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Restated Articles of The Detroit Edison Company, as filed December 10, 1991. (Exhibit 13-3 to Form 10-Q for quarter ended June 30, 1999)

Bylaws of The Detroit Edison Company, as amended through September 22, 1999. (Exhibit 3-14 to Form 10-Q for quarter ended September 30, 1999)

Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company (File No. 1-2198) and First Chicago Trust Company of New York as trustee (Exhibit B-1 to Registration Statement No. 2-1630) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below:

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

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

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

For the fiscal year ended December 31, 2005

Commission file number 1-2198

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

THE DETROIT EDISON COMPANY

(Exact name of registrant as specified in its charter)


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

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

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

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

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

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

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

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 associated therewith;

•		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;

•		changes in 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 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;

•		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 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.


(in millions)	2005		2004		2003
Revenue by Service
Residential	$	1,517		1,345		1,351
Commercial		1,331		1,123		1,308
Industrial		697		557		634
Wholesale		73		65		67
Other		464		234		201

Subtotal		4,082		3,324		3,561
Interconnection sales (1)		380		244		134


Total Revenue	$	4,462	$	3,568	$	3,695


(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 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 several long-term and short term contracts for a total purchase of approximately 26 million tons of low-sulfur western coal to be delivered from 2006 to 2008. We also have contracts with several suppliers for the purchase of approximately 7 million tons of Appalachian coal to be delivered from 2006 through 2008. These existing long-term coal contracts have fixed prices except for a single contract that has provisions for price escalation as well as de-escalation. We have approximately 90% of our

2006 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 Midwest Independent System Operator, a Regional Transmission Organization. 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. For example, when high temperatures occur during the summer, we require additional electricity to meet demand. This access to additional power is an efficient and economical way to meet our obligation to customers without increasing capital expenditures to build additional base-load power plants.

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, 2005 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 – Jointly Owned Utility Plant.

(4)		The Monroe Power Plant provided 38% of Detroit Edison’s total 2005 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 670 distribution substations with a capacity of approximately 32,489,000 kilovolt-amperes (kVA) and approximately 421,000 line transformers with a capacity of approximately 25,345,000 kVA. Circuit miles of distribution lines owned and in service as of December 31, 2005 are as follows:

Electric Distribution


	Circuit Miles
Operating Voltage-Kilovolts (kV)	Overhead		Underground
4.8 kV to 13.2 kV		28,104		13,379
24 kV		101		690
40 kV		2,323		327
120 kV		70		13

		30,598		14,409

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 and connect to neighboring energy companies.

Regulation

Detroit Edison’s business is subject to the regulatory jurisdiction of various agencies, including 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 our operations. In 1996, the MPSC began an initiative designed to give all of Michigan’s electric customer’s 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.

See Note 4.

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 12% of retail sales in 2005, 18% in 2004 and 12% of such sales in 2003 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, a wholly owned subsidiary of DTE Energy until February 2003. By FERC order, rates charged by ITC 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.

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	$	2,385
Water		50
Other Clean Up Sites		10
MGP Sites		3

Estimated total expenditures	$	2,448


Estimated 2006 expenditures	$	224

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 — We are required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of our facilities. Based on the results of studies to be conducted over the next four to six years, we may be required to install additional control technologies to reduce the environmental impact of the intake structures.

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.

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


Note		Title

4		Regulatory Matters
5		Nuclear Operations
13		Commitments and Contingencies

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.

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. DTE2 is a multi-year Company-wide initiative to improve existing processes and implement new core information systems. We launched the first phase of our DTE2 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.

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 MPSC has continued to regulate electric rates for our customers, while alternative electric suppliers can 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 period of electric Customer Choice many commercial customers chose alternative electric suppliers. MPSC rate orders in 2004 and 2005 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.

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.

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 approximately 4,000 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.

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.

Michigan tax reform may be costly. We are a significant taxpayer in the State of Michigan. Should the legislature change the tax laws, 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.

EMPLOYEES

We had 7,980 employees as of December 31, 2005, of which 3,961 were represented by unions. Of the represented employees, 3,487 are under a three-year contract that expires in 2007. The contract of the remaining represented employees expires in 2008.

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.

In June 2005, Detroit Edison was named as one of approximately 21 defendant utility companies in a class action lawsuit filed in the Superior Court of Justice in Ontario, Canada. Detroit Edison has not been served with this lawsuit. The plaintiffs, a class comprised of current and prior residents living in Ontario (and their respective family members and/or heirs), claim that the defendants emitted and continue to emit pollutants that have harmed the plaintiffs. As a result, the plaintiffs are seeking damages (in Canadian dollars) of approximately $49 billion for alleged negligence, approximately $4 billion per year until the defendants cease emitting pollutants, punitive and exemplary damages of $1 billion, and such other relief as the court deems appropriate. Detroit Edison is not able to predict or assess the outcome of this lawsuit at this time.

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


Note		Title

4 5 13		Regulatory Matters Nuclear Operations 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 2005, $303 million in 2004 and $295 million in 2003.

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 $124 million to $274 million in 2005 from $150 million in 2004. 2004 net income decreased $96 million from the $246 million earned in 2003. These results primarily reflect 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 expense in 2005, 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)	2005			2004
Operating Revenues	$	894		$	(127	)
Fuel and Purchased Power		705			(54	)

Gross Margin		189			(73	)
Operation and Maintenance		(87	)		63
Depreciation and Amortization		117			50
Taxes Other Than Income		(8	)		(8	)
Gains on sales of assets		(25	)		(21	)

Operating Income		192			(157	)
Other (Income) and Deductions		(20	)		26
Income Tax Provision		85			(81	)

Net Income before Accounting Change		127			(102	)
Cumulative Effect of Accounting Change		(3	)		6

Net Income	$	124		$	(96	)

Gross margins increased $189 million during 2005 and declined $73 million in 2004. Operating revenues increased due to higher demand resulting from warmer weather in 2005 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 in 2005. Gross margins were favorably impacted by decreased electric Customer Choice penetration, whereby Detroit Edison lost 12% of retail sales to electric Customer Choice customers in 2005 and 18% of such sales during 2004 as retail customers migrated back to Detroit Edison as their electric generation provider rather than remaining with alternative suppliers. 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)	2005			2004
Weather related margin	$	166		$	(25	)
MPSC 2004 rate orders		116			22
Unrecovered power supply costs – residential customers		(73	)		—
Transmission charges (1)		(93	)		—
Electric Customer Choice program		79			(82	)
Service territory economic performance		(23	)		9
Other, net		17			3

Increase in gross margin performance	$	189		$	(73	)


(1)		Transmission expenses were recorded in operation and maintenance expense in 2004.

