Reconciliation of Regulatory Asset Recovery Surcharge

In December 2006, Detroit Edison filed a reconciliation of costs underlying its existing Regulatory Asset Recovery Surcharge (“RARS”). This true-up filing was made to maximize the remaining time for recovery of significant cost increases prior to expiration of the RARS five-year recovery limit under PA 141. Detroit Edison requested a reconciliation of the regulatory asset surcharge to ensure proper recovery by the end of the five year period of: (1) Clean Air Act Expenditures, (2) Capital in Excess of Base Depreciation, (3) MISO Costs and (4) the regulatory liability for the 1997 Storm Charge. In July 2007, the MPSC approved a negotiated RARS deficiency settlement that resulted in a $10 million write down of RARS-related costs in 2007. As previously, discussed above, the CIM in the MPSC Show-Cause Order will reduce the regulatory asset. Approximately $28 million was credited to the unrecovered regulatory asset in 2007 due to the CIM.

Power Supply Costs Recovery Proceedings

2005 Plan Year– In March 2006, Detroit Edison filed its 2005 PSCR reconciliation that sought approval 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, the filing included a reconciliation for the Pension Equalization Mechanism (PEM) for the periods from November 24, 2004 through December 31, 2004 and from January 1, 2005 through December 31, 2005. The PEM reconciliation seeks to allocate and refund approximately $12 million to customers based upon their contributions to pension expense during the subject periods. In September 2006, the MPSC ordered the Company to roll the entire 2004 PSCR over-collection amount to the Company’s 2005 PSCR Reconciliation. An order was issued on May 22, 2007 approving a 2005 PSCR undercollection amount of $94 million and the recovery of this amount through a surcharge for 12 months beginning in June 2007. In addition, the order approved Detroit Edison’s proposed PEM reconciliation that was refunded to customers on a bills-rendered basis during June 2007.

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2006 Plan Year —In September 2005, Detroit Edison filed its 2006 PSCR plan case seeking approval of a levelized PSCR factor of 4.99 mills per kWh above the amount included in base rates for residential customers and 8.29 mills per kWh above the amount included in base rates for commercial and industrial customers. Included in the factor for all customers are fuel and power supply costs, including transmission expenses, Midwest Independent Transmission System Operator (MISO) market participation costs, and NOx emission allowance costs. The Company’s PSCR Plan included a matrix which provided for different maximum PSCR factors contingent on varying electric Customer Choice sales levels. The plan also included $97 million for recovery of its projected 2005 PSCR under-collection associated with commercial and industrial customers. Additionally, the PSCR plan requested MPSC approval of expense associated with sulfur dioxide emission allowances, mercury emission allowances, and a fuel additive. In conjunction with DTE Energy’s sale of its transmission assets to ITC Transmission in February 2003, the FERC froze ITC Transmission’s rates through December 2004. In approving the sale, FERC authorized ITC Transmission’s recovery of the difference between the revenue it would have collected and the actual revenue collected during the rate freeze period. This amount is estimated to be $66 million which is to be included in ITC Transmission’s rates over a five-year period beginning June 1, 2006. This increased Detroit Edison’s transmission expense in 2006 by approximately $7 million. The MPSC authorized Detroit Edison in 2004 to recover transmission expenses through the PSCR mechanism.

In December 2005, the MPSC issued a temporary order authorizing the Company to begin implementation of maximum quarterly PSCR factors on January 1, 2006. The quarterly factors reflect a downward adjustment in the Company’s total power supply costs of approximately 2 percent to reflect the potential variability in cost projections. The quarterly factors allowed the Company to more closely track the costs of providing electric service to our customers and, because the non-summer factors are well below those ordered for the summer months, effectively delay the higher power supply costs to the summer months at which time our customers will not be experiencing large expenditures for home heating. The MPSC did not adopt the Company’s request to recover its projected 2005 PSCR under-collection associated with commercial and industrial customers nor did it adopt the Company’s request to implement contingency factors based upon the Company’s increased costs associated with providing electric service to returning electric Customer Choice customers. The MPSC deferred both of those Company proposals to the final order on the Company’s entire 2006 PSCR plan. In September 2006, the MPSC issued an order in this case that approved the inclusion of sulfur dioxide emission allowance expense in the PSCR, determined that fuel additive expense should not be included in the PSCR based upon its impact on maintenance expense, found the Company’s determination of third party sales revenues to be correct, and allowed the Company to increase its PSCR factor for the balance of the year in an effort to reverse the effects of the previously ordered temporary reduction. The MPSC declined to rule on the Company’s requests to include mercury emission allowance expense in the PSCR or its request to include prior PSCR over/(under) recoveries in future year PSCR plans. The Company filed its 2006 PSCR reconciliation case in March 2007. The $51 million PSCR under-collection amount reflected in that filing is being collected in the 2007 PSCR plan. Included in the 2006 PSCR reconciliation filing was the Company’s 2006 PEM reconciliation that reflects a $21 million ovecollection which is subject to refund to customers. An MPSC order in this case is expected in 2008.

2007 Plan Year —In September 2006, Detroit Edison filed its 2007 PSCR plan case seeking approval of a levelized PSCR factor of 6.98 mills per kWh above the amount included in base rates for all PSCR customers. The Company’s PSCR plan filing included $130 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 includes fuel and power supply costs, including NOx and SO₂ emission allowance costs, transmission costs and MISO costs. The Company filed supplemental testimony and briefs in December 2006 supporting its updated request to include approximately $81 million for the recovery of its projected 2006 PSCR under-collection. The MPSC issued a temporary order in December 2006 approving the Company’s request. In addition, Detroit Edison was granted the

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authority to include all PSCR over/(under) collections in future PSCR plans, thereby reducing the time between refund or recovery of PSCR reconciliation amounts. The Company began to collect its 2007 power supply costs, including the 2006 rollover amount, through a PSCR factor of 8.69 mills/kWh on January 1, 2007. The Company reduced the PSCR factor to 6.69 mills/kWh on July 1, 2007 based on the updated 2007 PSCR plan year projections. In August 2007, the MPSC approved Detroit Edison’s 2007 PSCR case and authorized the Company to charge a maximum power supply cost recovery factor of 8.69 mills/kWh in 2007.

2008 Plan Year —In September 2007, Detroit Edison filed its 2008 PSCR plan case seeking approval of a levelized PSCR factor of 9.23 mills/kWh above the amount included in base rates for all PSCR customers. The Company is supporting a total 2008 power supply expense forecast of $1.3 billion that includes $1 million for the recovery of its projected 2007 PSCR under-collection. The Company’s PSCR Plan will allow the Company to recover its reasonably and prudently incurred power supply expense including; fuel costs, purchased and net interchange power costs, NOx and SO₂ emission allowance costs, transmission costs and MISO costs. Also included in the filing is a request for approval of the Company’s emission compliance strategy which includes pre-purchases of emission allowances as well as a request for pre-approval of a contract for capacity and energy associated with a renewable (wind energy) project. On January 31, 2008, Detroit Edison filed a revised PSCR plan case seeking approval of a levelized PSCR factor of 11.22 mills/kWh above the amount included in base rates for all PSCR customers. The revised filing supports a 2008 power supply expense forecast of $1.4 billion and includes $43 million for the recovery of a projected 2007 PSCR under-collection. On March 11, 2008, the commission ordered that Detroit Edison shall not self-implement the 11.22 mills/kWh PSCR factor proposed in its January 31, 2008 filing.

Other

On July 3, 2007, the Court of Appeals of the State of Michigan published its decision with respect to an appeal by Detroit Edison and others of certain provisions of a November 23, 2004 MPSC order, including reversing the MPSC’s denial of recovery of merger control premium costs. In its published decision, the Court of Appeals held that Detroit Edison is entitled to recover its allocated share of the merger control premium and remanded this matter to the MPSC for further proceedings to establish the precise amount and timing of this recovery. Detroit Edison filed a 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.

