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THE DETROIT EDISON COMPANY

(Registrant)

Date: March 1, 2007

/s/ PETER B. OLEKSIAK

Peter B. Oleksiak
Vice President and Controller, and
Chief Accounting Officer

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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


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


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

For the fiscal year ended December 31, 2006

Commission file number 1-2198

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 (State or other jurisdiction of incorporation or organization)		38-0478650 (I.R.S. Employer Identification No.)

2000 2^nd Avenue, Detroit, Michigan (Address of principal executive offices)		48226-1279 (Zip Code)

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

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

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

Definitions


Customer Choice		Statewide initiatives giving customers in Michigan the option to choose alternative suppliers for electricity.

CTA		Costs to achieve, consisting of project management, consultant support and employee severance, related to the Performance Excellence Process

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. The power supply cost recovery mechanism was suspended under Michigan’s restructuring legislation (signed into law June 5, 2000), which lowered and froze electric customer rates and was reinstated by the MPSC effective January 1, 2004.

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

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 contemplated, projected, estimated or budgeted. There are many factors that may impact forward-looking statements including, but not limited to, the following:

•		the effects of weather and other natural phenomena on operations and sales to customers, and purchases from suppliers;

•		economic climate and population growth or decline in the geographic areas where we do business;

•		environmental issues, laws and regulations, and the cost of remediation and compliance;

•		nuclear regulations and operations associated with nuclear facilities;

•		implementation of the electric Customer Choice program;

•		impact of electric utility restructuring in Michigan, including legislative amendments;

•		employee relations and the impact of collective bargaining agreements;

•		unplanned outages;

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

•		the timing and extent of changes in interest rates;

•		the level of borrowing;

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

•		effects of competition;

•		impact of regulation by FERC, MPSC, NRC and other applicable governmental proceedings and regulations, including any associated impact on rate structures;

•		changes in and application of federal, state and local tax laws and their interpretations, including the Internal Revenue Code, regulations, rulings, court proceedings and audits;

•		the ability to recover costs through rate increases;

•		the availability, cost, coverage and terms of insurance;

•		the cost of protecting assets against, or damage due to, terrorism;

•		changes in and application of accounting standards and financial reporting regulations;

•		changes in federal or state laws and their interpretation with respect to regulation, energy policy and other business issues;

•		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.

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

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

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

Revenue by Service


(in Millions)	2006		2005		2004
Residential	$	1,671	$	1,517	$	1,345
Commercial		1,603		1,331		1,123
Industrial		835		697		557
Wholesale		109		73		65
Other		350		464		234

Subtotal		4,568		4,082		3,324
Interconnection sales (1)		169		380		244

Total Revenue	$	4,737	$	4,462	$	3,568


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

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

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

Fuel Supply and Purchased Power

Our power is generated from a variety of fuels and is supplemented with purchased power. We expect to have an adequate supply of fuel and purchased power to meet our obligation to serve customers. Our generating capability is heavily dependent upon the availability of coal. Coal is purchased from various sources in different geographic areas under agreements that vary in both pricing and terms. We expect to obtain the majority of our coal requirements through long-term contracts with the balance to be obtained through short-term agreements and spot purchases. We have six long-term and two short-term contracts for a total purchase of approximately 35 million tons of low-sulfur western coal to be delivered from 2007 to 2010. We also have ten

contracts for the purchase of approximately 8 million tons of Appalachian coal to be delivered from 2007 through 2009. All of these contracts have fixed prices. We have approximately 90% of our 2007 expected coal requirements under contract. Given the geographic diversity of supply, we believe we can meet our expected generation requirements. We lease a fleet of rail cars and have long-term transportation contracts with companies to provide rail and vessel services for delivery of purchased coal to our generating facilities.

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

Properties

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

Generating plants owned and in service as of December 31, 2006 are as follows:


	Location by	Summer Net
	Michigan	Rated Capability (1) (2)
Plant Name	County	(MW)		(%)		Year in Service
Fossil-fueled Steam-Electric
Belle River (3)	St. Clair		1,026		9.2	1984 and 1985
Conners Creek	Wayne		215		1.9	1951
Greenwood	St. Clair		785		7.1	1979
Harbor Beach	Huron		103		0.9	1968
Marysville	St. Clair		84		0.8	1943 and 1947
Monroe (4)	Monroe		3,115		28.0	1971, 1973 and 1974
River Rouge	Wayne		510		4.6	1957 and 1958
St. Clair	St. Clair		1,415		12.7	1953, 1954, 1959, 1961 and 1969
Trenton Channel	Wayne		730		6.6	1949 and 1968

			7,983		71.8
Oil or Gas-fueled Peaking Units	Various		1,102		9.9	1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric
Fermi 2 (5)	Monroe		1,111		10.0	1988
Hydroelectric Pumped Storage
Ludington (6)	Mason		917		8.3	1973

			11,113		100.0


(1)		Summer net rated capabilities of generating plants in service are based on periodic load tests and are changed depending on operating experience, the physical condition of units, environmental control limitations and customer requirements for steam, which otherwise would be used for electric generation.

(2)		Excludes one oil-fueled unit, St. Clair Unit No. 5 (250 MW), in cold standby status.

(3)		The Belle River capability represents Detroit Edison’s entitlement to 81.39% of the capacity and energy of the plant. See Note 6.

(4)		The Monroe Power Plant provided 38% of Detroit Edison’s total 2006 power plant generation.

(5)		Fermi 2 has a design electrical rating (net) of 1,150 MW.

(6)		Represents Detroit Edison’s 49% interest in Ludington with a total capability of 1,872 MW. See Note 6.

Detroit Edison owns and operates 675 distribution substations with a capacity of approximately 33,075,000 kilovolt-amperes (kVA) and approximately 426,700 line transformers with a capacity of approximately 25,883,000 kVA.

Circuit miles of distribution lines owned and in service as of December 31, 2006 are as follows:

Electric Distribution


	Circuit Miles
Operating Voltage-Kilovolts (kV)	Overhead		Underground
4.8 kV to 13.2 kV		28,155		13,747
24 kV		101		690
40 kV		2,323		332
120 kV		70		13

		30,649		14,782

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

Regulation

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

Since 1996, there have been several important acts, orders, court rulings and legislative actions in the State of Michigan that affect Detroit Edison’s operations. In 1996, the MPSC began an initiative designed to give all of Michigan’s electric customers access to electricity supplied by other generators and marketers. In 1998, the MPSC authorized the electric Customer Choice program that allowed for a limited number of customers to purchase electricity from suppliers other than their local utility. The local utility continues to transport the electric supply to the customers’ facilities, thereby retaining distribution margins. The electric Customer Choice program was phased in over a three-year period, with all customers having the option to choose their electric supplier by January 2002.

In 2000, the Michigan Legislature enacted legislation that reduced electric rates by 5% and reaffirmed January 2002 as the date for full implementation of the electric Customer Choice program. This legislation also contained provisions freezing rates through 2003 and preventing rate increases for small business customers through 2004 and for residential customers through 2005. The legislation and an MPSC order issued in 2001 established a methodology to enable Detroit Edison to recover stranded costs related to its generation operations that may not otherwise be recoverable due to electric Customer Choice related lost sales and margins. The legislation also provides for the recovery of the costs associated with the implementation of the electric Customer Choice program. The MPSC has determined that these costs will be treated as regulatory assets. Additionally, the legislation provides for recovery of costs incurred as a result of changes in taxes, laws and other governmental actions including the Clean Air Act.

In 2004, the MPSC issued interim and final rate orders that authorized electric rate increases totaling $374 million, and eliminated transition credits and implemented transition charges for electric Customer Choice customers. The increases were applicable to all customers not subject to a rate cap. The interim order affirmed the resumption of the PSCR mechanism for both capped and uncapped customers, which reduced PSCR revenues. The MPSC also authorized the recovery of approximately $385 million in regulatory assets, including stranded costs. As part of the final order Detroit Edison was ordered to file an application to restructure its electric rates.

In February 2005, Detroit Edison filed a rate restructuring proposal with the MPSC to restructure its electric rates and begin phasing out subsidies within the current pricing structure. In December 2005, the MPSC issued an order that provided for initial steps to improve the current competitive imbalance in Michigan’s electric Customer Choice program. The December 2005 order establishes cost-based power supply rates for Detroit Edison’s full service customers. Electric Customer Choice participants will pay cost-based distribution rates while Detroit Edison’s full service commercial and industrial customers will pay cost-based distribution rates that reflect the cost of the residential rate subsidy. Residential customers continue to pay a subsidized below cost rate for distribution service. These revenue neutral revised rates were effective February 1, 2006. Detroit Edison was also ordered to file a general rate case no later than July 1, 2007, based on 2006 actual results.

In March 2006, the MPSC issued an order directing Detroit Edison to show cause by June 1, 2006 why its retail electric rates should not be reduced in 2007. The MPSC cited certain changes that had occurred since the November 2004 order in Detroit Edison’s last general rate case, or were expected to occur. These changes included: declines in electric Customer Choice program participation, expiration of the residential rate caps, and projected reductions in Detroit Edison operating costs. The show cause filing was to reflect sales, costs and financial conditions that were expected to occur by 2007. On June 1, 2006, Detroit Edison filed its response explaining why its electric rates should not be reduced in 2007. Detroit Edison indicated that it will have a revenue deficiency of approximately $45 million beginning in 2007 due to significant capital investments over the next several years for infrastructure improvements to enhance electric service reliability and for mandated environmental expenditures. The impacts of these investments will be partially offset by efficiency and cost-savings measures that have been initiated. Therefore, Detroit Edison requested that the show cause proceeding allow for rate increase adjustments based on the combined effects of investment expenditures and cost-savings programs. The MPSC denied this request and indicated that a full review of rates will be made in Detroit Edison’s next general rate case, which is due to be filed by July 1, 2007. The MPSC issued an order approving a settlement agreement in this proceeding on August 31, 2006. The order provided for an annualized rate reduction of $53 million for 2006, effective September 5, 2006. Beginning January 1, 2007, and continuing until the later of March 31, 2008 or 12 months from the filing date of Detroit Edison’s next main case, rates will be reduced by an additional $26 million, for a total reduction of $79 million. The revenue reduction is net of the recovery of the amortization of the costs associated with the implementation of the Performance Excellence Process, a company wide review of our operations. The settlement agreement provides for some level of realignment of the existing rate structure by allocating a larger percentage share of the rate reduction to the commercial and industrial customer classes than to the residential customer classes. As part of the settlement agreement, a Choice Incentive Mechanism (CIM) was established with a base level of electric choice sales set at 3,400 GWh.