Operating revenues and fuel and purchased power costs increased in 2005 reflecting a $8.79 per MWh (58%) increase in fuel and purchased power costs during the year. Fuel and purchased power costs are a pass-through

with the reinstatement of the PSCR mechanism, except for residential customers whose rate caps expired in January 2006.

The increase in power supply costs was driven by higher seasonal demand, higher purchased power rates, higher coal prices and increased power purchases due to weather and plant outages. 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 decline in 2004 revenues was partially offset by increased base rates resulting from the interim and final rate orders. Revenues in 2004 were adversely impacted by reduced cooling demand resulting from mild summer weather. In addition, operating revenues and fuel and purchased power costs decreased in 2004 reflecting a $1.27 per MWh (8%) decline in fuel and purchased power costs. The loss of retail sales under the electric Customer Choice program also resulted in lower purchase power requirements, as well as excess power capacity that was sold in the wholesale market. Under the 2004 interim and final rate orders, revenues from selling excess power reduce the level of recoverable fuel and purchased power costs and, therefore, do not impact margins associated with uncapped customers.

The rate orders also lowered PSCR revenues, which were partially offset by increased base rate and transition charge revenues. Since fuel and purchased power costs are a pass-through with the reinstatement of the PSCR in 2004, a decrease affects both revenues and fuel and purchased power costs but does not affect margins or earnings associated with uncapped customers. The decrease in fuel and purchased power costs is attributable to lower priced purchases and the use of a more favorable power supply mix driven by higher generation output. The favorable mix is due to lower purchases, driven by lost sales under the electric Customer Choice program.


Power Generated and Purchased
(in Thousands of MWh)	2005					2004					2003
Power Plant Generation
Fossil		40,756		73	%		39,432		75	%		38,052		72	%
Nuclear		8,754		16			8,440		16			8,114		16

		49,510		89			47,872		91			46,166		88
Purchased Power		6,378		11			4,650		9			6,354		12

System Output		55,888		100	%		52,522		100	%		52,520		100	%
Less Line Loss and Internal Use		(3,205	)				(3,574	)				(3,248	)

Net System Output		52,683					48,948					49,272


Average Unit Cost ($/MWh)
Generation (1)	$	15.47				$	12.98				$	12.89

Purchased Power	$	89.37				$	37.06				$	41.73

Overall Average Unit Cost	$	23.90				$	15.11				$	16.38


(1)		Represents fuel costs associated with power plants.


(in Thousands of MWh)	2005		2004		2003
Electric Sales
Residential		16,812		15,081		15,074
Commercial		15,618		13,425		15,942
Industrial		12,317		11,472		12,254
Wholesale		2,329		2,197		2,241
Other		390		401		402

		47,466		42,576		45,913
Interconnection sales (1)		5,217		6,372		3,359

Total Electric Sales		52,683		48,948		49,272


Electric Deliveries
Retail and Wholesale		47,466		42,576		45,913
Electric Choice		6,760		9,245		6,193
Electric Choice – Self Generators (2)		518		595		1,088

Total Electric Sales and Deliveries		54,744		52,416		53,194


(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 decreased $87 million in 2005 and increased $63 million in 2004. As a result of the MPSC final rate order, transmission and MISO expenses in 2005 are now included in purchased power expense with related revenues recorded through the PSCR mechanism. In addition, as a result of the MPSC final rate order, merger interest is no longer allocated from the DTE Energy parent company to Detroit Edison. Partially offsetting the lack of merger interest expense and the transmission expense accounting reclassification were higher 2005 storm expenses.

The 2004 increase reflects costs associated with maintaining our generation fleet, including costs of scheduled and forced plant outages. Additionally, the increase in 2004 is due to incremental costs associated with the implementation of our DTE2 project.

Operation and maintenance expense in both years includes higher employee pension and health care benefit costs due to financial market performance, discount rates and health care cost trend rates, and increased reserves for uncollectible accounts receivable, reflecting high past-due amounts attributable to economic conditions. In addition, we accrued a refund due from the Midwest Independent System Operator in 2004 for transmission services.

Depreciation and amortization expense increased $117 million in 2005 and increased $50 million in 2004. The increases reflect the income effect of recording regulatory assets, which lowered depreciation and amortization expenses. The regulatory asset deferrals totaled $46 million in 2005, $107 million in 2004 and $153 million in 2003, representing net stranded costs and other costs we believe are recoverable under Public Act (PA) 141. Additionally, higher 2005 sales volumes compared to 2004 resulted in greater amortization of regulatory assets.

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

Other income and deductions expense decreased $20 million in 2005 and increased $26 million in 2004. 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. The 2004 increase is primarily due to lower income associated with recording a return on regulatory assets, as well as costs associated with addressing the structural issues of PA 141.

Outlook — We continue to improve the operating performance of Detroit Edison. During the past year we have resolved many of our regulatory issues and continue to pursue additional regulatory solutions for structural problems within our competitive environment, mainly 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 improve performance. Looking forward, additional issues, such as rising prices for coal, uranium and health care, continued under-performance of Michigan’s economy and 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 Operating System and the Performance Excellence Process to seek opportunities to improve productivity, remove waste, 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 facility, with an estimated cost of $1 billion to $2 billion.