The Company is unable to predict the outcome of the regulatory matters discussed herein. Resolution of these matters is dependent upon future MPSC orders and appeals, which may materially impact the financial position, results of operations and cash flows of the Company.

NOTE 5 — NUCLEAR OPERATIONS

General

Fermi 2, the Company’s nuclear generating plant, began commercial operation in 1988. Fermi 2 has a design electrical rating (net) of 1,150 MW. This plant represents approximately 10% of Detroit Edison’s summer net rated capability. The net book balance of the Fermi 2 plant was written off at December 31, 1998, and an equivalent regulatory asset was established. In 2001, the Fermi 2 regulatory asset was securitized. Detroit Edison also owns Fermi 1, a nuclear plant that was shut down in 1972 and is currently being decommissioned. The NRC has jurisdiction over the licensing and operation of Fermi 2 and the decommissioning of Fermi 1.

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Property Insurance

Detroit Edison maintains several different types of property insurance policies specifically for the Fermi 2 plant. These policies cover such items as replacement power and property damage. The Nuclear Electric Insurance Limited (NEIL) is the primary supplier of the insurance polices.

Detroit Edison maintains a policy for extra expenses, including replacement power costs necessitated by Fermi 2’s unavailability due to an insured event. This policy has a 12-week waiting period and provides an aggregate $490 million of coverage over a three-year period.

Detroit Edison has $500 million in primary coverage and $2.25 billion of excess coverage for stabilization, decontamination, debris removal, repair and/or replacement of property and decommissioning. The combined coverage limit for total property damage is $2.75 billion.

The Terrorism Risk Insurance Extension Act of 2005 (TRIA) was scheduled to expire on December 15, 2007. Effective December 26, 2007, the Terrorism Risk Insurance Program Reauthorization Act of 2007 extended the TRIA though December 31, 2014. A major change in the extension is the inclusion of “domestic” acts of terrorism in the definition of covered or “certified” acts.

For multiple terrorism losses caused by acts of terrorism not covered under the TRIA occurring within one year after the first loss from terrorism, the NEIL policies would make available to all insured entities up to $3.2 billion, plus any amounts recovered from reinsurance, government indemnity, or other sources to cover losses.

Under the NEIL policies, Detroit Edison could be liable for maximum assessments of up to approximately $31 million per event if the loss associated with any one event at any nuclear plant in the United States should exceed the accumulated funds available to NEIL.

Public Liability Insurance

As required by federal law, Detroit Edison maintains $300 million of public liability insurance for a nuclear incident. For liabilities arising from a terrorist act outside the scope of TRIA, the policy is subject to one industry aggregate limit of $300 million. Further, under the Price-Anderson Amendments Act of 2005, deferred premium charges up to $101 million could be levied against each licensed nuclear facility, but not more than $15 million per year per facility. Thus, deferred premium charges could be levied against all owners of licensed nuclear facilities in the event of a nuclear incident at any of these facilities.

Decommissioning

Detroit Edison has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. This obligation is reflected as an asset retirement obligation on the Statements of Financial Position. Based on the actual or anticipated extended life of the nuclear plant, decommissioning expenditures for Fermi 2 are expected to be incurred primarily during the period of 2025 through 2050. It is estimated that the cost of decommissioning Fermi 2, when its license expires in 2025, will be $1.3 billion in 2007 dollars and $3.4 billion in 2025 dollars, using a 6% inflation rate. In 2001, Detroit Edison began the decommissioning of Fermi 1, with the goal of removing the radioactive material and terminating the Fermi 1 license. The decommissioning of Fermi 1 is expected to be complete by 2010.

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The NRC has jurisdiction over the decommissioning of nuclear power plants and requires decommissioning funding based upon a formula. The MPSC and FERC regulate the recovery of costs of decommissioning nuclear power plants and both require the use of external trust funds to finance the decommissioning of Fermi 2. Rates approved by the MPSC provide for the recovery of decommissioning costs of Fermi 2 and the disposal of low-level radioactive waste. Detroit Edison is continuing to fund FERC jurisdictional amounts for decommissioning even though explicit provisions are not included in FERC rates. The Company believes the MPSC and FERC collections will be adequate to fund the estimated cost of decommissioning using the NRC formula. The decommissioning assets, anticipated earnings thereon and future revenues from decommissioning collections will be used to decommission the nuclear facilities. The Company expects the regulatory liabilities to be reduced to zero at the conclusion of the decommissioning activities. If amounts remain in the trust funds for these units following the completion of the decommissioning activities, those amounts will be disbursed based on rulings by the MPSC and FERC.

A portion of the funds recovered through the Fermi 2 decommissioning surcharge and deposited in external trust accounts is designated for the removal of non-radioactive assets and the clean-up of the Fermi site. This removal and clean-up is not considered a legal liability. Therefore, it is not included in the asset retirement obligation, but is reflected as the nuclear decommissioning regulatory liability.

The decommissioning of Fermi 1 is funded by Detroit Edison. Contributions to the Fermi 1 trust are discretionary.

The following table summarizes the fair value of the nuclear decommissioning trust fund assets.

	As of December 31
(in Millions)	2007		2006
Fermi 2	$	778	$	694
Fermi 1		13		15
Low level radioactive waste		33		31
Total	$	824	$	740

At December 31, 2007, investments in the external nuclear decommissioning trust funds consisted of approximately 54% in publicly traded equity securities, 45% in fixed debt instruments and 1% in cash equivalents. The debt securities had an average maturity of approximately 5.3 years.

At December 31, 2006, investments in the external nuclear decommissioning trust funds consisted of approximately 54% in publicly traded equity securities, 43% in fixed debt instruments and 3% in cash equivalents. The debt securities had an average maturity of approximately 5.1 years.

The costs of securities sold are determined on the basis of specific identification. The following table sets forth the gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds:

	Year Ended December 31
(in Millions)	2007			2006			2005
Realized gains	$	25		$	21		$	11
Realized losses		(17	)		(9	)		(8	)
Proceeds from sales of securities	$	286		$	253		$	201

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Realized gains and losses and proceeds from sales of securities for the Fermi 2 and the Low Level Radioactive Waste funds are recorded to the asset retirement obligation regulatory asset and nuclear decommissioning regulatory liability, respectively. The following table sets forth the fair value and unrealized gains for the nuclear decommissioning trust funds:

			Total
	Fair		Unrealized
(in Millions)	Value		Gains
As of December 31, 2007
Equity Securities	$	443	$	170
Debt Securities		373		9
Cash and Cash Equivalents		8		—
	$	824	$	179
As of December 31, 2006
Equity Securities	$	399	$	140
Debt Securities		316		4
Cash and Cash Equivalents		25		—
	$	740	$	144

Securities held in the nuclear decommissioning trust funds are classified as available-for-sale. As Detroit Edison does not have the ability to hold impaired investments for a period of time sufficient to allow for the anticipated recovery of market value, all unrealized losses are considered to be “other than temporary” impairments.

Impairment charges for unrealized losses incurred by the Fermi 2 trust are recognized as a regulatory asset. Detroit Edison recognized $22 million and $10 million of unrealized losses as regulatory assets for the years ended December 31, 2007 and 2006, respectively. Since the decommissioning of Fermi 1 is funded by Detroit Edison rather than through a regulatory recovery mechanism, there is no corresponding regulatory asset treatment. Therefore, impairment charges for unrealized losses incurred by the Fermi 1 trust are recognized in earnings immediately. For the years ended December 31, 2007 and 2006, Detroit Edison recognized impairment charges of $0.2 million in each year for unrealized losses incurred by the Fermi 1 trust.

Nuclear Fuel Disposal Costs

In accordance with the Federal Nuclear Waste Policy Act of 1982, Detroit Edison has a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. Detroit Edison is obligated to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold. The fee is a component of nuclear fuel expense. Delays have occurred in the DOE’s program for the acceptance and disposal of spent nuclear fuel at a permanent repository. Detroit Edison is a party in the litigation against the DOE for both past and future costs associated with the DOE’s failure to accept spent nuclear fuel under the timetable set forth in the Federal Nuclear Waste Policy Act of 1982. Detroit Edison currently employs a used nuclear fuel storage strategy utilizing a spent fuel pool. In December 2007, Detroit Edison announced plans to move to a dry cask storage method which is expected to provide sufficient storage capability for the life of the plant.