In accordance with the MPSC’s directive in Detroit Edison’s November 2004 rate order, in March 2005, Detroit Edison filed a joint application and testimony in its 2004 PSCR Reconciliation Case and its 2004 Net Stranded Cost Recovery Case. In September 2006, the MPSC issued an order recognizing $19 million of 2004 net stranded costs that required Detroit Edison to write off $112 million of 2004 net stranded costs. The MPSC order resulted in a $39 million reduction in the 2004 PSCR over-collection by allowing Detroit Edison to retain the benefit of third party wholesale sales required to support the electric Customer Choice program and to offset the recognition of the $19 million of 2004 stranded costs. The MPSC order also resulted in reductions to accrued interest on the 2004 and 2005 PSCR amounts of $15 million. The MPSC directed Detroit Edison to include the remaining 2004 PSCR over-collection amount and related interest in the 2005 PSCR Reconciliation which is in an under-collected position. The order resulted in a reduction of pre-tax income of approximately $58 million.

See Note 4 of the Notes to Consolidated Financial Statements.

Energy Assistance Programs

Energy assistance programs, funded by the federal government and the State of Michigan, remain critical to Detroit Edison’s ability to control its uncollectible accounts receivable and collections expenses. Detroit Edison’s uncollectible accounts receivable expense is directly affected by the level of government funded

assistance its qualifying customers receive. We work continuously with the State of Michigan and others to determine whether the share of funding allocated to our customers is representative of the number of low-income individuals in our service territory.

Strategy and Competition

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

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

Effective January 2002, the electric Customer Choice program expanded in Michigan so that all of the Company’s electric customers can choose to purchase their electricity from alternative electric suppliers of generation services. Detroit Edison lost 6% of retail sales in 2006, 12% in 2005 and 18% of such sales in 2004 as a result of customers choosing to purchase power from alternative electric suppliers. Customers participating in the electric Customer Choice program consist primarily of industrial and commercial customers whose MPSC-authorized full service rates exceed their cost of service. Customers who elect to purchase their electricity from alternative electric suppliers by participating in the electric Customer Choice program have an unfavorable effect on our financial performance. The effect of lost sales due to the electric Customer Choice program has reduced our need for purchased power and when market conditions are favorable we sell power into the wholesale market, in order to lower costs to full service customers.

Detroit Edison acquires transmission services from ITC Transmission. By FERC order, rates charged by ITC Transmission to Detroit Edison were frozen through December 2004. Thereafter, rates became subject to normal FERC regulation. With the MPSC’s November 2004 final rate order, transmission costs are recoverable through Detroit Edison’s PSCR mechanism.

We are currently involved in a contract dispute with BNSF Railway Company that has been referred to arbitration. Under this contract, BNSF transports western coal east for Detroit Edison. We have filed a breach of contract claim against BNSF for the failure to provide certain services that we believe are required by the contract. The arbitration hearing is scheduled for mid-2007. While we believe we will prevail on the merits in this matter, a negative decision with respect to the significant issues being heard in the arbitration could have an adverse effect on our business.

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

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 summarizes our expected significant environmental expenditures:


( in Millions)
Air	$	2,185
Water		53
Other Clean Up Sites		12
MGP Sites		4

Estimated total future expenditures	$	2,254

Estimated 2007 expenditures	$	234

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

Water – In response to an EPA regulation, currently under judicial review, Detroit Edison may be required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of the studies to be conducted over the next several years, Detroit Edison may be required to install additional control technologies to reduce the impacts of the intakes. However, a recent court decision remanded back to the EPA several provisions of the federal regulation which may result in a delay in compliance requirements. The court decision also raised the possibility that the Company may have to install cooling towers at some facilities. We cannot predict the effect on Detroit Edison of this court decision or any resulting regulations.

Contaminated Sites - We conducted remedial investigations at contaminated sites, including two 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 expected to be incurred over the next several years. In addition, we will be making capital improvements to the ash landfill in 2007.

Greater details on environmental issues are provided in the following Notes to Consolidated Financial Statements:


Note		Title

4		Regulatory Matters
5		Nuclear Operations
13		Commitments and Contingencies

EMPLOYEES

We had 7,217 employees as of December 31, 2006, of which 3,724 were represented by unions. Approximately 3,239 of our represented employees are under contracts that expire in June 2007. The contract of the remaining represented employees expires in 2008.

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.

Michigan’s electric Customer Choice program is negatively impacting our financial performance. The electric Customer Choice program, as originally contemplated in Michigan, anticipated an eventual transition to a totally deregulated and competitive environment where customers would be charged market-based rates for their electricity. The State of Michigan currently experiences a hybrid market, where the MPSC continues to regulate electric rates for our customers, while alternative electric suppliers charge market-based rates. In addition, such regulated electric rates for certain groups of our customers exceed the cost of service to those customers. Due to distorted pricing mechanisms, during the initial implementation period of electric Customer Choice many commercial customers chose alternative electric suppliers. Recent MPSC rate orders have removed some of the pricing disparity. Recent higher wholesale electric prices have also resulted in some former electric Customer Choice customers migrating back to Detroit Edison for electric generation service. Even with the electric Customer Choice-related rate relief received in Detroit Edison’s 2004 and 2005 rate 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 our operations. Deviations from normal hot and cold weather conditions affect our earnings and cash flow. Mild temperatures can result in decreased utilization of our assets, lowering income and cash flow. Damage due to ice storms, tornadoes, or high winds can damage our infrastructure and require us to perform emergency repairs and incur material unplanned expenses. The expenses of storm restoration efforts may not be recoverable through the regulatory process.

We are subject to rate regulation. Our electric rates are set by the MPSC and the FERC and cannot be increased without regulatory authorization. We may be impacted by new regulations or interpretations by the MPSC, the FERC or other regulatory bodies. New legislation, regulations or interpretations could change how our business operates, impact our ability to recover costs through rate increases or require us to incur additional expenses.

Adverse changes in our credit ratings may negatively affect us. Increased scrutiny of the energy industry and regulatory changes, as well as changes in our economic performance could result in credit agencies reexamining our credit rating. While credit ratings reflect the opinions of the credit agencies issuing such ratings and may not necessarily reflect actual performance, a downgrade in our credit rating could restrict or discontinue our ability to access capital markets at attractive rates and increase our borrowing costs.

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

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

Environmental laws and liability may be costly. We are subject to numerous environmental regulations. These regulations govern air emissions, water quality, wastewater discharge, and disposal of solid and hazardous waste. Compliance with these regulations can significantly increase capital spending, operating expenses and plant down times. These laws and regulations require us to seek a variety of environmental licenses, permits, inspections and other regulatory approvals. We may also incur liabilities as a result of potential future requirements to address the climate change issue. The regulatory environment is subject to significant change; therefore, we cannot predict how future issues may impact the company.

Additionally, we may become a responsible party for environmental clean up at sites identified by a regulatory body. We cannot predict with certainty the amount and timing of future expenditures related to environmental matters because of the difficulty of estimating clean up costs. There is also uncertainty in

quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

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

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

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.

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

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

Michigan tax reform may be costly. The State of Michigan is experiencing a revenue shortfall. We are a significant taxpayer in the State of Michigan. The legislature is expected to change the tax laws in 2007, and we could face increased taxes.

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

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

Failure to successfully implement new processes and information systems could interrupt our operations. Our business depends on numerous information systems for operations and financial information and billings. We are in the midst of a multi-year Company-wide initiative to improve existing processes and implement new core information systems. We launched the first phase of our Enterprise Business Systems project in 2005. Additional phases of implementation are planned for 2007. Failure to successfully implement new processes and new core information systems could interrupt our operations.

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

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

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

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


Note		Title

4		Regulatory Matters
5		Nuclear Operations
13		Commitments and Contingencies

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 2006 and 2005, and $303 million in 2004.

Item 6. Selected Financial Data

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

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 increased $47 million and $124 million in 2006 and 2005, respectively. These results primarily reflect higher gross margins, partially offset by increased depreciation and amortization expenses. Additionally, 2005 results were affected by higher rates due to the November 2004 MPSC final rate order, return of customers from the electric Customer Choice program, warmer weather and lower operations and maintenance expenses, partially offset by a portion of higher fuel and purchased power costs, which were unrecoverable as a result of residential rate caps (which expired January 1, 2006), and increased depreciation and amortization expenses.

Increase (Decrease) in Income Statement Components Compared to Prior Year


(in Millions)	2006			2005
Operating Revenues	$	275		$	894
Fuel and Purchased Power		(24	)		705

Gross Margin		299			189
Operation and Maintenance		29			(87	)
Depreciation and Amortization		172			117
Taxes Other Than Income		11			(8	)
Asset (Gains) and Losses, net		20			(25	)

Operating Income		67			192
Other (Income) and Deductions		11			(20	)
Income Tax Provision		13			85

Income Before Accounting Change		43			127
Cumulative Effect of Accounting Change		4			(3	)

Net Income	$	47		$	124

Gross margin increased $299 million during 2006 and $189 million in 2005. The 2006 improvement was primarily due to increased rates due to the expiration of the residential rate cap on January 1, 2006 and returning sales from electric Customer Choice, partially offset by milder weather. The increase in 2005 was due to higher demand resulting from warmer weather and increased rates due to the November 2004 MPSC final rate order, partially offset by unrecovered power supply costs as a result of residential rate caps (which expired January 1, 2006) and a poor Michigan economy. Gross margin was favorably impacted by decreased electric Customer Choice penetration, whereby we lost 6% of retail sales to electric Customer Choice customers in 2006 and 12% of such sales during 2005 as retail customers migrated back to us as their electric generation provider rather than remaining with alternative suppliers. Pursuant to the MPSC final rate order, transmission expense, previously recorded in operation and maintenance expenses in 2004, is now reflected in purchased power expenses. The PSCR mechanism provides related revenues for the transmission expense.

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

Increase (Decrease) in Gross Margin Components Compared to Prior Year


(in Millions)	2006			2005
Weather-related margin impacts	$	(81	)	$	166
Removal of residential rate caps effective January 1, 2006		186			—
Return of customers from electric Customer Choice		156			79
Service territory economic performance		(16	)		(23	)
Impact of MPSC 2004 rate orders		26			116
Unrecovered power supply costs – residential customers		—			(73	)
Transmission charges		—			(93	)
Other, net		28			17

Increase in gross margin performance	$	299		$	189

Power Generated and Purchased


(in Thousands of MWh)	2006					2005					2004
Power Plant Generation
Fossil		39,686		70	%		40,756		73	%		39,432		75	%
Nuclear		7,477		13			8,754		16			8,440		16

		47,163		83			49,510		89			47,872		91
Purchased Power		9,861		17			6,378		11			4,650		9

System Output		57,024		100	%		55,888		100	%		52,522		100	%
Less Line Loss and Internal Use		(3,603	)				(3,205	)				(3,574	)

Net System Output		53,421					52,683					48,948


Average Unit Cost ($/MWh)
Generation (1)	$	15.61				$	15.47				$	12.98

Purchased Power (2)	$	53.71				$	89.37				$	37.06

Overall Average Unit Cost	$	22.20				$	23.90				$	15.11


(1)		Represents fuel costs associated with power plants.