The following variables, either in combination or acting alone, will 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;

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

	•		plant performance;

	•		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.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES

In the fourth quarter of 2005, we adopted additional new accounting rules for asset retirement obligations. The cumulative effect of adopting these new accounting rules reduced 2005 earnings by $3 million.

On January 1, 2003, we adopted a new accounting rule for asset retirement obligations. The cumulative effect of adopting this new accounting rule reduced 2003 earnings by $6 million.

See Note 2.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Detroit Edison has commodity price risk arising from market price fluctuations in conjunction with the anticipated purchases of coal, uranium and electricity to meet its obligations during periods of peak demand. To limit our exposure to commodity price fluctuations, we have entered into electricity option contracts. Commodity price risk is limited due to the PSCR mechanism (See Note 1).

See Note 12.

Interest Rate Risk

Detroit Edison is subject to interest rate risk in connection with the issuance of debt securities. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). We estimate that if interest rates were 10% higher or lower, the fair value of long-term debt at December 31, 2005 would decrease $183 million and increase $199 million, respectively.

Credit Risk

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

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, 2005 and 2004 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, 2005. 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, 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 a new accounting principle, in 2005 and in 2003 the Company changed its method of accounting for asset retirement obligations.

/S/ DELOITTE & TOUCHE LLP

Detroit, Michigan
March 7, 2006

The Detroit Edison Company

Consolidated Statement of Operations


	Year Ended December 31
(in Millions)	2005			2004			2003
Operating Revenues	$	4,462		$	3,568		$	3,695


Operating Expenses
Fuel and purchased power		1,590			885			939
Operation and maintenance		1,308			1,395			1,332
Depreciation and amortization		640			523			473
Taxes other than income		241			249			257
Asset (gains) and losses, net		(26	)		(1	)		20

		3,753			3,051			3,021


Operating Income		709			517			674


Other (Income) and Deductions
Interest expense		267			280			284
Interest income		(3	)		—			(7	)
Other income		(27	)		(34	)		(66	)
Other expenses		46			57			66

		283			303			277


Income Before Income Taxes		426			214			397

Income Tax Provision		149			64			145


Income Before Accounting Change		277			150			252

Cumulative Effect of Accounting Change (Note 2)		(3	)		—			(6	)


Net Income	$	274		$	150		$	246

See Notes to Consolidated Financial Statements

The Detroit Edison Company

Consolidated Statement of Financial Position


	December 31
(in Millions)	2005			2004
Assets
Current Assets
Cash and cash equivalents	$	26		$	6
Restricted cash		84			75
Accounts receivable
Customer (less allowance for doubtful accounts of $54 and $55, respectively)		305			258
Accrued unbilled revenues		223			207
Accrued power supply cost recovery revenue		144			—
Other		112			120
Inventories
Fuel		123			100
Materials and supplies		116			118
Notes receivable from affiliate (Note 15)		—			85
Other		43			46

		1,176			1,015


Investments
Nuclear decommissioning trust funds		646			590
Other		65			55

		711			645


Property
Property, plant and equipment		13,416			12,931
Less accumulated depreciation (Notes 1 and 2)		(5,595	)		(5,354	)

		7,821			7,577


Other Assets
Regulatory assets (Note 4)		2,006			2,053
Securitized regulatory assets (Note 4)		1,340			1,438
Other		115			114

		3,461			3,605


Total Assets	$	13,169		$	12,842

See Notes to Consolidated Financial Statements

The Detroit Edison Company
Consolidated Statement of Financial Position


	December 31
(in Millions, Except Shares)	2005			2004
Liabilities and Shareholder’s Equity
Current Liabilities
Accounts payable	$	392		$	346
Accrued interest		79			79
Dividends payable (Note 15)		76			76
Accrued payroll		12			12
Accrued vacations		80			76
Short-term borrowings		163			—
Accrued power supply cost recovery refund		129			112
Current portion long-term debt, including capital leases		135			499
Other		196			130

		1,262			1,330


Other Liabilities
Deferred income taxes		1,961			1,941
Regulatory liabilities (Notes 2 and 4)		224			253
Asset retirement obligations (Note 2)		953			869
Unamortized investment tax credit		115			125
Nuclear decommissioning (Notes 2 and 5)		85			77
Accrued pension liability		261			247
Other		787			676

		4,386			4,188


Long-Term Debt (net of current portion) (Note 9)
Mortgage bonds, notes and other		3,221			2,879
Securitization bonds		1,295			1,400
Capital lease obligations		57			66

		4,573			4,345


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
Premium on common stock		1,104			1,104
Common stock expense		(44	)		(44	)
Retained earnings		500			531
Accumulated other comprehensive income		2			2

		2,948			2,979


Total Liabilities and Shareholder’s Equity	$	13,169		$	12,842

See Notes to Consolidated Financial Statements

The Detroit Edison Company

Consolidated Statement of Cash Flows


	Year Ended December 31
(in Millions)	2005			2004			2003
Operating Activities
Net Income	$	274		$	150		$	246
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		640			523			473
Deferred income taxes		40			142			32
Loss (gain) on sale of assets		(26	)		(1	)		21
Cumulative effect of accounting change		3			—			6
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		98			376			(13	)

Net cash from operating activities		1,029			1,190			765


Investing Activities
Plant and equipment expenditures		(722	)		(702	)		(580	)
Proceeds from sale of assets, net		30			1			2
Restricted cash for debt redemptions		(9	)		6			49
Notes receivable from affiliate		85			(78	)		50
Proceeds from sale of nuclear decommissioning trust fund assets		201			254			199
Investment in nuclear decommissioning trust funds		(235	)		(287	)		(231	)
Other investments		(71	)		(33	)		(94	)

Net cash used for investing activities		(721	)		(839	)		(605	)


Financing Activities
Issuance of long-term debt		857			266			49
Redemption of long-term debt		(997	)		(206	)		(504	)
Short-term borrowings, net		163			(100	)		100
Capital contribution by parent company		—			—			470
Dividends on common stock		(305	)		(303	)		(295	)
Other		(6	)		(8	)		(10	)