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NOTE 6 — JOINTLY OWNED UTILITY PLANT

Detroit Edison has joint ownership interest in two power plants, Belle River and Ludington Hydroelectric Pumped Storage. Ownership information of the two utility plants as of December 31, 2007 was as follows:

			Ludington
			Hydroelectric
	Belle River		Pumped Storage
In-service date		1984-1985		1973
Total plant capacity	1,026 MW		1,872 MW
Ownership interest		*		49	%
Investment (in Millions)	$	1,575	$	164
Accumulated depreciation (in Millions)	$	847	$	101

* Detroit Edison’s ownership interest is 63% in Unit No. 1, 81% of the facilities applicable to Belle River used jointly by the Belle River and St. Clair Power Plants and 75% in common facilities used at Unit No. 2.

Belle River

The Michigan Public Power Agency (MPPA) has an ownership interest in Belle River Unit No. 1 and other related facilities. The MPPA is entitled to 19% of the total capacity and energy of the plant and is responsible for the same percentage of the plant’s operation, maintenance and capital improvement costs.

Ludington Hydroelectric Pumped Storage

Consumers Energy Company has an ownership interest in the Ludington Hydroelectric Pumped Storage Plant. Consumers Energy is entitled to 51% of the total capacity and energy of the plant and is responsible for the same percentage of the plant’s operation, maintenance and capital improvement costs.

NOTE 7 — INCOME TAXES

Income Tax Summary

We are part of the consolidated federal income tax return of DTE Energy. The federal income tax expense for Detroit Edison is determined on an individual company basis with no allocation of tax benefits or expenses from other affiliates of DTE Energy. We have an income tax receivable of $34 million at December 31, 2007 and $16 million at December 31, 2006 due from DTE Energy.

Total income tax expense varied from the statutory federal income tax rate for the following reasons:

(Dollars in Millions)	2007			2006			2005
Income tax expense at 35% statutory rate	$	163		$	169		$	149
Investment tax credits		(7	)		(7	)		(7	)
Depreciation		3			3			3
Employee Stock Ownership Plan dividends		(4	)		(4	)		(4	)
Medicare Part D subsidy		(4	)		(5	)		(6	)
Adjustment to deferred tax accounts		—			—			14
Other, net		(2	)		6			—
Total	$	149		$	162		$	149
Effective federal income tax rate		32.0	%		33.6	%		35.0	%

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Components of income tax expense were as follows:

(in Millions)	2007			2006		2005
Current federal and other income tax expense (benefit)	$	260		$	160	$	110
Deferred federal and other income tax expense		(111	)		2		39
Total	$	149		$	162	$	149

Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in the financial statements. Deferred tax assets and liabilities are classified as current or noncurrent according to the classification of the related assets or liabilities. Deferred tax assets and liabilities not related to assets or liabilities are classified according to the expected reversal date of the temporary differences.

Deferred income tax assets (liabilities) were comprised of the following at December 31:

(in Millions)	2007			2006
Property, plant and equipment	$	(1,156	)	$	(1,209	)
Securitized regulatory assets		(621	)		(670	)
Pension and benefits		101			94
Other comprehensive income		(2	)		(1	)
Other, net		(176	)		(180	)
	$	(1,854	)	$	(1,966	)
Deferred income tax liabilities	$	(2,662	)	$	(2,478	)
Deferred income tax assets		808			512
	$	(1,854	)	$	(1,966	)
Current deferred income tax liabilities (included in Current Liabilities – Other)	$	(29	)		(38	)
Long term deferred income tax liabilities		(1,825	)		(1,928	)
	$	(1,854	)		(1,966	)

The above table excludes deferred tax liabilities associated with unamortized investment tax credits that are shown separately on the Consolidated Statement of Financial Position.

Uncertain Tax Positions

The Company adopted the provisions of FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109 (FIN 48)on January 1, 2007. This interpretation prescribes a more-likely-than-not recognition threshold and a measurement attribute for the financial statement reporting of tax positions taken or expected to be taken on a tax return. As a result of the implementation of FIN 48, the Company recognized a decrease in liabilities that was accounted for as an increase to the January 1, 2007 balance of retained earnings in an immaterial amount. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

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(in Millions)
Balance at January 1, 2007	$	12
Additions for tax positions of prior years		2
Settlements		(7	)
Balance at December 31, 2007	$	7

Unrecognized tax benefits at January 1, 2007 and at December 31, 2007, if recognized, would not favorably impact our effective tax rate. We do not anticipate any significant changes in the unrecognized tax benefits during the next twelve months.

The Company recognizes interest and penalties pertaining to income taxes in Interest expense and Other expenses, respectively, on its Consolidated Statements of Operations. Accrued interest pertaining to income taxes totaled $1 million and $1 million at January 1, 2007 and December 31, 2007, respectively. The Company had no accrued penalties pertaining to income taxes. The Company recognized interest expense related to income taxes of $1 million during 2007.

The U.S. federal income tax returns for years 2004 and subsequent years remain subject to examination by the IRS for DTE Energy Company and its subsidiaries. The Company also files tax returns in various state and local tax jurisdictions with varying statutes of limitation.

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 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.

In 2007 a state deferred tax liability of $318 million was recognized by the Company for cumulative differences between book and tax assets and liabilities for the Company. Effective September 30, 2007, legislation was adopted by the State of Michigan creating a deduction for businesses that realize an increase in their deferred tax liability due to the enactment of the MBT. Therefore, a deferred tax asset of $318 million was established related to the future deduction. 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 2007.

The $318 million of deferred tax liabilities and assets recognized by the Company was offset by corresponding regulatory assets 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.

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NOTE 8 — LONG-TERM DEBT

Our long-term debt outstanding and weighted average interest rates(1) of debt outstanding at December 31 were:

(in Millions)	2007			2006
Detroit Edison Taxable Debt, Principally Secured
5.9% due 2010 to 2038	$	2,305		$	2,267
Detroit Edison Tax Exempt Revenue Bonds (2)
5.3% due 2008 to 2036		1,213			1,213
Other Long-Term Debt		—			59
		3,518			3,539
Less amount due within one year		(45	)		(24	)
	$	3,473		$	3,515
Securitization Bonds
6.4% due 2008 to 2015	$	1,185		$	1,295
Less amount due within one year		(120	)		(111	)
	$	1,065		$	1,184

(1)	Weighted average interest rates as of December 31, 2007 are shown below the description of each category of debt.
(2)	Detroit Edison Tax Exempt Revenue Bonds are issued by a public body that loans the proceeds to Detroit Edison on terms substantially mirroring the Revenue Bonds.

Debt Issuances

In 2007, we issued the following long-term debt:

Month						(in Millions)
Issued	Type	Interest Rate			Maturity	Amount
December	Senior Notes (1)		6.47	%	March 2038	$	50

(1) The proceeds from the issuance were used to refinance other long-term debt and for general corporate purposes.

Debt Retirements and Redemptions

The following debt was retired, through optional redemption or payment at maturity, during 2007.

Month						(in Millions)
Retired	Type	Interest Rate			Maturity	Amount
December	Other long term debt		7.61	%	June 2011	$	47

The following table shows the scheduled debt maturities, excluding any unamortized discount or premium on debt:

											2013 &
(in Millions)	2008		2009		2010		2011		2012		thereafter		Total
Amount to mature	$	165	$	145	$	652	$	303	$	402	$	3,041	$	4,708

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Cross Default Provisions

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

Other

As of December 31, 2007, the Company had $238 million of variable auction rate tax exempt bonds outstanding. These bonds, which are subject to rate reset every 7 days, are insured by bond insurers. Overall credit market conditions have resulted in credit rating downgrades and may result in future credit rating downgrades for the bond insurers. This has caused a loss in liquidity in the auction rate markets for their insured bonds. These conditions have negatively impacted interest rates, including default rates in the case of failed auctions. The Company does not expect its interest rate exposure regarding these bonds to be material.