(2)		The change in purchased power costs were driven primarily by seasonal demand and coal and gas prices.


(in Thousands of MWh)	2006		2005		2004
Electric Sales
Residential		15,769		16,812		15,081
Commercial		17,948		15,618		13,425
Industrial		13,235		12,317		11,472
Wholesale		2,826		2,329		2,197
Other		402		390		401

		50,180		47,466		42,576
Interconnection sales (1)		3,241		5,217		6,372

Total Electric Sales		53,421		52,683		48,948


Electric Deliveries
Retail and Wholesale		50,180		47,466		42,576
Electric Customer Choice		2,694		6,760		9,245
Electric Customer Choice – Self Generators (2)		909		518		595

Total Electric Sales and Deliveries		53,783		54,744		52,416


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

(2)		Represents deliveries for self generators who have purchased power from alternative energy suppliers to supplement their power requirements.

Operation and maintenance expense increased $29 million in 2006 and decreased $87 million in 2005. The 2006 increase was primarily due to increased distribution system maintenance of $35 million and increased plant outages of $33

million which was partially offset by $36 million of lower storm expenses. Pursuant to MPSC authorization, Detroit Edison deferred approximately $102 million of CTA in 2006. The comparability of 2005 to 2004 is affected by the November 2004 MPSC final rate order which required transmission and MISO expenses to be included in purchased power expense with related revenues to be recorded through the PSCR mechanism. Additionally, the DTE Energy parent company no longer allocated merger-related interest as a result of the November 2004 MPSC final rate order, which was partially offset by higher 2005 storm expenses.

Depreciation and amortization expense increased $172 million and $117 million in 2006 and 2005, respectively. The 2006 increase was due to a $112 million net stranded cost write-off related to the September 2006 MPSC order regarding stranded costs and a $19 million increase in our asset retirement obligation at our Fermi 1 nuclear facility. We also had increased amortization of regulatory assets of $19 million related to electric Customer Choice and $8 million related to our securitized assets. The 2005 increase reflects the income effect of recording regulatory assets in 2004, which lowered depreciation and amortization expenses. The regulatory asset deferrals totaled $46 million in 2005 and $107 million in 2004. Additionally, higher 2005 sales volumes compared to 2004 resulted in greater amortization of regulatory assets.

Asset (gains) and losses, net decreased $20 million in 2006 and increased $25 million in 2005 primarily as a result of our 2005 sale of land near our headquarters in Detroit, Michigan.

Other income and deductions expense increased $11 million in 2006 and decreased $20 million in 2005. The 2006 increase is attributable to higher interest expense due to increased long-term debt. The 2005 decrease is due primarily to lower interest expense as a result of lower interest rates and a favorable adjustment related to tax audit settlements.

Outlook – We continue to improve the operating performance of Detroit Edison. During the past year, we have resolved a portion of our regulatory issues and continue to pursue additional regulatory and/or legislative solutions for structural problems within the Michigan market structure, primarily electric Customer Choice and the need to adjust rates for each customer class to reflect the full cost of service.

Concurrently, we will move forward in our efforts to continue to improve performance. Looking forward, additional issues, such as rising prices for coal, health care and higher levels of capital spending, will result in us taking meaningful action to address our costs while continuing to provide quality customer service. We will utilize the DTE Energy Operating System and the Performance Excellence Process to seek opportunities to improve productivity, remove waste and decrease our costs while improving customer satisfaction.

Long term, we will be required to invest an estimated $2.4 billion on emission controls through 2018. Should we be able to recover these costs in future rate cases, we may experience a growth in earnings.

Additionally, our service territory may require additional generation capacity. A new base-load generating plant has not been built within the State of Michigan in the last 20 years. Should our regulatory environment be conducive to such a significant capital expenditure, we may build or expand a new base-load coal or nuclear facility. While we have not decided on construction of a new base-load nuclear facility, in February 2007, we announced that we will prepare a license application for construction and operation of 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 DTE Energy’s non-utility operations to Detroit Edison to support future power generation requirements.

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

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

	•		our ability to reduce costs and maximize plant performance;

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

	•		economic conditions within the State of Michigan;

	•		weather, including the severity and frequency of storms; and

	•		levels of customer participation in the electric Customer Choice program.

We expect cash flows and operating performance will continue to be at risk due to the electric Customer Choice program until the issues associated with this program are adequately addressed. We will accrue as regulatory assets any future unrecovered generation-related fixed costs (stranded costs) due to electric Customer Choice that we believe are recoverable under Michigan legislation and MPSC orders. We cannot predict the outcome of these matters. See Note 4 of the Notes to Consolidated Financial Statements.

In January 2007, the MPSC submitted the State of Michigan’s 21^st 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.

We continue to review the energy plan and are unable to predict the impact on the Company of the implementation of the plan.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES

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

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

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 to manage this risk. The approaches include forward energy, capacity, storage and futures contracts, as well as regulatory rate-recovery mechanisms. Regulatory rate-recovery occurs in the form of 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

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, 2006 and 2005 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, 2006. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements of the Company taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, in connection with the required adoption of new accounting principles, in 2006 the Company changed its method of accounting for defined benefit pension and other postretirement plans and share based payments. As discussed in Note 1 to the consolidated financial statements, in connection with the required adoption of a new accounting principle, in 2005 the Company changed its method of accounting for asset retirement obligations.

/s/ DELOITTE & TOUCHE
Detroit, Michigan
March 1, 2007

The Detroit Edison Company

Consolidated Statement of Operations


	Year Ended December 31
(in Millions)	2006			2005			2004
Operating Revenues	$	4,737		$	4,462		$	3,568


Operating Expenses
Fuel and purchased power		1,566			1,590			885
Operation and maintenance		1,337			1,308			1,395
Depreciation and amortization		812			640			523
Taxes other than income		252			241			249
Asset (gains) and losses, net		(6	)		(26	)		(1	)

		3,961			3,753			3,051


Operating Income		776			709			517


Other (Income) and Deductions
Interest expense		278			267			280
Interest income		(4	)		(3	)		—
Other income		(35	)		(27	)		(34	)
Other expenses		55			46			57

		294			283			303


Income Before Income Taxes		482			426			214

Income Tax Provision (Note 7)		162			149			64


Income Before Accounting Change		320			277			150

Cumulative Effect of Accounting Change (Notes 1 and 2)		1			(3	)		—


Net Income	$	321		$	274		$	150

See Notes to Consolidated Financial Statements

The Detroit Edison Company

Consolidated Statement of Financial Position


	December 31
(in Millions)	2006			2005
Assets
Current Assets
Cash and cash equivalents	$	27		$	26
Restricted cash (Note 1)		132			84
Accounts receivable(less allowance for doubtful accounts of $72 and $54, respectively)
Customer		601			528
Other		70			112
Accrued power supply cost recovery revenue		116			144
Inventories
Fuel		136			123
Materials and supplies		130			116
Other		54			43

		1,266			1,176


Investments
Nuclear decommissioning trust funds		740			646
Other		89			65

		829			711


Property
Property, plant and equipment		13,916			13,416
Less accumulated depreciation (Note 1)		(5,580	)		(5,595	)

		8,336			7,821


Other Assets
Regulatory assets (Note 4)		2,862			2,006
Securitized regulatory assets (Note 4)		1,235			1,340
Intangible assets		9			40
Other		74			75

		4,180			3,461


Total Assets	$	14,611		$	13,169

See Notes to Consolidated Financial Statements

The Detroit Edison Company
Consolidated Statement of Financial Position


	December 31
(in Millions, Except Shares)	2006		2005
Liabilities and Shareholder’s Equity
Current Liabilities
Accounts payable	$	411	$	392
Accrued interest		79		79
Dividends payable (Note 15)		76		76
Accrued vacations		77		80
Short-term borrowings		277		163
Accrued power supply cost recovery refund		—		129
Current portion long-term debt, including capital leases		142		135
Other		288		208

		1,350		1,262


Other Liabilities
Deferred income taxes		1,928		1,961
Regulatory liabilities (Notes 1 and 4)		255		224
Asset retirement obligations (Notes 1 and 5)		1,069		953
Unamortized investment tax credit		105		115
Nuclear decommissioning (Note 5)		119		85
Accrued pension liability		364		261
Accrued postretirement liability		1,055		252
Other		502		535

		5,397		4,386


Long-Term Debt (net of current portion) (Notes 9 and 11)
Mortgage bonds, notes and other		3,515		3,221
Securitization bonds		1,184		1,295
Capital lease obligations		50		57

		4,749		4,573


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		1,386		1,386
Additional paid in capital		1,210		1,060
Retained earnings		516		500
Accumulated other comprehensive income		3		2

		3,115		2,948


Total Liabilities and Shareholder’s Equity	$	14,611	$	13,169

See Notes to Consolidated Financial Statements

The Detroit Edison Company

Consolidated Statement of Cash Flows


	Year Ended December 31
(in Millions)	2006			2005			2004
Operating Activities
Net Income	$	321		$	274		$	150
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		812			640			523
Deferred income taxes		2			40			142
Gain on sale of assets		(6	)		(26	)		(1	)
Cumulative effect of accounting change		(1	)		3			—
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		(213	)		98			376

Net cash from operating activities		915			1,029			1,190


Investing Activities
Plant and equipment expenditures		(972	)		(722	)		(702	)
Proceeds from sale of assets, net		28			30			1
Restricted cash for debt redemptions		(48	)		(9	)		6
Notes receivable from affiliate		—			85			(78	)
Proceeds from sale of nuclear decommissioning trust fund assets		253			201			254
Investment in nuclear decommissioning trust funds		(284	)		(235	)		(287	)
Other investments		(29	)		(71	)		(33	)

Net cash used for investing activities		(1,052	)		(721	)		(839	)


Financing Activities
Issuance of long-term debt		314			857			266
Redemption of long-term debt		(126	)		(997	)		(206	)
Short-term borrowings, net		114			163			(100	)
Capital contribution by parent company		150			—			—
Dividends on common stock		(305	)		(305	)		(303	)
Other		(9	)		(6	)		(8	)

Net cash from (used for) financing activities		138			(288	)		(351	)


Net Increase in Cash and Cash Equivalents		1			20			—
Cash and Cash Equivalents at Beginning of the Period		26			6			6

Cash and Cash Equivalents at End of the Period	$	27		$	26		$	6

See Notes to Consolidated Financial Statements

The Detroit Edison Company

Consolidated Statement of Changes in Shareholder’s Equity and
Comprehensive Income


										Accumulated
					Additional					Other
(Dollars in Millions,	Common Stock				Paid in		Retained			Comprehensive
Shares in Thousands)	Shares		Amount		Capital		Earnings			Income		Total

Balance, December 31, 2003		134,288	$	1,343	$	933	$	686		$	1	$	2,963

Net income		—		—		—		150			—		150
Dividends declared on Common stock		—		—		—		(305	)		—		(305	)
Net change in unrealized losses on derivatives, net of tax		—		—		—		—			1		1
Common stock issued to parent company		4,344		43		127		—			—		170

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 gain 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

The following table displays comprehensive income:


(in Millions)	2006		2005		2004
Net income	$	321	$	274	$	150

Other comprehensive income:
Net change in unrealized gain on investments, net of tax		1		—		1

Comprehensive income	$	322	$	274	$	151

See Notes to Consolidated Financial Statements

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. We eliminate all intercompany balances and transactions.