Net cash used for financing activities		(288	)		(351	)		(190	)


Net Increase (Decrease) in Cash and Cash Equivalents		20			—			(30	)
Cash and Cash Equivalents at Beginning of the Period		6			6			36

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

See Notes to Consolidated Financial Statements

The Detroit Edison Company

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


					Premium								Accumulated
					On		Common						Other
	Common Stock				Common		Stock			Retained			Comprehensive
	Shares		Amount		Stock		Expense			Earnings			Income (Loss)			Total
(Dollars in Millions,
Shares in Thousands)

Balance, December 31, 2002		134,288	$	1,343	$	507	$	(44	)	$	735		$	(419	)	$	2,122

Net income		—		—		—		—			246			—			246
Dividends declared on Common stock		—		—		—		—			(295	)		—			(295	)
Net change in unrealized losses on derivatives, net of tax		—		—		—		—			—			3			3
Pension obligation (Note 14)		—		—		—		—			—			417			417
Capital contribution by parent company		—		—		470		—			—			—			470

Balance, December 31, 2003		134,288		1,343		977		(44	)		686			1			2,963

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

Balance, December 31, 2004		138,632		1,386		1,104		(44	)		531			2			2,979

Net income		—		—		—		—			274			—			274
Dividends declared on Common stock		—		—		—		—			(305	)		—			(305	)

Balance, December 31, 2005		138,632	$	1,386	$	1,104	$	(44	)	$	500		$	2		$	2,948

The following table displays comprehensive income (loss):


(in Millions)	2005		2004		2003
Net income	$	274	$	150	$	246

Other comprehensive income (loss), net of tax:
Net unrealized losses on derivatives:
Gains or (losses) arising during the period, net of taxes of $-, $- and $4		—		—		8
Amounts reclassified to income, net of taxes of $-, $- and $(3)		—		—		(5	)

		—		—		3
Net change in unrealized gain on investments, net of taxes of $-, $- and $-		—		1		—
Pension obligations, net of taxes of $-, $- and $224 (Notes 4 and 14)		—		—		417

Comprehensive income	$	274	$	151	$	666

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. For a detailed discussion of FIN 46-R see Note 2.

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.

We reclassified certain prior year balances to match the current year’s financial statement presentation.

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. Prior to 2004, Detroit Edison’s retail rates were frozen under Public Act (PA) 141. Accordingly, Detroit Edison did not accrue revenues under the PSCR mechanism prior to 2004. See Note 4.

Comprehensive Income

Comprehensive income is the change in common shareholders’ 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, 2005 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		—		—		—

Ending balance	$	1	$	1	$	2

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)	2005			2004
Property, Plant and Equipment
Generation	$	7,375		$	7,100
Distribution		6,041			5,831

Total		13,416			12,931


Less Accumulated Depreciation and Depletion
Generation		(3,439	)		(3,277	)
Distribution		(2,156	)		(2,077	)

Total		(5,595	)		(5,354	)


Net Property, Plant and Equipment	$	7,821		$	7,577

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, is charged to accumulated depreciation.

Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2. Approximately $25 million of expenses related to the anticipated Fermi 2 refueling outage scheduled for 2006 were accrued at December 31, 2005. Amounts are being accrued on a pro-rata basis over an 18-month period that began in November 2004. 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 also matches the regulatory recovery of these costs in rates set by the MPSC.

We base depreciation provisions for utility property on straight-line rates approved by the MPSC. The composite depreciation rate for Detroit Edison was 3.4% in 2005, 2004 and 2003.

The average estimated useful life for our generation and distribution property was 39 years and 37 years, respectively, at December 31, 2005.

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

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, including Software Costs

Our intangible assets consist primarily of software. 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, either 5 or 15 years. Intangible assets amortization expense was $33 million in 2005, $32 million in 2004 and $30 million in 2003. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2005 were $346 million and $121 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2004 were $253 million and $88 million, respectively. Amortization expense of intangible assets is estimated to be $34 million annually for 2006 through 2010.

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 and have recorded such investments at market value with unrealized gains or losses included in earnings. Changes in the fair value of nuclear decommissioning-related investments are recorded as adjustments to regulatory assets or liabilities. See Note 5.

Affiliate Transactions

Detroit Edison shares costs with or incurs costs on behalf of unconsolidated affiliated companies. Prior to September 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)	2005			2004			2003
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	(29	)	$	91		$	13
Accrued unbilled receivables		(16	)		(11	)		(19	)
Inventories		(21	)		14			18
Accrued pensions		41			123			(179	)
Accounts payable		46			135			(27	)
Accrued power supply cost recovery refund		(127	)		112			—
Accrued payroll		—			(15	)		3
Income taxes payable		(10	)		(14	)		(24	)
General taxes		(1	)		(13	)		(7	)
Risk management and trading activities		—			(1	)		(7	)
Postretirement obligation		110			11			93
Other assets		58			(17	)		71
Other liabilities		47			(39	)		52

	$	98		$	376		$	(13	)

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

Consolidation of Variable Interest Entities

In January 2003, FIN 46, Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin (ARB) No. 51 was issued and requires an investor with a majority of the variable interests (primary beneficiary) in a variable interest entity to consolidate the assets, liabilities and results of operations of the entity. A variable interest entity is an entity in which the equity investors do not have controlling interests, the equity investment at risk is insufficient to finance the entity’s activities without receiving additional subordinated financial support from other parties, or equity investors do not share proportionally in gains or losses.

In October 2003 and December 2003, the FASB issued Staff Position No. FIN 46-6 and FIN 46-Revised (FIN 46-R), respectively, which clarified and replaced FIN 46 and also provided for the deferral of the effective date of FIN 46 for certain variable interest entities. We have evaluated all of our equity and non-equity interests and have adopted all current provisions of FIN 46-R. The adoption of FIN 46-R did not have a material effect on our financial statements.