NOTE 9 — PREFERRED SECURITIES

At December 31, 2007, Detroit Edison had approximately 6.75 million shares of preferred stock with a par value of $100 per share and 30 million shares of preference stock with a par value of $1 per share authorized, with no shares issued.

NOTE 10 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

In October 2005, Detroit Edison entered into a $69 million, five-year unsecured revolving credit agreement and simultaneously amended its existing $206 million, five-year credit facility entered into in October 2004. Our aggregate availability under the combined facilities is $275 million. The five-year credit facilities are with a syndicate of banks and may be utilized for general corporate borrowings, but are intended to provide liquidity support for our commercial paper program. Borrowings under the facilities are available at prevailing short-term interest rates. The agreements require us to maintain a debt to total capitalization ratio of no more than 0.65 to 1. Should we have delinquent obligations of at least $50 million to any creditor, such delinquency will be considered a default under our credit agreements.

Detroit Edison is currently in compliance with its covenants.

We had outstanding commercial paper of $181 million and $177 million at December 31, 2007 and 2006, respectively.

The weighted average interest rate for short-term borrowings were 5.4% at December 31, 2007 and 2006.

Detroit Edison has a $200 million short-term financing agreement secured by customer accounts receivable. This agreement contains certain covenants related to the delinquency of accounts receivable.

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Detroit Edison is currently in compliance with these covenants. We had an outstanding balance of $125 million and $100 million at December 31, 2007 and December 31, 2006, respectively.

Detroit Edison initiated a $100 million short-term unsecured bank loan in the fourth quarter of 2007. The purpose of these loans was to enhance liquidity and reduce reliance on the commercial paper market. The loans have covenants identical to those specified under our back-up credit facilities. Detroit Edison was in compliance with those covenants at December 31, 2007. Detroit Edison had $100 million outstanding under these loans at December 31, 2007.

NOTE 11 — CAPITAL AND OPERATING LEASES

Lessee– We lease various assets under capital and operating leases, including coal cars, computers, vehicles and other equipment. The lease arrangements expire at various dates through 2023.

Future minimum lease payments under non-cancelable leases at December 31, 2007 were:

	Capital			Operating
(in Millions)	Leases			Leases
2008	$	11		$	37
2009		11			30
2010		9			23
2011		7			18
2012		5			17
Thereafter		17			69
Total minimum lease payments		60		$	194
Less imputed interest		(10	)
Present value of net minimum lease payments		50
Less current portion		(8	)
Non-current portion	$	42

Rental expense for operating leases was $48 million in 2007, $44 million in 2006, and $28 million in 2005.

NOTE 12 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

We comply with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. Under SFAS No. 133, all derivatives are recognized on the Consolidated Statements of Financial Position at their fair value unless they qualify for certain scope exceptions, including normal purchases and normal sales exception. Further, derivatives that qualify and are designated for hedge accounting are classified as either hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge), or as hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge). For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the value of the underlying exposure is deferred in Accumulated other comprehensive income and later reclassified into earnings when the underlying transaction occurs. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For derivatives that do not qualify or are not designated for hedge accounting, changes in the fair value are recognized in earnings each period.

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Our primary market risk exposure is associated with commodity prices and credit. We have risk management policies to monitor and decrease market risks. We use derivative instruments to manage some of the exposure. We do not hold or issue derivative instruments for trading purposes.

Commodity Price Risk

Detroit Edison uses forward energy and capacity contracts to manage changes in the price of electricity and fuel. Substantially all of these derivatives meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. Other derivative contracts are recoverable through the PSCR mechanism when realized. This results in the deferral of unrealized gains and losses or regulatory assets or liabilities until realized.

Credit Risk

We are exposed to credit risk if customers or counterparties do not comply with their contractual obligations. We maintain credit policies that significantly minimize overall credit risk. These policies include an evaluation of potential customers’ and counterparties’ financial condition, credit rating, collateral requirements or other credit enhancements such as letters of credit or guarantees. We generally use standardized agreements that allow the netting of positive and negative transactions associated with a single counterparty.

The Company maintains a provision for credit losses based on factors surrounding the credit risk of its customers, historical trends, and other information. Based on the Company’s credit policies and its December 31, 2007 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to result in material effects on the Company’s financial statements.

Fair Value of Other Financial Instruments

The fair value of financial instruments is determined by using various market data and other valuation techniques. The table below shows the fair value relative to the carrying value for long-term debt securities. The carrying value of certain other financial instruments, such as notes payable, customer deposits and notes receivable approximate fair value and are not shown. As of December 31, 2007, the Company had approximately $1 billion of tax exempt securities insured by insurers. Since December 31, 2007, overall credit market conditions have resulted in credit rating downgrades and may result in future credit rating downgrades for these insurers. The Company does not expect the impact on interest rates or fair value to be material.

	2007		2006
	Fair Value	Carrying Value	Fair Value	Carrying Value
Long-Term Debt	$4.8 billion	$4.7 billion	$5.0 billion	$4.8 billion

NOTE 13 — 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, 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 $1.1 billion through 2007. The Company estimates Detroit Edison future capital expenditures at up to $282 million in 2008 and up to $2.4 billion of additional capital expenditures through 2018 to satisfy both the existing and proposed new control requirements.

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Water– In response to an EPA regulation, Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of 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 $55 million over the four to six years subsequent to 2007 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 that may result in a delay in compliance dates. The decision also raised the possibility that Detroit Edison may have to install cooling towers at some facilities at a cost substantially greater than was initially estimated for other mitigative technologies.

Contaminated Sites- Detroit Edison conducted remedial investigations at contaminated sites, including three 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 $15 million that was accrued in 2007 and is expected to be incurred over the next several years. In addition, Detroit Edison expects to make approximately $6 million of capital improvements to the ash landfill in 2008.

Labor Contracts

There are several bargaining units for our represented employees. In December 2007, a new three-year agreement was ratified by our represented 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 $20 million at December 31, 2007 is being amortized to fuel, purchased power and gas expense with non-cash accretion expense being recorded through 2008. The Company estimates steam and electric purchase commitments from 2008 through 2024 will not exceed $343 million. In January 2003, the Company sold the steam heating business of Detroit Edison to Thermal Ventures II, LP. Under the terms of the sale, Detroit Edison remains contractually obligated to buy steam of $33 million from GDRRA until 2008. Also, the Company guaranteed bank loans of $13 million that Thermal Ventures II, LP may use for capital improvements to the steam heating system. During 2007, the Company recorded reserves of $13 million related to the bank loan guarantee.

As of December 31, 2007, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments and energy trading contracts. The Company estimates that these commitments will be approximately $1.4 billion from 2008 through 2024. The Company also estimates that 2008 capital expenditures will be approximately $1 billion. The Company has made certain commitments in connection with expected capital expenditures.

Bankruptcies

We purchase and sell electricity from and to numerous companies operating in the steel, automotive, energy, retail and other industries. Certain of our customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We regularly review contingent matters relating to these customers and our purchase and sale contracts and we record provisions for amounts considered at risk of

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probable loss. We believe our previously accrued amounts are adequate for probable losses. The final resolution of these matters is not expected to have a material effect on our consolidated financial statements.

Other

Detroit Edison was involved in a contract dispute with BNSF Railway Company (BNSF) that was referred to arbitration. Under this contract, BNSF transports western coals east for Detroit Edison. The Company filed a breach of contract claim against BNSF for the failure to provide certain services that the Company believed were required by the contract. The Company received an award from the arbitration panel in September 2007 that held that BNSF is required to provide such services under the contract and awarded damages to the Company. We have entered into a settlement agreement with BNSF pursuant to which BNSF will provide the required services.