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

Basis of Presentation

The accompanying consolidated financial statements are prepared using accounting principles generally accepted in the United States of America. These accounting principles require us to use estimates and assumptions that impact reported amounts of assets, liabilities, revenues, 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.

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, 2006 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
	Losses on		Gains on		Comprehensive
(in Millions)	Derivatives		Investments		Income
Beginning balance	$	1	$	1	$	2
Current-period change				1		1

Ending balance	$	1	$	2	$	3

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 is classified as a current asset as all restricted cash is designated for interest and principal payments due within one year.

Inventories

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

Property, Retirement and Maintenance, and Depreciation and Depletion

Summary of property by classification as of December 31:


(in Millions)	2006			2005
Property, Plant and Equipment
Generation	$	7,667		$	7,375
Distribution		6,249			6,041

Total		13,916			13,416


Less Accumulated Depreciation and Depletion
Generation		(3,410	)		(3,439	)
Distribution		(2,170	)		(2,156	)

Total		(5,580	)		(5,595	)


Net Property, Plant and Equipment	$	8,336		$	7,821

Property is stated at cost and includes construction-related labor, materials, overheads and an allowance for funds used during construction. The cost of properties retired, less salvage value, is charged to accumulated depreciation.

Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2. Approximately $16 million of expenses related to the anticipated Fermi 2 refueling outage scheduled for 2007 were accrued at December 31, 2006. Amounts are being accrued on a pro-rata basis over an 18-month period that began in May 2006. We have utilized the accrue-in-advance policy for nuclear refueling outage costs since the Fermi 2 plant was placed in service in 1988. This method matches the regulatory recovery of these costs in rates set by the MPSC. See Note 2.

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 2006, and 3.4% in 2005 and 2004.

The average estimated useful life for our generation and distribution property was 40 years and 37 years, respectively, at December 31, 2006.

We credit depreciation 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 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 Statement of Financial Position. We capitalize the costs associated with computer software we develop or obtain for use in our business. We amortize intangible assets on a straight-line basis over the expected period of benefit, ranging from 5 to 15 years. Intangible assets amortization expense was $28 million in 2006, $33 million in 2005 and $32 million in 2004. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2006 were $373 million and $52 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2005 were $346 million and $121 million, respectively. Amortization expense of intangible assets is estimated to be $37 million annually for 2007 through 2011.

Asset Retirement Obligations

We have recorded asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and FASB Interpretation FIN No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. We have a legal retirement obligation for the decommissioning costs for our Fermi 1 and Fermi 2 nuclear plants. 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.

The adoptions of SFAS No. 143 and FIN 47 resulted primarily in timing differences in the recognition of legal asset retirement costs that we are currently recovering in rates. We defer such differences under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

As a result of adopting FIN 47 on December 31, 2005, we recorded a plant asset of $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.

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

A reconciliation of the asset retirement obligation for 2006 follows:


(in Millions)
Asset retirement obligations at January 1, 2006	$	953
Accretion		64
Liabilities settled		(7	)
Revision in estimated cash flows		59

Asset retirement obligations at December 31, 2006	$	1,069

A significant portion of the asset retirement obligations represents nuclear decommissioning liabilities which are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear plant.

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 and at December 31, 2005, an intangible asset relating to an additional minimum pension liability recorded pursuant to SFAS No. 87.

Excise and Sales Taxes

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

Deferred Debt Costs

The costs related to the issuance of long-term debt are deferred and amortized over the life of each debt issue. In accordance with MPSC regulations, 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, respectively. Changes in the fair value of Fermi 2 nuclear decommissioning-related investments are recorded as adjustments to regulatory assets or liabilities. Our investments are reviewed for impairment each reporting period. If the assessment indicates that the impairment is other than temporary, a loss is recognized resulting in the investment being written down to its estimated fair value. See Note 5.

Affiliate Transactions

Detroit Edison shares costs with or incurs costs on behalf of unconsolidated affiliated companies. Prior to year end 2005, we recorded such costs within “Other expenses” and related reimbursement within “Other income” in the Consolidated Statement of Operations. These transactions do not affect combined other income and deductions or net income. Our financial statements now reflect such affiliate transactions exclusively within affiliate accounts receivable. Consistent with the current period’s presentation, previously reported amounts within the Consolidated Statement of Operations have been adjusted accordingly.

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)	2006			2005			2004
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	(36	)	$	(45	)	$	80
Inventories		(28	)		(21	)		14
Recoverable pension and postretirement costs		(925	)		61			(21	)
Accrued pensions		125			41			123
Accounts payable		7			46			135
Accrued power supply cost recovery refund		(101	)		(127	)		112
Accrued payroll		47			—			(15	)
Income taxes payable		16			(10	)		(14	)
General taxes		13			(1	)		(13	)
Risk management and trading activities		—			—			(1	)
Postretirement obligation		803			110			11
Other assets		(114	)		(3	)		4
Other liabilities		(20	)		47			(39	)

	$	(213	)	$	98		$	376

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


(in Millions)	2006		2005		2004
Cash Paid for
Interest (excluding interest capitalized)	$	278	$	267	$	277
Income taxes		141		118		2

Non-cash Financing Activity
Sale of assets		—		13		—
Common stock issued to parent company in conjunction with parent company common stock contribution to pension plan		—		—		170

Asset (gains) and losses, net

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

NOTE 2 – NEW ACCOUNTING PRONOUNCEMENTS

Accounting for Uncertainty in Income Taxes

In July 2006, the FASB issued Financial Interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109 – Accounting for Income Taxes. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109. Additionally, it prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in the tax return. FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition and is effective for fiscal years beginning after December 15, 2006. We plan to adopt FIN 48 on January 1, 2007. We do not expect the adoption to have a material impact to the January 1, 2007 balance of retained earnings.

Fair Value Accounting

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. It emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Fair value measurement should be determined based on the assumptions that market participants would use in pricing an asset or liability. SFAS 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We plan to adopt SFAS 157 on January 1, 2008. We are currently assessing the effects of this statement, and have not yet determined the impact on the consolidated financial statements.

In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115. This standard permits an entity to choose to measure many financial instruments and certain other items at fair- value. The fair value option established by SFAS 159 permits all entities to choose to measure eligible items at fair value at specified election dates. An entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to entire instruments and not to portions of instruments. SFAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. We are currently assessing the effects of this statement, and have not yet determined the impact on the consolidated financial statements.

Accounting for Defined Benefit Pension and Other Postretirement Plans

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an Amendment of FASB Statements No. 87, 88, 106, and 132(R). SFAS 158 requires companies to (1) recognize the overfunded or underfunded status of defined benefit pension and defined benefit other postretirement plans in its financial statements, (2) recognize as a component of other comprehensive income, net of tax, the actuarial gains or losses and the prior service costs or credits that arise during the period but are not immediately recognized as components of net periodic benefit cost, (3) recognize adjustments to other comprehensive income when the actuarial gains or losses, prior service costs or credits, and transition assets or obligations are recognized as components of net periodic benefit cost, (4) measure postretirement benefit plan assets and plan obligations as of the date of the employer’s statement of financial position, and (5) disclose additional information in the notes to financial statements about certain effects on net periodic benefit cost in the upcoming fiscal year that arise from delayed recognition of the actuarial gains and losses and the prior service cost and credits.

The requirement to recognize the funded status of a defined benefit pension or defined benefit other postretirement plan and the related disclosure requirements was effective for fiscal years ending after December 15, 2006, and we adopted this portion of the standard on December 31, 2006. We requested

and received agreement from the MPSC to record the additional liability amounts on the balance sheet as a regulatory asset.

The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. The Statement provides two options for the transition to a fiscal year end measurement date. We currently use a November 30 measurement date. We have not yet determined which of the available transition measurement options we will use.

See Note 14.

Accounting for Planned Major Maintenance

In September 2006, the FASB issued its Staff Position (FSP), AUG AIR-1, Accounting for Planned Major Maintenance Activities. This FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. We have historically charged expenditures for maintenance and repairs to expense as they were incurred, with the exception of Fermi 2, where we have utilized the accrue-in-advance policy for nuclear refueling outage costs since the plant was placed in service in 1988. We adopted this FSP on December 31, 2006. Although this FSP prohibits use of the accrue-in-advance method, we will continue to use it to account for the cost of Fermi 2 refueling outages because it matches the regulatory recovery of these costs in rates set by the MPSC and, therefore is in compliance with the requirements of SFAS No. 71. The adoption of FSP AUG AIR-1 had no income impact on our financial statements. See Note 4.

Quantifying Misstatements

In September 2006, the SEC staff issued Staff Accounting Bulletin (SAB) Topic 1N, Financial Statements — Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements (SAB 108). SAB 108 addresses how a registrant should quantify the effect of an error on the financial statements. The SEC staff concluded in SAB 108 that a dual approach should be used to compute the amount of a misstatement. Specifically, the amount should be computed using both the “rollover” (current year income statement perspective) and “iron curtain” (year-end balance sheet perspective) methods. We adopted this SAB effective December 31, 2006. Based on our assessment, we identified no errors that would require an adjustment to current or prior financial statements; therefore, the adoption of SAB 108 had no financial statement impact.

Stock-Based Compensation

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 2006 for stock-based compensation expense was approximately $14 million. The cumulative effect of the adoption of SFAS 123(R) was a decrease in operation and maintenance 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).

NOTE 3 – RESTRUCTURING

Performance Excellence Process

In mid-2005, we initiated a company-wide review of our operations called the Performance Excellence Process. Specifically, we began a series of focused improvement initiatives within our Detroit Edison and associated corporate support functions. We expect this process will be carried out over a two- to three-year period beginning in 2005.