Medicare Act Accounting

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law. The Medicare Act 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. We elected at that time to defer the provisions of the Medicare Act, and its impact on our accumulated postretirement benefit obligation and net periodic postretirement benefit cost pending the issuance of specific authoritative accounting guidance by the FASB.

In May 2004, FASB Staff Position (FSP) No. 106-2 was issued on accounting for the effects of the Medicare Act. The guidance in this FSP is applicable to sponsors of single-employer defined benefit postretirement health care plans for which (a) the employer has concluded the prescription drug benefits available under the plan to some or all participants are “actuarially equivalent” to Medicare Part D and thus qualify for the subsidy under the Medicare Act and (b) the expected subsidy will offset or reduce the employer’s share of the cost of the underlying postretirement prescription drug coverage on which the subsidy is based. We believe we qualify for the subsidy under the Medicare Act and the expected subsidy will partially offset our share of the cost of postretirement prescription drug coverage.

In June 2004, we adopted FSP No. 106-2, retroactive to January 1, 2004. 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 and was accounted for as an actuarial gain. The effects of the subsidy reduced net postretirement costs by $15 million in 2005 and $12 million in 2004.

Asset Retirement Obligations

On January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations, which requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred. We identified a legal retirement obligation for the decommissioning costs for our Fermi 1 and Fermi 2 nuclear plants.

On December 31, 2005, we adopted FASB Interpretation FIN No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. FIN 47 clarifies that the term conditional asset retirement obligation as used in FASB Statement No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a

future event. FIN 47 also clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if fair value can be reasonably estimated. The accounting for FIN 47 uses the same methodology as SFAS 143. When a new liability is recorded, an entity will capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

We believe that adoptions of SFAS No. 143 and FIN 47 result primarily in timing differences in the recognition of legal asset retirement costs that we are currently recovering in rates. We will be deferring 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 identified conditional retirement obligations for the disposal of asbestos at certain of our power plants. To a lesser extent, we have conditional retirement obligations at certain service centers, and PCB disposal costs within transformers and circuit breakers. 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.

If we had applied FIN 47 to prior periods, we would have recorded asset retirement obligations of $32 million as of December 31, 2004 and 2003, with an immaterial effect on earnings.

No liability has been recorded with respect to lead-based paint, as the quantities of lead-based paint 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 liability has been recorded for this asset.

A reconciliation of the asset retirement obligation for 2005 follows:


(in Millions)
Asset retirement obligations at January 1, 2005	$	869
Accretion		58
Liabilities incurred (primarily adoption of FIN 47)		32
Liabilities settled		(6	)

Asset retirement obligations at December 31, 2005	$	953

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.

NOTE 3 — DISPOSITIONS

Steam Heating Business

In January 2003, we sold our steam heating business to Thermal Ventures II, LP. Due to our continuing involvement in the steam heating business, including the commitment to purchase steam and/or electricity

through 2024, fund certain capital improvements and guarantee the buyer’s credit facility, we recorded a net of tax loss of approximately $14 million in 2003. As a result of our continuing involvement, this transaction is not considered a sale for accounting purposes. See Note 13.

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)	2005			2004
Assets
Securitized regulatory assets	$	1,340		$	1,438


Recoverable income taxes related to securitized regulatory assets	$	734		$	788
Recoverable minimum pension liability		543			604
Asset retirement obligation		196			183
Other recoverable income taxes		104			109
Recoverable costs under PA 141
Net stranded costs		112			122
Excess capital investment		22			7
Deferred Clean Air Act expenditures		82			76
Midwest Independent System Operator charges		56			27
Electric Customer Choice implementation costs		98			95
Enhanced security costs		13			8
Unamortized loss on reacquired debt		41			29
Accrued PSCR revenue		144			—
Other		5			5

		2,150			2,053
Less amount included in current assets		(144	)		—


(in Millions)	2005			2004
	$	2,006		$	2,053


Liabilities
Asset removal costs	$	213		$	250
Accrued PSCR refund		129			112
Accrued pension		11			—
Other		2			3

		355			365
Less amount included in current liabilities		(131	)		(112	)

	$	224		$	253

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 minimum pension liability — An additional minimum pension liability was recorded under generally accepted accounting principles due to the current under funded status of certain pension plans. The traditional rate setting process allows for the recovery of pension costs as measured by generally accepted accounting principles. Accordingly, the minimum pension liability is recoverable. 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 occur when fixed cost related revenues do not cover the fixed cost revenue requirements.

•		Excess capital investment — 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.

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 Detroit Edison’s customers representing the difference created from volatility in the pension obligation and amounts recognized pursuant to MPSC authorization.

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 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 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 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.

2004 PSCR Reconciliation and 2004 Net Stranded Cost Case

In accordance with the MPSC’s direction in Detroit Edison’s November 2004 final 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. The combined proceeding will provide a comprehensive true-up of the 2004 PSCR and production fixed cost stranded cost calculations, including treatment of Detroit Edison’s third party wholesale sales revenues. Under the MPSC’s preferred methodology, Detroit Edison incurred approximately $112 million in stranded costs for 2004. Detroit Edison also received approximately $218 million in third party wholesale sales.

In the filing, Detroit Edison recommended the following distribution of the $218 million of third party wholesale sale revenues: $91 million to offset PSCR fuel expense and $74 million to offset 2004 production operation and maintenance expense. The remaining $53 million would be allocated between bundled customers and electric Customer Choice customers. This allocation would result in a refund of approximately $8 million to bundled customers and a net stranded cost amount to be collected from electric Customer Choice customers of approximately $99 million.

Included with the application was the filing of a motion for a temporary interim order requesting the continuation of the existing electric Customer Choice transition charges until a final order is issued. The MPSC denied this motion in August 2005. A final order is expected in the first half of 2006.

Electric Industry Restructuring

Electric Rates, Customer Choice and Stranded Costs — 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.