We are aware of attempts by an environmental organization known as the Waterkeeper Alliance to initiate a criminal action in Canada against the Company for alleged violations of the Canadian Fisheries Act. Fines under the relevant Canadian statute could be significant. To date, the Company has not been served process in this matter and is not able to predict or assess the outcome of this action at this time.

We are involved in 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. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss. The resolution of pending proceedings is not expected to have a material effect on our operations or financial statements in the period they are resolved.

See Note 4 for a discussion of contingencies related to Regulatory Matters.

NOTE 14 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

Adoption of SFAS No. 158,Employers’ 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 No.158 requires companies to (1) recognize the over funded or under funded status of defined benefit pension and other postretirement plans in its financial statements, (2) recognize as a component of other comprehensive income, net of tax, the actuarial gains or losses and the prior service costs or credits that arise during the period but are not immediately recognized as components of net periodic benefit cost, (3) recognize adjustments to other comprehensive income when the actuarial gains or losses, prior service costs or credits, and transition assets or obligations are recognized as components of net periodic benefit cost, (4) measure postretirement benefit plan assets and plan obligations as of the date of the employer’s statement of financial position, and (5) disclose additional information in the notes to financial statements about certain effects on net periodic benefit cost in the upcoming fiscal year that arise from delayed recognition of the actuarial gains and losses and the prior service cost and credits.

The requirement to recognize the funded status of a postretirement benefit plan and the related disclosure requirements is effective for fiscal years ending after December 15, 2006. The Company adopted this requirement as of December 31, 2006. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. The Company plans to adopt this requirement as of December 31, 2008. Retrospective application of the changes required by SFAS No. 158 is prohibited; therefore certain disclosures below are not comparable.

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Detroit Edison received approval from the MPSC to record the charge related to the additional liability as a Regulatory asset since the traditional rate setting process allows for the recovery of pension and other postretirement plan costs.

Measurement Date

All amounts and balances reported in the following tables as of December 31, 2007 and December 31, 2006 are based on measurement dates of November 30, 2007 and November 30, 2006, respectively.

Qualified and Nonqualified Pension Plan Benefits

We have a defined benefit retirement plan. The plan is noncontributory and covers substantially all employees. The plan provides traditional retirement benefits based on the employees’ years of benefit service, average final compensation and age at retirement. In addition, certain non-represented employees are covered under cash balance provisions that base benefits on annual employer contributions and interest credits. We operate as the sponsor of the plan, which is treated as a plan covering employees of various affiliates of DTE Energy from the affiliates’ perspective. The annual expense disclosed below is our portion of the total plan expense. Each affiliate is charged their portion of the expense.

Our policy is to fund pension costs by contributing amounts consistent with the Pension Protection Act of 2006 provisions and additional amounts we deem appropriate. In December 2007, we contributed $150 million to the qualified pension plans. We anticipate making up to a $150 million contribution to our qualified pension plans in 2008 and a $5 million contribution to our nonqualified pension plans in 2008.

We also maintain supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees. These plans provide for benefits that supplement those provided by Detroit Edison’s other retirement plans.

Net pension cost includes the following components:

	Qualified Pension Plans									Nonqualified Pension Plans
(in Millions)	2007			2006			2005			2007		2006		2005
Service cost	$	49		$	49		$	53		$	2	$	2	$	1
Interest cost		135			133			130			3		3		2
Expected return on plan assets		(148	)		(135	)		(135	)		—		—		—
Amortization of:
Net income		44			44			50			2		1		1
Prior service cost		6			8			9			—		—		—
Special termination benefits		8			38			—			—		—		—
Net pension cost	$	94		$	137		$	107		$	7	$	6	$	4

Special termination benefits in the above tables represent costs associated with our Performance Excellence Process.

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Retrospective application of the changes required by SFAS No. 158 is prohibited; therefore certain disclosures below are not comparable.

	Qualified Pension Plans					Nonqualified Pension Plans
(in Millions)	2007			2006		2007			2006
Other changes in plan assets and benefit obligations recognized in regulatory assets
Net actuarial (gain)/ loss	$	(188	)	$	N/A	$	1		$	N/A
Amortization of net actuarial (gain)		(44	)		N/A		(1	)		N/A
Prior service cost		1			N/A		—			N/A
Amortization of prior service (credit)		(6	)		N/A		(1	)		N/A
Total recognized in regulatory assets	$	(237	)	$	N/A	$	(1	)	$	N/A
Total recognized in net periodic pension cost and regulatory assets	$	(143	)	$	N/A	$	6		$	N/A
Estimated amounts to be amortized from regulatory assets into net periodic benefit cost during next fiscal year
Net actuarial loss	$	26		$	44	$	1		$	1
Prior service cost	$	6		$	6	$	—		$	1

The above table represents disclosure required of SFAS No. 158 beginning in 2007.

The following table reconciles the obligations, assets and funded status of the plan as well as the amount recognized as pension liability in the consolidated statement of financial position at December 31. The results include liabilities and assets for Detroit Edison and all affiliates participating in the combined plan. The prepaid asset contributed to the combined plan by such affiliates is reflected as an amount due to affiliates of $325 million and $295 million at December 31, 2007 and 2006, respectively.

	Qualified Pension Plans						Nonqualified Pension Plans
	2007			2006			2007			2006
Accumulated benefit obligation, end of year	$	2,519		$	2,668		$	48		$	46
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	2,872		$	2,738		$	48		$	41
Service cost		53			55			2			2
Interest cost		159			156			3			3
Actuarial loss/ (gain)		(189	)		66			—			5
Benefits paid		(200	)		(180	)		(3	)		(3	)
Plan amendments		1			(6	)		—			—
Special termination benefits		8			43			—			—
Projected benefit obligation, end of year	$	2,704		$	2,872		$	50		$	48
Change in plan assets
Plan assets at fair value, beginning of year	$	2,373		$	2,273		$	—		$	—
Actual return on plan assets		246			280			—			—
Company contributions		180			—			3			3
Benefits paid		(200	)		(180	)		(3	)		(3	)

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	Qualified Pension Plans						Nonqualified Pension Plans
	2007			2006			2007			2006
Plan assets at fair value, end of year	$	2,599		$	2,373		$	—		$	—
Funded status of the plans, November 30	$	(105	)	$	(499	)	$	(50	)	$	(48	)
December contribution		150			180			—			—
Funded status, December 31	$	45		$	(319	)	$	(50	)	$	(48	)
Noncurrent assets	$	372		$	—		$	—		$	—
Current liabilities		—			—			(3	)		(3	)
Noncurrent liabilities		(327	)		(319	)		(47	)		(45	)
	$	45		$	(319	)	$	(50	)	$	(48	)
Amounts recognized in regulatory assets
Net actuarial loss	$	436		$	706		$	18		$	18
Prior service cost	$	14		$	20		$	1		$	2

Assumptions used in determining the projected benefit obligation and net pension costs are listed below:

	2007			2006			2005
Projected benefit obligation
Discount rate		6.50	%		5.70	%		5.90	%
Rate of compensation increase		4.00	%		4.00	%		4.00	%
Net pension costs
Discount rate		5.70	%		5.90	%		6.00	%
Rate of compensation increase		4.00	%		4.00	%		4.00	%
Expected long-term rate of return on Plan assets		8.75	%		8.75	%		9.00	%

At December 31, 2007, the benefits related to our qualified and nonqualified plans expected to be paid in each of the next five years and in the aggregate for the five fiscal years thereafter are as follows:

(in Millions)
2008	$	173
2009		178
2010		183
2011		187
2012		195
2013 - 2017		1,086
Total	$	2,002

We employ a consistent formal process in determining the long-term rate of return for various asset classes. We review historic financial market risks and returns and long-term historic relationships between the asset classes of equities, fixed income and other assets, consistent with the widely accepted capital market principle that asset classes with higher volatility generate a greater return over the long-term. Current market factors such as inflation, interest rates, asset class risks and asset class returns are evaluated and considered before long-term capital market assumptions are determined. The long-term portfolio return is also established employing a consistent formal process, with due consideration of diversification, active investment management and rebalancing. Peer data is reviewed to check for reasonableness.