We have incurred CTA for employee severance and other costs. Other costs include project management and consultant support. Pursuant to MPSC authorization, in 2006, Detroit Edison deferred approximately $102 million of CTA. Detroit Edison will begin amortizing deferred 2006 costs in 2007 as the recovery of these costs was provided for by the MPSC. See Note 4.

Amounts expensed are recorded in within the Operations and maintenance line in the Consolidated Statement of Operations. Deferred amounts are recorded within the Regulatory asset line in the Consolidated Statement of Financial Position. Expenses incurred in 2006 are as follows:


	Employee
(in Millions)	Severance Costs (1)		Other Costs		Total Costs
Costs incurred:	$	51	$	56	$	107

Less amounts deferred or capitalized:		51		56		107

Amount expensed	$	—	$	—	$	—


(1)		Includes corporate allocations.

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

NOTE 4 — 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.

As subsequently discussed in the “Electric Industry Restructuring” section, Detroit Edison’s rates were frozen through 2003 and capped for small business customers through 2004 and for residential customers through 2005 as a result of Public Act (PA) 141. However, Detroit Edison was allowed to defer certain costs to be recovered once rates could be increased, including costs incurred as a result of changes in taxes, laws and other governmental actions.

Regulatory Assets and Liabilities

Detroit Edison 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. 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)	2006			2005
Assets
Securitized regulatory assets	$	1,235		$	1,340


Recoverable income taxes related to securitized regulatory assets	$	677		$	734
Recoverable pension and postretirement costs		1,469			543
Asset retirement obligation		236			196
Other recoverable income taxes		100			104
Recoverable costs under PA 141
Net stranded costs		—			112
Excess capital expenditures		22			22
Deferred Clean Air Act expenditures		67			82
Midwest Independent System Operator charges		48			56
Electric Customer Choice implementation costs		78			98
Enhanced security costs		13			13
Unamortized loss on reacquired debt		38			41
Accrued PSCR revenue		116			144
Costs to achieve Performance Excellence Process		102			—
Enterprise Business Systems costs		9			—
Other		3			5

		2,978			2,150
Less amount included in current assets		(116	)		(144	)

	$	2,862		$	2,006


Liabilities
Asset removal costs	$	222		$	213
Accrued PSCR refund		—			129
Accrued pension		33			11
Fermi 2 refueling outage		16			25
Other		2			2

		273			380
Less amount included in current liabilities		(18	)		(156	)

	$	255		$	224

ASSETS

•

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

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

•		Recoverable pension and postretirement costs — The traditional rate setting process allows for the recovery of pension and postretirement costs as measured by generally accepted accounting principles. In 2006, we adopted SFAS No. 158. See Note 14.

•		Asset retirement obligation — Asset retirement obligations were recorded pursuant to adoption of SFAS No. 143 in 2003 and FIN 47 in 2005. These obligations are primarily for Fermi 2 decommissioning costs that are recovered in rates.

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

•		Net stranded costs — PA 141 permits, after MPSC authorization, the recovery of and a return on fixed cost deficiency associated with the electric Customer Choice program. Net stranded costs occured when fixed cost related revenues did not cover the fixed cost revenue requirements.

•		Excess capital expenditures — Starting in 2004, PA 141 permits, after MPSC authorization, the recovery of and a return on capital expenditures that exceed a base level of depreciation expense.

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

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

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

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

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

•		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.

LIABILITIES

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

•		Accrued PSCR refund — Payable for the temporary over-recovery of and a return on power supply costs, and beginning with the MPSC’s November 2004 rate order, transmission costs incurred by Detroit Edison which are recoverable through the PSCR mechanism.

•		Accrued 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 – Liability for refueling outage at Fermi 2 pursuant to MPSC authorization. See Note 2.

Electric Rate Restructuring Proposal

In February 2005, Detroit Edison filed a rate restructuring proposal with the MPSC to restructure its electric rates and begin phasing out subsidies within the current pricing structure. In December 2005, the MPSC issued an order that did not provide for the comprehensive realignment of the existing rate structure that Detroit Edison requested in its rate restructuring proposal. The MPSC order did take some initial steps to improve the current competitive imbalance in Michigan’s electric Customer Choice program. The December 2005 order established cost-based power supply rates for Detroit Edison’s full service customers. Electric Customer Choice participants will pay cost-based distribution rates, while Detroit Edison’s full service commercial and industrial customers will pay cost-based distribution rates that reflect the cost of the residential rate subsidy. Residential customers continue to pay a subsidized below-cost rate for distribution service. These revenue neutral revised rates were effective February 1, 2006. Detroit Edison was also ordered to file a general rate case by July 1, 2007, based on 2006 actual results.

Other Postretirement Benefits Costs Tracker

In February 2005, Detroit Edison filed an application, pursuant to the MPSC’s November 2004 final rate order, requesting MPSC approval of a proposed tracking mechanism for retiree health care costs. This mechanism would recognize differences between cost levels collected in rates and the actual costs under current accounting rules as regulatory assets or regulatory liabilities with an annual reconciliation proceeding before the MPSC. In February 2006, the MPSC denied Detroit Edison’s request and ordered that this issue be addressed in the next general rate case due to be filed by July 1, 2007.

MPSC Show-Cause Order

The MPSC issued an order approving a settlement agreement in this proceeding on August 31, 2006. The order provided for an annualized rate reduction of $53 million for 2006, effective September 5, 2006. Beginning January 1, 2007, and continuing until the later of March 31, 2008 or 12 months from the filing date of Detroit Edison’s next general rate case, rates will be reduced by an additional $26 million, for a total reduction of $79 million. The revenue reduction is net of the recovery of the amortization of the costs associated with the implementation of the Performance Excellence Process. The settlement agreement provides for some level of realignment of the existing rate structure by allocating a larger

percentage share of the rate reduction to the commercial and industrial customer classes than to the residential customer classes.

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

Regulatory Accounting Treatment for Performance Excellence Process

In May 2006, we filed applications with the MPSC to allow deferral of costs associated with the implementation of the Performance Excellence Process, a company-wide cost-savings and performance improvement program. Implementation costs include project management, consultant support and employee severance expenses. We sought MPSC authorization to defer and amortize Performance Excellence Process implementation costs for accounting purposes to match the expected savings from the Performance Excellence Process program with the related CTA. We anticipate that the Performance Excellence Process will be carried out over a two- to three-year period beginning in 2006. Detroit Edison’s CTA is estimated to total between $160 million and $190 million. In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison, commencing in 2006, to defer the incremental CTA. Further, the order provides for Detroit Edison to amortize the CTA deferrals over a ten-year period beginning with the year subsequent to the year the CTA was deferred. Detroit Edison recorded the deferred CTA costs of $102 million as a regulatory asset and will begin amortizing deferred 2006 costs in 2007 as the recovery of these costs was provided for by the MPSC in the order approving the settlement in the show cause proceeding.

Electric Industry Restructuring

In 2000, the Michigan Legislature enacted PA 141 that reduced electric retail rates by 5%, as a result of savings derived from the issuance of securitization bonds. The legislation also contained provisions freezing rates through 2003 and preventing rate increases (i.e., rate caps) for small business customers through 2004 and for residential customers through 2005. The price freeze period expired on February 20, 2004 pursuant to an MPSC order. In addition, PA 141 codified the MPSC’s existing electric Customer Choice program and provided Detroit Edison with the right to recover net stranded costs associated with electric Customer Choice. Detroit Edison was also allowed to defer certain costs to be recovered once rates could be increased, including costs incurred as a result of changes in taxes, laws and other governmental actions.

As required by PA 141, the MPSC conducted a proceeding to develop a methodology for calculating net stranded costs associated with electric Customer Choice. In a December 2001 order, the MPSC determined that Detroit Edison could recover net stranded costs associated with the fixed cost component of its electric generation operations. Specifically, there would be an annual proceeding or true-up before the MPSC reconciling the receipt of revenues associated with the fixed cost component of its generation services to the revenue requirement for the fixed cost component of those services, inclusive of an allowance for the cost of capital. Any resulting shortfall in recovery, net of mitigation, would be considered a net stranded cost. The MPSC authorized Detroit Edison to establish a regulatory asset to defer recovery of its incurred stranded costs, subject to review in a subsequent annual net stranded cost proceeding.

2004 PSCR Reconciliation and 2004 Net Stranded Cost Case

Securitization

Detroit Edison formed The Detroit Edison Securitization Funding LLC (Securitization LLC), a wholly owned subsidiary, for the purpose of securitizing its qualified costs, primarily related to the unamortized investment in the Fermi 2 nuclear power plant. In March 2001, the Securitization LLC issued $1.75 billion of securitization bonds, and Detroit Edison sold $1.75 billion of qualified costs to the Securitization LLC. The Securitization LLC is independent of Detroit Edison, as is its ownership of the qualified costs. Due to principles of consolidation, the qualified costs and securitization bonds appear on our Consolidated Statement of Financial Position. We make no claim to these assets. Ownership of such assets has vested in the Securitization LLC and been assigned to the trustee for the securitization bonds. Neither the qualified costs nor funds from an MPSC approved non-bypassable surcharge collected from Detroit Edison’s customers for the payment of costs related to the Securitization LLC and securitization bonds are available to Detroit Edison’s creditors.

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 approved a settlement agreement providing for the deferral of up to $60 million of certain EBS costs that would otherwise be expensed, as a regulatory asset for future rate recovery starting January 1, 2006. At December 31, 2006, approximately $9 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

Power Supply Costs Recovery Proceedings

2005 Plan Year – In September 2004, Detroit Edison filed its 2005 PSCR plan case seeking approval of a levelized PSCR factor of 1.82 mills per kWh above the amount included in base rates. In December 2004, Detroit Edison filed revisions to its 2005 PSCR plan case in accordance with the November 2004 MPSC rate order. The revised filing seeks approval of a levelized PSCR factor of up to 0.48 mills per kWh above the new base rates established in the final electric rate order. Included in the factor were power supply costs, transmission expenses and nitrogen oxide (NOx) emission allowance costs. Detroit Edison self-implemented a factor of negative 2.00 mills per kWh on January 1, 2005. Effective June 1, 2005, Detroit Edison began billing the maximum allowable factor of 0.48 mills per kWh due to increased power supply costs. In September 2005, the MPSC approved Detroit Edison’s 2005 PSCR plan case. At December 31, 2005, Detroit Edison has recorded an under-recovery of approximately $144 million related to the 2005 plan year. In March 2006, Detroit Edison filed its 2005 PSCR reconciliation. The

filing sought approval for recovery of approximately $144 million 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. The September 2006 order in the Company’s 2004 PSCR Reconciliation and Stranded Cost proceeding directed the Company to roll the entire 2004 PSCR over-collection amount to the Company’s 2005 PSCR Reconciliation, thereby reducing the Company’s 2005 PSCR Reconciliation under-collection amount for commercial and industrial customers to $64 million. An order is expected in the first half of 2007.