In July 2003, the MPSC issued an order finding that Detroit Edison had no net stranded costs in 2000 and 2001. Detroit Edison filed a petition for rehearing of the July 2003 order, which the MPSC denied in December 2003. The MPSC’s November 2004 order authorized recovery of $44 million of historical stranded costs incurred in 2002, 2003 and January and February 2004 collectible from electric Customer Choice customers through transition charges. From March 2004 through the first quarter of 2005, Detroit Edison recorded $112 million of additional stranded costs as a regulatory asset as the result of rate caps and higher electric Customer Choice sales losses than included in the 2004 MPSC interim order. In March of 2005, Detroit Edison filed an application for its 2004 stranded cost recovery case. A final order is expected in the first quarter of 2006.

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.

DTE2 Accounting

In July 2004, Detroit Edison filed an accounting application with the MPSC requesting authority to capitalize and amortize DTE2 costs, 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 DTE2 costs that would otherwise be expensed, as a regulatory asset for future rate recovery starting January 1, 2006. In addition, DTE2 costs recorded as plant assets will be amortized over a 15-year period.

Power Supply 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 are power supply costs, transmission expenses and nitrogen oxide 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.

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 power supply costs, transmission expenses, MISO market participation costs, and nitrogen oxide 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 fuel additives. In conjunction with DTE Energy’s sale of the transmission assets of ITC in February 2003, the FERC froze ITC’s transmission rates through December 2004. In approving the sale, FERC authorized ITC recovery of the difference between the revenue it would have collected and the actual revenue ITC did collect during the rate freeze period. At December 31, 2005 this amount is estimated to be $66 million which is to be included in ITC’s rates over a five-year period beginning June 1, 2006. It is expected that this amortization will increase Detroit Edison’s transmission expense in 2006 by $7 million. As previously discussed, Detroit Edison received rate orders in 2004 that allow for the recovery of 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.

Administrative and General Expenses Report to the MPSC

In October 2005, the MPSC ordered Detroit Edison to file a report on why its administrative and general expenses appear to be higher than levels incurred by Consumers Energy, Michigan’s other major electric utility. On February 1, 2006, a report was filed that explained Detroit Edison’s administrative and general expense differences, as well as its overall cost and rate competitiveness.

Emergency Rules for Electric Bills

In October 2005, the MPSC established emergency billing practices in effect for electric services rendered November 1, 2005 through March 31, 2006. The rule changes:

	•		lengthen the period of time before a bill is due once it is transmitted to the customer;

	•		prohibit shut off or late payment fees unless an actual meter read is made;

	•		limit the required monthly payment on a settlement agreement;

	•		increase the income level qualifying for shut-off protection and lower the payment required to remain on shut-off protection; and

	•		lessen or eliminate certain deposit requirements.

Transmission Proceedings

In November 2004, a FERC order approved a transmission pricing structure to facilitate seamless trading of electricity between MISO and the PJM Interconnection. The pricing structure eliminates layers of transmission charges between the two regional transmission organizations. The FERC noted that the new pricing structure may result in transmission owners facing abrupt revenue shifts. To facilitate the transition to the new pricing structure, the FERC authorized a Seams Elimination Cost Adjustment (SECA), effective from December 2004 through March 2006. Under MISO’s filing with the FERC, Detroit Edison’s SECA obligation was approximately $2 million per month from December 2004 through March 2005 and approximately $1 million per month from April 2005 through March 2006. In December 2004, Detroit Edison filed a request for rehearing with the FERC which states, among other things, that SECA is retroactive ratemaking and is unlawful under the Federal Power Act. FERC has not ruled on the Company’s request for rehearing. However in February 2005, FERC ordered hearings to review the proposed SECA charges. The charges are being collected subject to refund. Hearings on this matter are scheduled to conclude in late 2006. Under the MPSC’s November 2004 final rate order, transmission expenses are recoverable through the PSCR mechanism. Therefore, SECA charges, if ultimately imposed, should not have a financial impact to Detroit Edison.

Minimum Pension Liability

In December 2002, we recorded an additional minimum pension liability as required under SFAS No. 87, with offsetting amounts to an intangible asset and other comprehensive income. During 2003, the MPSC Staff provided an opinion that the MPSC’s traditional rate setting process allowed for the recovery of pension costs as measured by SFAS No. 87. Based on the MPSC Staff opinion, management believes that it will be allowed to recover in rates the minimum pension liability associated with its utility operations and as such the amount was reclassified to a regulatory asset. At December 31, 2005 and 2004, we have recorded a regulatory asset of approximately $543 million ($353 million net of tax) and $604 million ($393 million net of tax), respectively. See Note 14.

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.

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 $30 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 2041. It is estimated that the cost of decommissioning Fermi 2, when its license expires in 2025, will be $1.1 billion in 2005 dollars and $3.4 billion in 2025 dollars, using a 6% inflation rate. In 2001, the company 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 decommissioning and the disposal of low-level radioactive waste through a revenue surcharge. The amounts recovered from customers are deposited in the restricted external trust accounts to fund decommissioning.


(in Millions)	2005		2004		2003
Revenue	$	40	$	38	$	36
Net unrealized investment gains		—		17		62

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


(in Millions)	As of December 31,
Decommissioning trust funds	2005		2004
Fermi 2	$	601	$	546
Fermi 1		18		18
Low level radioactive waste		27		26

Total	$	646	$	590

At December 31, 2005, investments in the external trust consisted of approximately 49% in publicly traded equity securities, 44% 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.

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 estimates that existing storage capacity will be sufficient until 2007. We plan expansion of our spent fuel storage capacity that will meet our requirements through 2010. 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, 2005 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)	$	1,571	$	167
Accumulated depreciation (in Millions)	$	778	$	92


*		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.