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

Our plans’ weighted-average asset allocations by asset category at December 31 were as follows:

	2007			2006			Target
Equity securities		66	%		68	%		55	%
Debt securities		19			23			20
Other		15			9			25
		100	%		100	%		100	%

We also sponsor defined contribution retirement savings plans. Participation in one of these plans is available to substantially all represented and non-represented employees. We match employee contributions up to certain predefined limits based upon eligible compensation and the employee’s contribution rate. The cost of these plans was $17 million in 2007, $23 million in 2006, and $23 million in 2005.

Other Postretirement Benefits

We provide certain postretirement health care and life insurance benefits for employees who are eligible for these benefits. Our policy is to fund certain trusts to meet our postretirement benefit obligations. Separate qualified Voluntary Employees Beneficiary Association (VEBA) trusts exist for represented and non-represented employees. In 2007 and January 2008, we made cash contributions of $76 million and $40 million, respectively, to our postretirement benefit plans. At the discretion of management, we may make up to a $76 million contribution to our VEBA trusts in 2008. We recorded $2 million postretirement benefit cost associated with our Performance Excellence Process in 2007.

Net postretirement cost includes the following components:

(in Millions)	2007			2006			2005
Service cost	$	48		$	45		$	44
Interest cost		90			88			80
Expected return on plan assets		(54	)		(49	)		(58	)
Amortization of:
Net loss		51			53			44
Prior service costs		4			4			3
Net transition obligation		7			7			7
Special termination benefits		2			6			—
Net postretirement cost	$	148		$	154		$	120

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Special termination benefits in the above tables represent costs associated with our Performance
Excellence Process.

Retrospective application of the changes required by SFAS No. 158 is prohibited; therefore certain disclosures below are not comparable.

(in Millions)	2007			2006
Other changes in plan assets and APBO recognized in regulatory assets
Net actuarial (gain)	$	(216	)	$	N/A
Amortization of net actuarial (gain)		(51	)		N/A
Prior service (credit)		(39	)		N/A
Amortization of prior service cost		(4	)		N/A
Amortization of transition (asset)		(7	)		N/A
Total recognized in regulatory assets	$	(317	)	$	N/A
Total recognized in net periodic pension cost and regulatory assets	$	(169	)	$	N/A
Estimated amounts to be amortized from regulatory assets into net periodic benefit cost during next fiscal year
Net actuarial loss	$	27		$	50
Prior service cost	$	2		$	4
Net transition obligation	$	2		$	6

The above table represents disclosure required of SFAS No. 158 beginning in 2007.

The following table reconciles the obligations, assets and funded status of the plans including amounts recorded as accrued postretirement cost in the consolidated statement of financial position at December 31:

(in Millions)	2007			2006
Change in accumulated post retirement benefit obligation during the year
Accumulated postretirement benefit obligation, beginning of year	$	1,660		$	1,525
Service cost		48			45
Interest cost		90			88
Plan amendments		(39	)		2
Actuarial (gain)/ loss		(214	)		63
Benefits paid		(73	)		(70	)
Special termination benefits		2			6
Medicare Part D		5			1
Accumulated postretirement benefit obligation , end of year	$	1,479		$	1,660
Change in plan assets during the year
Plan assets at fair value, beginning of year	$	636		$	581
Actual return on plan assets		56			70
Company contributions		36			40
Benefits paid		(70	)		(55	)
Plan assets at fair value, end of year	$	658		$	636

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(in Millions)	2007			2006
Funded status of the Plans, as of November 30	$	(821	)	$	(1,024	)
December adjustment		5			(31	)
Funded status, as of December 31	$	(816	)	$	(1,055	)
Non-current liabilities	$	(816	)	$	(1,055	)
Amounts Recognized in Regulatory Assets
Net actuarial loss	$	391		$	659
Prior service cost	$	3		$	24
Net transition obligation	$	11		$	40

Assumptions used in determining the projected benefit obligation and net benefit costs are listed below:

	2007			2006			2005
Projected Benefit Obligation
Discount rate		6.50	%		5.70	%		5.90	%
Net Benefit Costs
Discount rate		5.70	%		5.90	%		6.00	%
Expected long-term rate of return on Plan assets		8.75	%		8.75	%		9.00	%
Health care trend rate pre-65		8.00	%		9.00	%		9.00	%
Health care trend rate post-65		7.00	%		8.00	%		8.00	%
Ultimate health care trend rate		5.00	%		5.00	%		5.00	%
Year in which ultimate reached		2011			2011			2011

A one-percentage-point increase in health care cost trend rates would have increased the total service cost and interest cost components of benefit costs by $22 million and increased the accumulated benefit obligation by $183 million at December 31, 2007. A one-percentage-point decrease in the health care cost trend rates would have decreased the total service and interest cost components of benefit costs by $18 million and would have decreased the accumulated benefit obligation by $156 million at December 31, 2007.

At December 31, 2007, the benefits expected to be paid, including prescription drug benefits, in each of the next five years and in the aggregate for the five fiscal years thereafter are as follows:

(in Millions)
2008	$	91
2009		98
2010		103
2011		107
2012		111
2013 - 2017		599
Total	$	1,109

The process used in determining the long-term rate of return for assets and the investment approach for our other postretirement benefits plans is similar to those previously described for our qualified pension plans.

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Our plans’ weighted-average asset allocations and related targets by asset category at December 31 were as follows:

	2007			2006			Target
Equity securities		68	%		68	%		55	%
Debt securities		20			25			20
Other		12			7			25
		100	%		100	%		100	%

In December 2003, the Medicare Act was signed into law which provides for a non-taxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least “actuarially equivalent” to the benefit established by law. The effects of the subsidy reduced net periodic postretirement benefit costs by $12 million in 2007, $16 million in 2006 and $15 million in 2005.

At December 31, 2007, the gross amount of federal subsidies expected to be received in each of the next five years and in the aggregate for the five fiscal years thereafter was as follows:

(in Millions)
2008	$	4
2009		4
2010		4
2011		4
2012		5
2013 - 2017		26
Total	$	47

NOTE 15 — RELATED PARTY TRANSACTIONS

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

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The following is a summary of transactions with affiliated companies:

(in Millions)	2007		2006			2005
Revenues
Energy sales	$	—	$	46		$	192
Other services		5		5			5
Shared capital assets		21		13			14
Costs
Power purchases		3		35			102
Other services and interest		6		3			7
Corporate expenses (net)		331		(86	)		(97	)
Other
Dividends declared		305		305			305
Dividends paid		305		305			305
Capital contribution		175		150			—

	December 31,
(in Millions)	2007		2006
Assets
Accounts receivable	$	3	$	19
Liabilities & Equity
Accounts payable		138		84
Short-term borrowings		277		—
Other liabilities ( pension obligations)		327		295
Dividends payable		76		76

Our accounts receivable from affiliated companies and accounts payable to affiliated companies are payable upon demand and are generally settled in cash within a monthly business cycle.

NOTE 16 — SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

	First		Second		Third		Fourth
(in Millions)	Quarter		Quarter		Quarter		Quarter(1)		Year
2007
Operating Revenues	$	1,094	$	1,210	$	1,403	$	1,193	$	4,900
Operating Income		131		162		227		223		743
Net Income		40		60		107		110		317
2006
Operating Revenues		1,050		1,175		1,460		1,052		4,737
Operating Income		161		164		270		181		776
Net Income		59		57		138		67		321

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(1) In the fourth quarter of 2007, Detroit Edison recorded adjustments that increased operating income by $27 million ($18 million after-tax) to correct prior amounts. These adjustments were primarily to record property, plant and equipment and deferred CTA costs for expenditures that had been expensed in earlier quarters of 2007, including $14 million ($9 million after-tax) expensed in the second quarter of 2007.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.   Controls and Procedures

See Item 8. Financial Statements and Supplementary Data for management’s evaluation of disclosure controls and procedures, its report on internal control over financial reporting, and its conclusion on changes in internal control over financial reporting.