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 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 includes a matrix which provides for different maximum PSCR factors contingent on varying electric Customer Choice sales levels. The plan also includes $97 million for recovery of its projected 2005 PSCR under-collection associated with commercial and industrial customers. Additionally, the PSCR plan requests 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% to reflect the potential variability in cost projections. The quarterly factors will allow 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. We have filed a petition for re-

hearing. In December 2006, Detroit Edison was granted its request to include its updated projection ($81 million) of its 2006 PSCR undercollection in its 2007 PSCR plan. In addition, Detroit Edison was granted the authority to include all PSCR over/ (under) collections in future PSCR plans, thereby reducing the time between refund or recovery of PSCR reconciliation amounts.

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 includes $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 includes 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 sulfur dioxide 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. The Company will begin 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.

Minimum Pension Liability

In December 2006, Detroit Edison adopted the provisions of SFAS No. 158, to recognize the obligations of its pension and postretirement plans. Based on approval received from the MPSC, Detroit Edison recorded the charge to a miscellaneous deferred debit included in regulatory assets in the Consolidated Statement of Financial Position.

Other

We are 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, our nuclear generating plant, began commercial operation in 1988. Fermi 2 has a design electrical rating (net) of 1,150 megawatts. 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. See Note 4. 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.

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. These policies have a 12-week waiting period and provide 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.

For multiple terrorism losses caused by acts of terrorism not covered under the Terrorism Risk Insurance Extension Act of 2005 (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 $29 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, which is classified as a noncurrent regulatory liability. 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 2025 through 2050. It is estimated that the cost of decommissioning Fermi 2, when its license expires in 2025, will be $1.2 billion in 2006 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.

Detroit Edison currently recovers funds for Fermi 2 decommissioning and the disposal of low-level radioactive waste through a revenue surcharge. The decommissioning of Fermi 1 is funded by Detroit Edison. The amounts recovered from customers are deposited in the restricted external trust accounts to fund decommissioning.


(in Millions)	2006		2005		2004
Revenue	$	39	$	40	$	38
Net unrealized investment gains		42		—		17

The nuclear decommissioning cost will be funded by investments held in trust funds that have been established for each nuclear station as follows:


	As of December 31,
(in Millions)	2006		2005
Decommissioning trust funds
Fermi 2	$	694	$	601
Fermi 1		15		18
Low level radioactive waste		31		27

Total	$	740	$	646

At December 31, 2006, investments in the external nuclear decommissioning trust funds consisted of approximately 50% in publicly traded equity securities, 43% in fixed debt instruments and 7% in cash equivalents.

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. Detroit Edison is continuing to fund FERC jurisdictional amounts for decommissioning even though explicit provisions are not included in FERC rates. We believe 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. We expect 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 returned to the ratepayers.

A portion of 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 included in the nuclear decommissioning regulatory liability.

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. Until the DOE is able to fulfill its obligation under the contract, Detroit Edison is responsible for the spent nuclear fuel storage. Detroit Edison is currently expanding the Fermi 2 spent fuel pool capacity to meet our storage requirements through 2009. 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.

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, 2006 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)	$	1,578	$	164
Accumulated depreciation (in Millions)	$	815	$	97


*		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

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 $16 million at December 31, 2006 and $33 million at December 31, 2005 due from DTE Energy.

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


(Dollars in Millions)	2006			2005			2004
Income tax expense at 35% statutory rate	$	169		$	149		$	75

Investment tax credits		(7	)		(7	)		(7	)
Depreciation		3			3			3
Employee Stock Ownership Plan dividends		(4	)		(4	)		(4	)
Medicare part D subsidy		(5	)		(6	)		(3	)
Adjustment to deferred tax accounts		—			14			—
Other, net		6			—			—

Total	$	162		$	149		$	64


Effective federal income tax rate		33.3	%		35.0	%		29.9	%

Components of income tax expense were as follows:


(in Millions)	2006		2005		2004
Current federal and other income tax expense (benefit)	$	160	$	110	$	(78	)
Deferred federal and other income tax expense		2		39		142


Total	$	162	$	149	$	64

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)	2006			2005
Property, plant and equipment	$	(1,209	)	$	(1,179	)
Securitized regulatory assets		(670	)		(723	)
Pension and benefits		94			92
Other Comprehensive Income		(1	)		(1	)
Other, net		(180	)		(146	)

	$	(1,966	)	$	(1,957	)


Deferred income tax liabilities	$	(2,478	)	$	(2,328	)
Deferred income tax assets		512			371

	$	(1,966	)	$	(1,957	)


Current deferred income tax assets (included in Current Assets – Other)		—			4
Current deferred income tax liabilities (included in Current Liabilities – Other		(38	)		—
Long term deferred income tax liabilities		(1,928	)		(1,961	)

		(1,966	)		(1,957	)

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

In January 2007, we signed an agreement with the Internal Revenue Service acknowledging our acceptance of the results of the 2002 and 2003 audits of Detroit Edison as a component of the DTE Energy federal income tax returns. We accrue tax and interest related to tax uncertainties that arise due to actual or potential disagreements with governmental agencies about the tax treatment of specific items. At December 31, 2006, the Company had accrued approximately $6 million for such uncertainties. We believe that our accrued tax liabilities are adequate for all years. See Note 2 for information regarding the planned January 1, 2007 adoption of FIN 48.

NOTE 8 – COMMON STOCK

In March 2004, we issued 4,344,492 shares of common stock to DTE Energy.

NOTE 9 — LONG-TERM DEBT AND PREFERRED SECURITIES

Long-Term Debt

Our long-term debt outstanding and weighted average interest rates(1) of debt outstanding at December 31, 2006 were:


(in Millions)	2006			2005
Detroit Edison Taxable Debt, Principally Secured
5.9% due 2010 to 2037	$	2,267		$	2,030
Detroit Edison Tax Exempt Revenue Bonds (2)
5.2% due 2008 to 2036		1,213			1,145
Other Long-Term Debt		59			67

		3,539			3,242
Less amount due within one year		(24	)		(21	)

	$	3,515		$	3,221


Securitization Bonds	$	1,295		$	1,400
Less amount due within one year		(111	)		(105	)

	$	1,184		$	1,295


(1)		Weighted average interest rate as of December 31, 2006 are shown below the description of each debt issue.

(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 2006, we issued the following long-term debt:

Month

(in Millions)

Company

Issued

Type

Interest Rate

Maturity

Amount

Detroit Edison

May

Senior Notes (1)

6.625%

June 2036

250

Detroit Edison

December

Tax Exempt Revenue Bonds (2)

Variable

December 2036

Total Issuances

319


(1)		The proceeds from the issuance were used to repay short-term borrowings and for general corporate purposes.

(2)		The proceeds from the issuance to be used to finance the construction, acquisition, improvement and installation of certain solid waste disposal facilities at Detroit Edison’s Monroe Power Plant.

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


											2012 &
(in millions)	2007		2008		2009		2010		2011		thereafter		Total

Amount to mature	$	135	$	178	$	158	$	667	$	310	$	3,392	$	4,840

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.

Preferred and Preference Securities – Authorized and Unissued

At December 31, 2006, 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 .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.

Effective December 31, 2006, the credit agreements were amended to, among other things, exclude the effects of SFAS No. 158 in the compliance calculation and exclude un-drawn letters of credit and guarantees (except for guaranteed debt of non-consolidated third parties) from the debt calculations under these credit agreements.

Detroit Edison is currently in compliance with its covenants.

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. Detroit Edison is currently in compliance with these covenants. We had an outstanding balance of $100 million at December 31, 2006 and no outstanding balance at December 31, 2005.

At December 31, 2006, we had outstanding commercial paper of $177 million and $163 million in 2005.

The weighted average interest rates for short-term borrowings were 5.4% and 4.4% at December 31, 2006 and 2005, respectively.

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, 2006 were:


	Capital			Operating
(in Millions)	Leases			Leases
2007	$	10		$	38
2008		11			32
2009		11			26
2010		9			21
2011		7			20
Thereafter		22			130

Total minimum lease payments		70		$	267

Less imputed interest		(13	)

Present value of net minimum lease payments		57
Less current portion		(7	)

Non-current portion	$	50

Rental expense for operating leases was $44 million in 2006, $28 million in 2005, and $19 million in 2004.

NOTE 12 – FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

We comply with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Listed below are important SFAS No. 133 requirements:

•		Derivative instruments must be recognized as assets or liabilities and measured at fair value, unless they meet the normal purchases and sales exemption.

•		Accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated as a hedge and qualifies for hedge accounting.

•		Special accounting is allowed for derivative instruments that qualify as a hedge and are designated as a hedge for the variability of cash flow associated with a forecasted transaction. Gain or loss associated with the effective portion of the hedge is recorded in other comprehensive income. The ineffective portion is recorded to earnings. Amounts recorded in other comprehensive income will be reclassified to net income when the forecasted transaction affects earnings. If a cash flow hedge is discontinued because it is likely the forecasted transaction will not occur, net gains or losses are immediately recorded to earnings.

•		Special accounting is also allowed for derivative instruments that qualify as a hedge and are designated as a hedge of the changes in fair value of an existing asset, liability or firm commitment. Gain or loss on the hedging instrument is recorded into earnings. An offsetting loss or gain on the underlying asset, liability or firm commitment is also recorded to earnings.

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 generates, purchases, distributes and sells electricity. Detroit Edison uses forward energy, capacity, and futures contracts to manage changes in the price of electricity and fuel. These derivatives are designated as cash flow hedges or meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. There were no commodity price risk cash flow hedges at December 31, 2006. Our commodity price risk is limited due to the PSCR mechanism. See Note 1.

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.

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.

2006

2005

Fair Value

Carrying Value

Fair Value

Carrying Value

Long-Term Debt

$5.0 billion

$4.8 billion

$4.8 billion

$4.6 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 $875 million through 2006. We estimate Detroit Edison future capital expenditures at up to $222 million in 2007 and up to $2 billion of additional capital expenditures through 2018 to satisfy both the existing and proposed new control requirements.

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 intakes. Initially, it was estimated that the Company could incur up to $53 million over the next three to five years in additional capital expenditures to comply with these requirements. However, a recent court decision remanded back to the EPA several provisions of the federal regulation resulting in a delay in complying with the regulation. The decision also raised the possibility that the Company 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 two former MGP sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is approximately $11 million which was accrued in 2006 and is expected to be incurred over the next several years. In addition, Detroit Edison expects to make approximately $5 million of capital improvements to the ash landfill in 2007.