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


(Dollars in Millions)
	2005			2004			2003

Income tax expense at 35% statutory rate	$	149		$	75		$	139

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

Total	$	149		$	64		$	145

Effective federal income tax rate		35.0	%		29.9	%		36.5	%

Components of income tax expense were as follows:


(in Millions)	2005		2004			2003
Current federal and other income tax expense (benefit)	$	110	$	(78	)	$	109
Deferred federal and other income tax expense		39		142			36


Total	$	149	$	64		$	145

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)	2005			2004
Property	$	(1,179	)	$	(1,147	)
Securitized regulatory assets		(723	)		(778	)
Pension and benefits		92			26
Other, net		(147	)		(17	)

	$	(1,957	)	$	(1,916	)


Deferred income tax liabilities	$	(2,328	)	$	(2,326	)
Deferred income tax assets		371			410

	$	(1,957	)	$	(1,916	)

The above table excludes deferred tax liabilities associated with unamortized investment tax credits which are shown separately on the consolidated statement of financial position.

During 2005, the IRS completed and closed its audits of Detroit Edison as a component of the DTE Energy federal income tax returns for the years 1998 through 2001. The IRS is currently conducting audits of Detroit Edison as a component of the DTE Energy federal income tax returns for the years 2002 and 2003. The Company accrues 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, 2005, the Company had accrued approximately $5 million for such uncertainties. We believe that our accrued tax liabilities are adequate for all years.

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 of debt outstanding at December 31, 2005 were:


(in Millions)	2005			2004
Detroit Edison Taxable Debt, Principally Secured
5.8% (1) due 2010 to 2037	$	2,030		$	1,672

Detroit Edison Tax Exempt Revenue Bonds (2)
5.3% (1) due 2008 to 2032		1,145			1,145
Quarterly Income Debt Securities (QUIDS)
7.5% (1) due 2026 to 2028		—			385
Other Long-Term Debt		67			74

		3,242			3,276
Less amount due within one year		(21	)		(397	)

	$	3,221		$	2,879


Securitization Bonds	$	1,400		$	1,496
Less amount due within one year		(105	)		(96	)

	$	1,295		$	1,400


(1)		Weighted average interest rate as of December 31,2005

(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 2005, we issued the following long-term debt:

(in Millions)

Month

Company

Issued

Type

Interest Rate

Maturity

Amount

Detroit Edison

February

Senior Notes (1)

4.80%

February 2015

200

Detroit Edison

February

Senior Notes (1)

5.45%

February 2035

200

Detroit Edison

August

Tax Exempt Revenue Bonds (2)

variable

August 2029

119

Detroit Edison

September

Senior Notes (3)

5.19%

October 2023

100

Detroit Edison

October

Senior Notes (4)

5.70%

October 2037

250

Total Issuances

869


(1)		The proceeds from the issuance were used to redeem QUIDS of Detroit Edison

(2)		The proceeds from the issuance were used to refinance Tax Exempt Revenue Bonds of Detroit Edison

(3)		The proceeds from the issuance were used to redeem Senior Notes of Detroit Edison

(4)		The proceeds from the issuance were used to repay short term borrowings of Detroit Edison

Debt Retirements and Redemptions

The following debt was retired, through optional redemption or payment at maturity, during 2005.

(in Millions)

Month

Company

Retired

Type

Interest Rate

Maturity

Amount

Detroit Edison

February

Senior Notes

7.500%

February 2005

Detroit Edison

February

Remarketed Senior Notes

7.000%

August 2034

100

Detroit Edison

March

QUIDS (1)

7.625%

March 2026

185

Detroit Edison

March

QUIDS (1)

7.540%

June 2028

100

Detroit Edison

March

QUIDS (1)

7.375%

December 2028

100

Detroit Edison

September

Tax Exempt Revenue Bond (2)

6.400%

September 2025

Detroit Edison

September

Tax Exempt Revenue Bond (2)

6.200%

August 2025

Detroit Edison

October

Senior Notes (3)

5.050%

October 2005

200

Total Retirements

880


(1)		The QUIDS were redeemed with the proceeds from issuance of Senior Notes by Detroit Edison

(2)		These Tax Exempt Revenue Bonds were redeemed with the proceeds from issuance of new Detroit Edison Tax Exempt Revenue Bonds

(3)		These Senior Notes were paid at maturity with the proceeds from the issuance of Senior Notes by Detroit Edison and short-term borrowings

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


											2011 &
(in millions)	2006		2007		2008		2009		2010		thereafter		Total

Amount to mature	$	126	$	135	$	178	$	158	$	667	$	3,384	$	4,648

Remarketable Securities

At December 31, 2004, $175 million of notes were subject to periodic remarketings. The $100 million scheduled to remarket in February 2005 was optionally redeemed, and no remarketings will take place in 2006. We direct the remarketing agents to remarket these securities at the lowest interest rate necessary to produce a par bid. In the event that a remarketing fails, we would be required to purchase the securities.

Quarterly Income Debt Securities (QUIDS)

Detroit Edison had three series of QUIDS outstanding at December 31, 2004. Detroit Edison redeemed all of its outstanding QUIDS on March 4, 2005.

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, 2005, 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 and restated its existing $206 million, five-year facility entered into in October 2004. Our aggregate availability under the combined facilities is $275 million. The new five-year credit facility replaced the October 2003 three-year $69 million revolving credit facility. 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 l. Should we have delinquent obligations of at least $50 million to any creditor, such delinquency will be considered a default under our credit agreements. Detroit Edison is currently in compliance with its covenants.

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 no balance outstanding under this financing agreement at December 31, 2005 and 2004.

At December 31, 2005, we had outstanding commercial paper of $163 million. There were no outstanding commercial paper balances at December 31, 2004.

The weighted average interest rate for short-term borrowings was 4.4% at December 31, 2005.

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 2024.

Future minimum lease payments under non-cancelable leases at December 31, 2005 were:


	Capital			Operating
(in Millions)	Leases			Leases
2006	$	13		$	32
2007		10			27
2008		11			22
2009		11			16
2010		9			13
Thereafter		29			104

Total minimum lease payments		83		$	214

Less imputed interest		(17	)

Present value of net minimum lease payments		66
Less current portion		(9	)

Non-current portion	$	57

Rental expense for operating leases was $37 million in 2005, $37 million in 2004 and $30 million in 2003.