Item 9B.   Other Information

None.

Part III

Item 10. Directors, Executive Officers and Corporate Governance

Item 11. Executive Compensation

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13. Certain Relationships and Related Transactions, and Director Independence

All omitted per General Instruction I (2) (c) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Item 14. Principal Accountant Fees and Services

For the years ended December 31, 2007 and 2006, professional services were performed by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, “Deloitte”). The following table presents fees for professional services rendered by Deloitte for the audit of Detroit Edison’s annual financial statements for the years ended December 31, 2007 and December 31, 2006, and fees billed for other services rendered by Deloitte during those periods.

	2007		2006
Audit fees (1)	$	1,275,216	$	1,652,619
Audit-related fees (2)(3)		6,179		35,750
Total	$	1,281,395	$	1,688,369

(1) Represents the aggregrate fees for the audits of Detroit Edison’s annual financial statements

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	and for the reviews of the financial statements included in Detroit Edison’s Quarterly Reports on Form 10-Q. 2006 fees include procedures performed to audit internal control over financial reporting of consolidated DTE Energy. Such fees in 2007 were incurred by DTE Energy and indirectly allocated to Detroit Edison through overheads.
(2)	Represents the aggregrate fees billed for audit-related services. The fees above exclude certain fees charged to DTE Energy that are indirectly allocated to Detroit Edison through overheads.

The above listed fees were pre-approved by the DTE Energy audit committee. Prior to engagement, the DTE Energy audit committee pre-approves these services by category of service. The DTE Energy audit committee may delegate to the chair of the audit committee, or to one or more other designated members of the audit committee, the authority to grant pre-approvals of all permitted services or classes of these permitted services to be provided by the independent auditor up to but not exceeding a pre-defined limit. The decision of the designated member to pre-approve a permitted service will be reported to the DTE Energy audit committee at the next scheduled meeting.

Part IV

Item 15. Exhibits and Financial Statement Schedules

(a) The following documents are filed as part of this Annual Report on Form 10-K.

(1)	Consolidated financial statements. See “Item 8 – Financial Statements and Supplementary Data.”
(2)	Financial statement schedule. See “Item 8 – Financial Statements and Supplementary Data.”
(3)	Exhibits.

(i) Exhibits filed herewith.

12-28	Computation of Ratio of Earnings to Fixed Charges.
23-20	Consent of Deloitte & Touche LLP.
31-37	Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report.
31-38	Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report.

(ii) Exhibits incorporated herein by reference.

3(a)	Restated Articles of Incorporation of The Detroit Edison Company, as filed December 10, 1991. (Exhibit 3-13 to Form 10-Q for the quarter ended June 30, 1999)
3(b)	Bylaws of The Detroit Edison Company, as amended through September 22, 1999. (Exhibit 3-14 to Form 10-Q for the quarter ended September 30, 1999)
4(a)	Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit B-1 to Registration Statement on Form A-2 (File No. 2-1630)) and indentures supplemental thereto, dated as of dates indicated

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below, and filed as exhibits to the filings set forth below:

Supplemental Indenture, dated as of December 1, 1940, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit B-14 to Registration Statement on Form A-2 (File No. 2-4609)). (amendment)

Supplemental Indenture, dated as of September 1, 1947, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit B-20 to Registration Statement on Form S-1 (File No. 2-7136)). (amendment)

Supplemental Indenture, dated as of March 1, 1950, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit B-22 to Registration Statement on Form S-1 (File No. 2-8290)). (amendment)

Supplemental Indenture, dated as of November 15, 1951, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit B-23 to Registration Statement on Form S-1 (File No. 2-9226)). (amendment)

Supplemental Indenture, dated as of August 15, 1957, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 3-B-30 to Form 8-K dated September 11, 1957). (amendment)

Supplemental Indenture, dated as of December 1, 1966, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 2-B-32 to Registration Statement on Form S-9 (File No. 2-25664)). (amendment)

Supplemental Indenture, dated as of February 15, 1990, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-212 to Form 10-K for the year ended December 31, 2000). (1990 Series B, C, E and F)

Supplemental Indenture, dated as of April 1, 1991, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-15 to Form 10-K for the year ended December 31, 1995). (1991 Series AP)

Supplemental Indenture, dated as of May 1, 1991, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee

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(Exhibit 4-178 to Form 10-K for the year ended December 31, 1996). (1991 Series BP and CP)

Supplemental Indenture, dated as of May 15, 1991, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-179 to Form 10-K for the year ended December 31, 1996). (1991 Series DP)

Supplemental Indenture, dated as of February 29, 1992, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-187 to Form 10-Q for the quarter ended March 31, 1998). (1992 Series AP)

Supplemental Indenture, dated as of April 26, 1993, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-215 to Form 10-K for the year ended December 31, 2000). (amendment)

Supplemental Indenture, dated as of June 30, 1993, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-216 to Form 10-K for the year ended December 31, 2000). (1993 Series AP)

Supplemental Indenture, dated as of August 1, 1999, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-204 to Form 10-Q for the quarter ended September 30, 1999). (1999 Series AP, BP and CP)

Supplemental Indenture, dated as of August 1, 2000, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-210 to Form 10-Q for the quarter ended September 30, 2000). (2000 Series BP)

Supplemental Indenture, dated as of March 15, 2001, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-222 to Form 10-Q for the quarter ended March 31, 2001). (2001 Series AP)

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

Supplemental Indenture, dated as of August 15, 2001, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and

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J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-227 to Form 10-Q for the quarter ended September 30, 2001). (2001 Series CP)

Supplemental Indenture, dated as of September 15, 2001, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-228 to Form 10-Q for the quarter ended September 30, 2001). (2001 Series D and E)

Supplemental Indenture, dated as of September 17, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4.1 to Registration Statement on Form S-3 (File No. 333-100000)). (amendment and successor trustee)

Supplemental Indenture, dated as of October 15, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-230 to Form 10-Q for the quarter ended September 30, 2002). (2002 Series A and B)

Supplemental Indenture, dated as of December 1, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-232 to Form 10-K for the year ended December 31, 2002). (2002 Series C and D)

Supplemental Indenture, dated as of August 1, 2003, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-235 to Form 10-Q for the quarter ended September 30, 2003). (2003 Series A)

Supplemental Indenture, dated as of March 15, 2004, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-238 to Form 10-Q for the quarter ended March 31, 2004). (2004 Series A and B)

Supplemental Indenture, dated as of July 1, 2004, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-240 to Form 10-Q for the quarter ended June 30, 2004). (2004 Series D)

Supplemental Indenture, dated as of April 1, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between Detroit Edison and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4.3 to Registration Statement on Form S-4 (File No. 333-123926)). (2005 Series AR and BR)

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	Supplemental Indenture, dated as of August 1, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4.2 to Form 8-K dated August 17, 2005). (2005 Series DT)
	Supplemental Indenture, dated as of September 15, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4.2 to Form 8-K dated September 29, 2005). (2005 Series C)
	Supplemental Indenture, dated as of September 30, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between Detroit Edison and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-248 to Form 10-Q for the quarter ended September 30, 2005). (2005 Series E)
	Supplemental Indenture, dated as of May 15, 2006, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-250 to Form 10-Q for the quarter ended June 30, 2006). (2006 Series A)
	Supplemental Indenture, dated as of December 1, 2006, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4.2 to Form 8-K dated December 8, 2006). (2006 Series CT)
	Supplemental Indenture, dated as of December 1, 2007, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4.2 to Form 8-K dated December 18, 2007). (2007 Series A)
4(b)	Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-152 to Registration Statement (File No. 33-50325)).
4(c)	Ninth Supplemental Indenture, dated as of October 10, 2001, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-229 to Form 10-Q for the quarter ended September 30, 2001). (5.050% Senior Notes due 2005 and 6.125% Senior Notes due 2010)
4(d)	Tenth Supplemental Indenture, dated as of October 23, 2002, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-231 to Form 10-Q for the quarter ended September 30, 2002). (5.20% Senior Notes due 2012 and 6.35% Senior Notes due 2032)
4(e)	Eleventh Supplemental Indenture, dated as of December 1, 2002, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-233 to Form 10-Q for the quarter ended March 31,