Personal Property Taxes

Detroit Edison and other Michigan utilities have asserted that Michigan’s valuation tables result in the substantial overvaluation of utility personal property. Valuation tables established by the Michigan State Tax Commission (STC) are used to determine the taxable value of personal property based on the property’s age. In November 1999, the STC approved new valuation tables that more accurately recognize the value of a utility’s personal property. The new tables became effective in 2000 and are currently used to calculate property tax expense. However, several local taxing jurisdictions took legal action attempting to prevent the STC from implementing the new valuation tables and continued to prepare assessments based on the superseded tables.

In December 2005, a settlement agreement was reached and executed Stipulations for Consent Judgment, Consent Judgments, and Schedules to Consent Judgment were filed with the Michigan Tax Tribunal on behalf of Detroit Edison, MichCon and a significant number of the largest jurisdictions, in terms of tax dollars, involved in the litigation. The filing of these documents fulfilled the requirements of the settlement agreement and resolves a number of claims by the litigants against each other including both property and non-property issues. The settlement agreement resulted in a pre-tax economic benefit to Detroit Edison in 2005 that included the release of a litigation reserve.

Labor Contracts

There are several bargaining units for our represented employees. Approximately 3,239 of our represented employees are under contracts that expire in June 2007. The contract of the remaining represented employees expires in 2008.

Other 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 special 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 is being amortized to fuel, purchased power and gas expense with non-cash accretion expense being recorded through 2008. We purchased approximately $42 million of steam and electricity in 2006, 2005 and 2004. We estimate steam and electric purchase commitments through 2024 will not exceed $386 million. In January 2003, we sold the steam heating business of Detroit Edison to Thermal Ventures II, LP. Due to terms of the sale, Detroit Edison remains contractually obligated to buy steam from GDRRA until 2008 and recorded an additional liability of $63 million for future commitments. Also, we have guaranteed bank loans of approximately $12 million that Thermal Ventures II, LP may use for capital improvements to the steam heating system.

As of December 31, 2006, we were party to numerous long-term purchase commitments relating to a variety of goods and services required for our business. These agreements primarily consist of fuel supply commitments. We estimate that these commitments will be approximately $1.3 billion through

2020. We also estimate that 2007 base level capital expenditures will be $875 million. We have made certain commitments in connection with expected capital expenditures.

Bankruptcies

Other

Detroit Edison is involved in a contract dispute with BNSF Railway Company that has been referred to arbitration. Under this contract, BNSF transports western coals east for Detroit Edison. We have filed a breach of contract claim against BNSF for the failure to provide certain services that we believe are required by the contract. The arbitration hearing is scheduled for mid-2007. While we believe we will prevail on the merits in this matter, a negative decision with respect to the significant issues being heard in the arbitration could have an adverse effect on our business.

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, 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 Notes 4 and 5 for a discussion of contingencies related to Regulatory Matters and Nuclear Operations.

NOTE 14 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

Adoption of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans

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. We 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. We plan to adopt this requirement as of December 31, 2008.

Detroit Edison received approval from the MPSC to record the charge related to the additional liability as a miscellaneous deferred debit in the regulatory asset line on the consolidated statement of financial position since the traditional rate setting process allows for the recovery of pension and other postretirement plan costs. Retrospective application of the changes required by SFAS No. 158 is prohibited; therefore certain disclosures below are not comparable.

Measurement Date

In the fourth quarter of 2004, we changed the date for actuarial measurement of our obligations for benefit programs from December 31 to November 30. We believe the one-month change of the measurement date is a preferable change as it allows time for management to plan and execute its review of the completeness and accuracy of its benefit programs results and to fully reflect the impact on its financial results. The change did not have a material effect on retained earnings as of January 1, 2004, and income from continuing operations, net income and related per share amounts for any interim period in 2004. Accordingly, all amounts reported in the following tables for balances as of December 31, 2006 and December 31, 2005 are based on measurement dates of November 30, 2006 and November 30, 2005, respectively. Amounts reported in tables for the year ended December 31, 2006 are based on a measurement date of November 30, 2005. Amounts reported in tables for the year ended December 31, 2005 are based on a measurement date of November 30, 2004. Amounts reported in tables for the year ended December 31, 2004 are based on a measurement date of December 31, 2003.

Qualified and Nonqualified Pension Plan Benefits

We have a defined benefit retirement plan. The plan is noncontributory, 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 nonrepresented 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. 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.

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 2006, we contributed $180 million to the qualified pension plans and $15 million to the nonqualified pension plans. We anticipate making up to a $180 million contribution to our qualified pension plans in 2007 and a $15 million contribution to our nonqualified pension plans in 2007.

Net pension cost includes the following components:


	Qualified Pension Plans									Nonqualified Pension Plans
(in Millions)	2006			2005			2004			2006		2005		2004
Service Cost	$	49		$	53		$	47		$	2	$	1	$	1
Interest Cost		133			130			130			3		2		2
Expected Return on Plan Assets		(135	)		(135	)		(135	)		—		—		—
Amortization of
Net income		44			50			49			1		1		1
Prior service cost		8			9			9			—		—		—
Special Termination Benefits		38			—			—			—		—		—

Net Pension Cost	$	137		$	107		$	100		$	6	$	4	$	4

Amounts in regulatory assets expected to be recognized as components of net periodic benefit cost during 2007 are comprised of $44 million of net actuarial loss and $6 million of prior service cost relating to the qualified plans and $1 million of net actuarial loss and $1 million of prior service cost relating to the nonqualified pension plans. We recorded a $38 million pension cost associated with our Performance Excellence Process in 2006.

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 amounts contributed to the combined plan by such affiliates is reflected as an amount due to affiliates, $295 million and $273 million at December 31, 2006 and 2005, respectively.


	Qualified Pension Plans						Nonqualified Pension Plans
(in Millions)	2006			2005			2006			2005
Accumulated Benefit Obligation-End of Period	$	2,668		$	2,497		$	46		$	37


Projected Benefit Obligation-Beginning of Period	$	2,738		$	2,643		$	41		$	36
Service Cost		55			59			2			1
Interest Cost		156			154			3			2
Actuarial Loss		66			35			5			4
Benefits Paid		(180	)		(153	)		(3	)		(2	)
Plan Amendments		(6	)		—			—			—
Special Termination Benefits		43			—			—			—

Projected Benefit Obligation-End of Period	$	2,872		$	2,738		$	48		$	41


Plan Assets at Fair Value-Beginning of Period	$	2,273		$	2,235		$			$	—
Actual Return on Plan Assets		280			191						—
Company Contributions		—			—			3			2
Benefits Paid		(180	)		(153	)		(3	)		(2	)

Plan Assets at Fair Value-End of Period	$	2,373		$	2,273		$	—		$	—


Funded Status of the Plans	$	(499	)	$	(465	)	$	(48	)	$	(41	)
December Adjustment		180			—			—			—


Funded Status, End of Year	$	(319	)	$	(465	)	$	(48	)	$	(41	)


Unrecognized (a)
Net Actuarial loss (a)					773					$	15
Prior service cost (a)					34						1

Net Amount Recognized-End of Period (a)				$	342					$	(25	)


Amount Recorded as (a)
Accrued pension liability (a)					(224	)					(37	)
Regulatory asset (a)					532						11
Intangible Asset (a)					34						1

				$	342					$	(25	)


Current Liabilities (b)	$	—					$	(3	)
Noncurrent Liabilities (b)		(319	)					(45	)

	$	(319	)				$	(48	)

Amounts Recognized in Regulatory Assets
Net Actuarial loss (b)	$	706					$	18
Prior service cost (b)	$	20					$	2


a		- Disclosure no longer required by FAS 158, adopted in 2006, retroactive adoption not permitted.

b		- New disclosure required by FAS 158, adopted in 2006, retroactive adoption not permitted.

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


	2006			2005			2004
Projected Benefit Obligation
Discount rate		5.70	%		5.90	%		6.00	%
Annual increase in future compensation levels		4.0	%		4.0	%		4.0	%

Net Pension Costs
Discount rate		5.90	%		6.00	%		6.25	%
Annual increase in future compensation levels		4.0	%		4.0	%		4.0	%
Expected long-term rate of return on Plan assets		8.75	%		9.0	%		9.0	%

At December 31, 2006, 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)
2007	$	163
2008		167
2009		173
2010		181
2011		186
2012 – 2016		1,053

Total	$	1,923

We employ a consistent formal process in determining the long-term rate of return for various asset classes. We evaluate input from our consultants, including their review of 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.

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 of 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 used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying investments. 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:


	2006			2005
Equity Securities		68	%		68	%
Debt Securities		23			27
Other		9			5

		100	%		100	%

Our plans’ weighted-average asset target allocations by asset category at December 31, 2006 were as follows:


Equity Securities	65	%
Debt Securities	20
Other	15

	100	%

We also sponsor defined contribution retirement savings plans. Participation in one of these plans is available to substantially all represented and nonrepresented 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 $23 million in 2006, $23 million in 2005, and $22 million in 2004.

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 nonrepresented employees. In 2006, we made cash contributions of $76 million to our postretirement benefit plans. At the discretion of management, we may make up to a $76 million contribution to our VEBA trusts in 2007.

Net postretirement cost includes the following components:


(in Millions)	2006			2005			2004
Service Cost	$	45		$	44		$	33
Interest Cost		88			80			69
Expected Return on Plan Assets		(49	)		(58	)		(45	)
Amortization of
Net loss		53			44			33
Prior service costs		4			3			—
Net transition obligation		7			7			8

Special Termination Benefits obligation		6			—			—

Net Postretirement Cost	$	154		$	120		$	98

Amounts in regulatory assets expected to be recognized as components of net periodic benefit cost during 2007 are comprised of $50 million of net actuarial loss, $4 million of prior service cost and $6 million of net transition obligation. We recorded $6 million postretirement benefit cost associated with our Performance Excellence Process in 2006.

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)	2006			2005
Accumulated Postretirement Benefit Obligation-Beginning of Period	$	1,525		$	1,361
Service Cost		45			44
Interest Cost		88			80
Actuarial Loss		63			111
Plan Amendments		2			(5	)
Benefits Paid		(70	)		(66	)
Special Termination Benefits		6			—
Medicare Part D subsidy		1			—

Accumulated Postretirement Benefit Obligation-End of Period	$	1,660		$	1,525


Plan Assets at Fair Value-Beginning of Period	$	581		$	551
Actual Return on Plan Assets		70			49
Company Contributions		40			40
Benefits Paid		(55	)		(59	)

Plan Assets at Fair Value-End of Period		636		$	581


Funded Status of the Plans	$	(1,024	)	$	(944	)
December Adjustment		(31	)		(50	)

Funded Status, as of December 31	$	(1,055	)	$	(994	)

Unrecognized (a)
Net Actuarial loss (a)				$	670
Prior service cost (a)					26
Net transition obligation (a)					46

Accrued Postretirement Liability-End of Period (a)				$	(252	)


Noncurrent Assets (b)	$	—
Current Liabilities (b)	$	—
Noncurrent Liabilities (b)	$	(1,055	)

Amounts Recognized in Regulatory Assets (b)
Net Actuarial loss (b)	$	659
Prior service cost (b)	$	24
Net transition obligation (b)	$	40


(a)		– Disclosure no longer required by FAS 158, adopted in 2006, retroactive adoption not permitted.