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	2003). (5.45% Senior Notes due 2032 and 5.25% Senior Notes due 2032)
4(f)	Twelfth Supplemental Indenture, dated as of August 1, 2003, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-236 to Form 10-Q for the quarter ended September 30, 2003). (5 1/2% Senior Notes due 2030)
4(g)	Thirteenth Supplemental Indenture, dated as of April 1, 2004, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-237 to Form 10-Q for the quarter ended March 31, 2004). (4.875% Senior Notes Due 2029 and 4.65% Senior Notes due 2028)
4(h)	Fourteenth Supplemental Indenture, dated as of July 15, 2004, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-239 to Form 10-Q for the quarter ended June 30, 2004). (2004 Series D 5.40% Senior Notes due 2014)
4(i)	Sixteenth Supplemental Indenture, dated as of April 1, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4.1 to Registration Statement on Form S-4 (File No. 333-123926)). (2005 Series AR 4.80% Senior Notes due 2015 and 2005 Series BR 5.45% Senior Notes due 2035)
4(j)	Seventeenth Supplemental Indenture, dated as of August 1, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4.1 to Form 8-K dated August 17, 2005). (2005 Series DT Variable Rate Senior Notes due 2029)
4(k)	Eighteenth Supplemental Indenture, dated as of September 15, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4.1 to Form 8-K dated September 29, 2005). (2005 Series C 5.19% Senior Notes due October 1, 2023)
4(l)	Nineteenth Supplemental Indenture, dated as of September 30, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-247 to Form 10-Q for the quarter ended September 30, 2005). (2005 Series E 5.70% Senior Notes due 2037)
4(m)	Twentieth Supplemental Indenture, dated as of May 15, 2006, to the Collateral Trust Indenture dated as of June 30, 1993, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee (Exhibit 4-249 to Form 10-Q for the quarter ended June 30, 2006). (2006 Series A Senior Notes due 2036)

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4(n)	Twenty-First Supplemental Indenture, dated as of December 1, 2006, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Trust Company, N.A., as successor trustee (Exhibit 4.1 to Form 8-K dated December 8, 2006). (2006 Series CT Variable Rate Senior Notes due 2036)
4(o)	Twenty-Second Supplemental Indenture, dated as of December 1, 2007, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Trust Company, N.A., as successor trustee (Exhibit 4.1 to Form 8-K dated December 18, 2007). (2007 Series A Senior Notes due 2038)
4(p)	Trust Agreement of Detroit Edison Trust I. (Exhibit 4.9 to Registration Statement on Form S-3 (File No. 333-100000))
4(q)	Trust Agreement of Detroit Edison Trust II. (Exhibit 4.10 to Registration Statement on Form S-3 (File No. 333-100000))
10(a)	Securitization Property Sales Agreement dated as of March 9, 2001, between The Detroit Edison Securitization Funding LLC and The Detroit Edison Company. (Exhibit 10-42 to Form 10-Q for the quarter ended March 31, 2001)
10(b)	Form of The Detroit Edison Company’s Five-Year Credit Agreement, dated as of October 17, 2005, by and among The Detroit Edison Company, the lenders party thereto, Barclays Bank PLC, as Administrative Agent, and Citibank, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.1 to Form 8-K dated October 17, 2005).
10(c)	Form of Amendment No.1 to The Detroit Edison Company’s Five-Year Credit Agreement, dated as of January 10, 2007, by and among The Detroit Edison Company, the lenders party thereto, Barclays Bank PLC, as Administrative Agent, and Citibank, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.1 to Form 8-K dated January 10, 2007).
10(d)	Form of Second Amended and Restated Five-Year Credit Agreement, dated as of October 17, 2005, by and among The Detroit Edison Company, the lenders party thereto, Barclays Bank PLC, as Administrative Agent, and Citibank, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.2 to Form 8-K dated October 17, 2005)
10(e)	Form of Amendment No. 1. to Second Amended and Restated Five-Year Credit Agreement dated as of January 10, 2007, by and among The Detroit Edison Company, the lenders party thereto, Barclays Bank PLC, as Administrative Agent, and Citibank, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.2 to Form 8-K dated January 10, 2007).
10(f)	Certain arrangements pertaining to the employment of Anthony F. Earley, Jr. with The Detroit Edison Company, dated April 25, 1994. (Exhibit 10-53 to Form 10-Q for the quarter ended March 31, 1994)

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

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	as amended (Exhibit 99-18 to Form 10-K dated December 31, 2004)
10(s)	Amendment No. 5 dated as of January 18, 2007 to the Amended and Restated Trade Receivables Purchase and Sale Agreement among Detroit Edison, CAFCO, Citibank and Citicorp, individually and as Agent dated March 9, 2001, as amended (Exhibit 10-42 to Form 10-K for the year ended December 31, 2006)
10(t)	Amendment No. 6 dated as of January 18, 2007 to the Amended and Restated Trade Receivables Purchase and Sale Agreement among Detroit Edison, CAFCO, Citibank and Citicorp, individually and as Agent dated March 9, 2001, as amended (Exhibit 10-01 to Form 8-K dated January 18, 2007)
10(u)	Amendment No. 7 dated as of January 17, 2008 to the Amended and Restated Trade Receivables Purchase and Sale Agreement among Detroit Edison, CAFCO, Citibank and Citicorp, individually and as Agent dated March 9, 2001, as amended. (Exhibit 10-1 to Form 8-K dated January 17, 2008)
99(a)	Belle River Participation Agreement, dated as of December 1, 1982, between The Detroit Edison Company and Michigan Public Power Agency. (Exhibit 28-5 to Registration Statement No. 2-81501)
99(b)	Belle River Transmission Ownership and Operating Agreement, dated as of December 1, 1982, between The Detroit Edison Company and Michigan Public Power Agency. (Exhibit 28-6 to Registration Statement No. 2-81501)
99(c)	Inter-Creditor Agreement, dated as of March 9, 2001, among Citicorp North America, Inc., Citibank, N.A., The Bank of New York, The Detroit Edison Securitization Funding LLC and The Detroit Edison Company. (Exhibit 99-41 to Form 10-Q for the quarter ended March 31, 2001)

(iii) Exhibits furnished herewith.

32-37	Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report.
32-38	Chief Financial Officer Section 906 Form 10-K Certification of Periodic Report.

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The Detroit Edison Company

Schedule II – Valuation and Qualifying Accounts

	Year Ended December 31
(in Millions)	2007			2006			2005
Allowance for Doubtful Accounts (shown as deduction from accounts receivable in the consolidated statements of financial position)
Balance at Beginning of Period	$	72		$	54		$	55
Additions:
Charged to costs and expenses		63			53			41
Charged to other accounts (1)		4			3			4
Deductions (2)		(46	)		(38	)		(46	)
Balance At End of Period	$	93		$	72		$	54

(1)	Collection of accounts previously written off.
(2)	Non-collectible accounts written off.

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Signatures

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

		THE DETROIT EDISON COMPANY (Registrant)
Date: March 17, 2008	By	/s/ PETER B. OLEKSIAK
		Peter B. Oleksiak
		Vice President and Controller, and
		Chief Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

By	/s/ ANTHONY F. EARLEY, JR.	By	/s/ PETER B. OLEKSIAK
	Anthony F. Earley, Jr.		Peter B. Oleksiak
	Chairman of the Board and		Vice President and Controller, and
	Chief Executive Officer		Chief Accounting Officer
By	/s/ SANDRA KAY ENNIS	By	/s/ DAVID E. MEADOR
	Sandra Kay Ennis		David E. Meador
	Director and Corporate Secretary		Director, Executive Vice President
			and Chief Financial Officer
By
	Bruce D. Peterson
	Director
Date: March 17, 2008

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