(b)		- New disclosure required by FAS 158, adopted in 2006, retroactive adoption not permitted.

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


	2006			2005			2004
Projected Benefit Obligation
Discount rate		5.70	%		5.90	%		6.00	%

Net Benefit Costs
Discount rate		5.90	%		6.00	%		6.25	%

Expected long-term rate of return on Plan assets		8.75	%		9.0	%		9.0	%

Benefit costs were calculated assuming health care cost trend rates beginning at 9% for 2006 and decreasing to 5% in 2011 and thereafter for persons under age 65 and decreasing from 8% to 5% for persons age 65 and over. 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 $23 million and increased the accumulated benefit obligation by $207 million at December 31, 2006. 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 $19 million and would have decreased the accumulated benefit obligation by $176 million at December 31, 2006.

At December 31, 2006, 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)
2007	$	91
2008		96
2009		99
2010		102
2011		105
2012 - 2016		547

Total	$	1,040

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. As discussed in Note 2, we adopted FSP No. 106-2 in 2004, which provides guidance on the accounting for the Medicare Act. As a result of the adoption, our accumulated postretirement benefit obligation for the subsidy related to benefits attributed to past service was reduced by approximately $70 million at January 1, 2004 and was accounted for as an actuarial gain. The effects of the subsidy reduced net periodic postretirement benefit costs by $16 million in 2006, $15 million in 2005 and $12 million in 2004.

At December 31, 2006, 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)
2007	$	3
2008		3
2009		3
2010		5
2011		5
2012 - 2016		27

Total	$	46

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

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


	2006			2005
Equity Securities		68	%		68	%
Debt Securities		25			28
Other		7			4

		100	%		100	%

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. Additionally, 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. As these functions essentially support the entire DTE Energy Company, total administrative and general expenses billed to DTE Energy corporate by Detroit Edison and the other affiliates, along with certain interest and financing costs were then billed to various subsidiaries of DTE Energy, including Detroit Edison. Detroit Edison is the sponsor of a defined benefit retirement plan in which various affiliates of DTE Energy participate.

The following is a summary of transactions with affiliated companies:


(in Millions)	2006			2005			2004
Revenues
Energy sales	$	46		$	192		$	206
Other services		5			5			37
Shared capital assets		13			14			12
Costs
Power purchases		35			102			61
Other services and interest		3			7			5
Corporate expenses and merger costs (net) (1)		(86	)		(97	)		(19	)


	December 31,
(in Millions)	2006		2005
Assets
Accounts receivable	$	19	$	27

Liabilities & Equity
Accounts payable		84		51
Other liabilities (pension obligations)		295		273
Dividends payable		76		76
Dividends declared		305		305
Dividends paid		305		305
Capital contribution		150		—


(1)		As a result of an MPSC order, DTE Energy ceased billing merger costs to Detroit Edison effective January 2005.

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		Year
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

2005
Operating Revenues		990		1,035		1,409		1,028		4,462
Operating Income		149		139		264		157		709
Net Income		55		43		114		62		274

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

None.

Item 9A. 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, 2006, which is the end of the period covered by this report. Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that such controls and procedures are effective in ensuring that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.

(b) Changes in internal control over financial reporting

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

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, 2006 and 2005, 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, 2006 and December 31, 2005, and fees billed for other services rendered by Deloitte during those periods.


	2006		2005
Audit fees (1)	$	1,222,952	$	1,978,724
Audit-related fees (2)(3)		35,750		13,000
Tax fees (3)		—		—
All other fees		—		—

Total	$	1,258,702	$	1,991,724


(1)		Represents the aggregrate fees billed for the audit of Detroit Edison’s annual financial statements and for the reviews of the financial statements included in Detroit Edison’s Quarterly Reports on Form 10-Q

(2)		Represents the aggregrate fees billed for audit-related services.

(3)		Certain audit-related and tax fees are charged to DTE Energy and 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.

10-41		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.

10-42		Amendment No. 5 dated as of January 19, 2006 to the Amended and Restated Trade Receivables Purchase and Sale Agreement among Detroit Edison, CAFCO, Citibank and Citicorp, individually and as Agent dated March 9, 2001, as amended.

12-27		Computation of Ratio of Earnings to Fixed Charges.

23-19		Consent of Deloitte & Touche LLP.

31-29		Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report.

31-30		Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report.

(ii)		Exhibits incorporated herein by reference.

3(a)		Restated Articles 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 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. 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 (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 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 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)

		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)

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, 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)

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)		Trust Agreement of Detroit Edison Trust I. (Exhibit 4-9 to Registration Statement on Form S-3 (File No. 333-100000))

4(p)		Trust Agreement of Detroit Edison Trust II. (Exhibit 4-10 to Registration Statement on Form S-3 (File No. 333-100000))

4(q)		Registration Rights Agreement, dated as of February 7, 2005, between The Detroit Edison Company and the Initial Purchasers named therein. (Exhibit 4-3


		to Form 8-K dated February 7, 2005)

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)		Form of Indemnification Agreement between The Detroit Edison Company and its officers. (Exhibit 10-40 to Form 10-K for the year ended December 31, 2000)

10(g)		Certain arrangements pertaining to the employment of Anthony F. Earley, Jr. with The Detroit Edison Company, dated April 25, 1994. (Exhibit 10-53 to Form 10-Q for the quarter ended March 31, 1994)

10(h)		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(i)		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(j)		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(k)		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(l)		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(m)		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(n)		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(o)		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(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, as amended (Exhibit 99-18 to Form 10-K dated December 31, 2004)

10(s)		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)

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)

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.

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. Anthony F. Earley, Jr. Chairman of the Board and Chief Executive Officer	By	/s/ PETER B. OLEKSIAK Peter B. Oleksiak Vice President and Controller, and Chief Accounting Officer

By	/s/ SANDRA KAY ENNIS Sandra Kay Ennis Director and Corporate Secretary	By	/s/ DAVID E. MEADOR David E. Meador Director, Executive Vice President and Chief Financial Officer

By	/s/ BRUCE D. PETERSON

	Bruce D. Peterson Director

Date: March 1, 2007

Exhibit Index


Exhibit No.		Description
(i)		Exhibits filed herewith.

10-41		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.

10-42		Amendment No. 5 dated as of January 19, 2006 to the Amended and Restated Trade Receivables Purchase and Sale Agreement among Detroit Edison, CAFCO, Citibank and Citicorp, individually and as Agent dated March 9, 2001, as amended.

12-27		Computation of Ratio of Earnings to Fixed Charges.

23-19		Consent of Deloitte & Touche LLP.

31-29		Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report.

31-30		Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report.

(iii)		Exhibits furnished herewith.

32-29		Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report.

32-30		Chief Financial Officer Section 906 Form 10-K Certification of Periodic Report.


		Page
Definitions			1

Forward-Looking Statements			2

Part I
Items 1., 1A., 1B. &2.	Business, Risk Factors, Unresolved Staff Comments and Properties		3

Item 3.	Legal Proceedings		11

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		58

Item 9A.	Controls and Procedures		58

Item 9B.	Other Information		59

Part III
Item 10.	Directors, Executive Officers and Corporate Governance		59

Item 11.	Executive Compensation		59

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		59

Item 13.	Certain Relationships and Related Transactions, and Director Independence		59

Item 14.	Principal Accountant Fees and Services		59

Part IV
Item 15.	Exhibits and Financial Statement Schedules		60

Signatures			70
Amendment No.1 to the Amended & Restated Trade Receivables Purchase & Sale Agreement
Amendment No.5 to the Amended & Restated Trade Receivables Purchase & Sale Agreement
Computation of Ratio of Earnings to Fixed Charges
Conset of Deloitte & Touche LLP
Section 302 Certification of Chief Executive Officer
Section 302 Certification of Chief Financial Officer
Section 906 Certification of Chief Executive Officer
Section 906 Certification of Chief Financial Officer


	Page
Report of Independent Registered Public Accounting Firm		18

Consolidated Statement of Operations		19

Consolidated Statement of Financial Position		20

Consolidated Statement of Cash Flows		22

Consolidated Statement of Changes in Shareholder’s Equity and Comprehensive Income		23

Notes to Consolidated Financial Statements		24

Schedule II – Valuation and Qualifying Accounts		71


				Non-Qualified			Postretirement		Total Benefit Plans
(in Millions)	Qualified Plans			Plans			Plans		Plans
Increase (Decrease) in Assets and Liabilities

Accrued pension liability	$	204		$	3		$	—	$	207
Accrued postretirement liability	$	—		$	—		$	723	$	723
Intangible assets	$	(20	)	$	(1	)	$	—	$	(21	)
Regulatory assets	$	224		$	4		$	723	$	951


	Year Ending December 31,
(in Millions)	2006			2005			2004
Allowance for Doubtful Accounts (shown as deduction from accounts receivable in the consolidated statement of financial position)
Balance at Beginning of Period	$	54		$	55		$	51
Additions:
Charged to costs and expenses		53			41			45
Charged to other accounts (1)		3			4			5
Deductions (2)		(38	)		(46	)		(46	)

Balance At End of Period	$	72		$	54		$	55


(1)		Collection of accounts previously written off.

(2)		Non-collectible accounts written off.


	Twelve Months Ended December 31
(Millions of Dollars)	2006		2005		2004		2003		2002
Earnings:
Pretax earnings	$	482	$	426	$	214	$	397	$	534
Fixed charges		299		280		294		294		322

Net earnings	$	781	$	706	$	508	$	691		856


Fixed charges:
Interest expense	$	278	$	267	$	280	$	284	$	319
Adjustments		21		13		14		10		3

Fixed charges	$	299	$	280	$	294	$	294	$	322


Ratio of earnings to fixed charges		2.61		2.52		1.73		2.35		2.66

1.		I have reviewed this annual report on Form 10-K of The Detroit Edison Company;

2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.		The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

	a.		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b.		(Intentionally omitted)

	c.		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	d.		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	a.		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	b.		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


/s/ DAVID E. MEADOR David E. Meador Executive Vice President and Chief Financial Officer of The Detroit Edison Company		Date: March 1, 2007

(1)		the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)		the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.