NOTE 12 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

We comply with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138 and SFAS No. 149. 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 a derivative instrument qualifying as a hedge and 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 a derivative instrument qualifying as a hedge and 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 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, 2005. Our commodity price risk is limited due to the PSCR mechanism (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.

2005

2004

Fair Value

Carrying Value

Fair Value

Carrying Value

Long-Term Debt

$4.8 billion

$4.6 billion

$5.1 billion

$4.8 billion

NOTE 13 — COMMITMENTS AND CONTINGENCIES

Environmental

Air — Detroit Edison is subject to EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. In March 2005, EPA issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, Detroit Edison has spent approximately $644 million through 2005. We estimate Detroit Edison future capital expenditures at up to $218 million in 2006 and up to $2.2 billion of additional capital expenditures through 2018 to satisfy both the existing and proposed new control requirements. Under the June 2000 Michigan restructuring legislation, beginning January 1, 2004, annual return of and on this capital expenditure could be deferred in ratemaking, until December 31, 2005, the expiration of the rate cap period.

Water — 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. It is estimated that we will incur up to $50 million over the next four to six years in additional capital expenditures for Detroit Edison.

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 $13 million which was accrued in 2005 and is expected to be incurred over the next several years.

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 have taken legal action attempting to prevent the STC from implementing the new valuation tables and have continued to prepare assessments based on the superseded tables. The legal actions regarding the appropriateness of the new tables were before the Michigan Tax Tribunal (MTT) which, in April 2002, issued a decision essentially affirming the validity of the STC’s new tables. In June 2002, petitioners in

the case filed an appeal of the MTT’s decision with the Michigan Court of Appeals. In January 2004, the Michigan Court of Appeals upheld the validity of the new tables. With no further appeal by the petitioners available, the MTT began to schedule utility personal property valuation cases for Prehearing General Calls. After a period of abeyance the MTT issued a scheduling order in a significant number of Detroit Edison appeals that set litigation calendars for these cases extending into mid-2006. After an extended period of settlement discussions, a Memorandum of Understanding has been reached with six principals in the litigation and the Michigan Department of Treasury that is expected to lead to settlement of all outstanding property tax disputes on a global basis.

On December 8, 2005, executed Stipulations for Consent Judgment, Consent Judgments, and Schedules to Consent Judgment were filed with the MTT on behalf of Detroit Edison 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 global settlement agreement and resolves a number of claims by the litigants against each other including both property and non-property issues. The global settlement agreement results in an economic benefit to Detroit Edison that includes the release of a litigation reserve.

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 $42 million of steam and electricity in 2005 and 2004 and $39 million in 2003. We estimate steam and electric purchase commitments through 2024 will not exceed $427 million. As discussed in Note 3, 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 $20 million for future commitments. Also, we have guaranteed bank loans that Thermal Ventures II, LP may use for capital improvements to the steam heating system.

As of December 31, 2005, 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 2006 base level capital expenditures will be $800 million. We have made certain commitments in connection with expected capital expenditures.

Bankruptcies

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

Other

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

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 net income amounts for any interim period in 2004. Accordingly, all amounts reported in the following tables for balances as of December 31, 2005 and December 31, 2004 are based on measurement dates of November 30, 2005, and November 30, 2004, respectively. 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. Amounts reported in tables for the year ended December 31, 2003 are based on a measurement date of December 31, 2002.

Qualified and Nonqualified Pension Plan Benefits

We have a defined benefit retirement plan. The plan is noncontributory, covers substantially all employees and provides retirement benefits based on the employees’ years of benefit service, average final compensation and age at retirement. Certain represented and nonrepresented employees are covered under cash balance benefits based on annual employer contributions and interest credits. We operate as the sponsor of the plan, which is treated as a plan covering employees of various affiliates of DTE Energy from the affiliates’ perspective. The annual expense disclosed below is our portion of the total plan expense. Each affiliate is charged their portion of the expense. Our policy is to fund pension costs by contributing the minimum amount required by the Employee Retirement Income Security Act and additional amounts we deem appropriate. We do not anticipate making a contribution to our qualified pension plans in 2006.

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

Net pension cost includes the following components:


	Qualified Pension Plans									Nonqualified Pension Plans
(in Millions)	2005			2004			2003			2005		2004		2003
Service Cost	$	53		$	47		$	40		$	1	$	1	$	1
Interest Cost		130			130			127			2		2		2
Expected Return on Plan Assets		(135	)		(135	)		(129	)		—		—		—
Amortization of
Net loss		50			49			32			1		1		1
Prior service cost		9			9			9			—		—		—

Net Pension Cost	$	107		$	100		$	79		$	4	$	4	$	4

The following table reconciles the obligations, assets and funded status of the plan as well as the amount recognized as pension liability in the consolidated statement of financial position at December 31. The results include liabilities and assets for Detroit Edison and all affiliates participating in the combined plan. The prepaid asset contributed to the combined plan by such affiliates is reflected as an amount due to affiliates, $273 million and $247 million at December 31, 2005 and 2004, respectively.


	Qualified Pension Plans						Nonqualified Pension Plans
(in Millions)	2005			2004			2005			2004
Accumulated Benefit Obligation-End of Period	$	2,497		$	2,447		$	37		$	34


Projected Benefit Obligation-Beginning of Period	$	2,643		$	2,498		$	36		$	36
Service Cost		59			53			1			1
Interest Cost		154			153			2			2
Actuarial Loss (Gain)		35			69			4			(1	)
Benefits Paid		(153	)		(136	)		(2	)		(2	)
Plan Amendments		—			6			—			—

Projected Benefit Obligation-End of Period	$	2,738		$	2,643		$	41		$	36


Plan Assets at Fair Value-Beginning of Period	$	2,235		$	2,029		$	—		$	—
Actual Return on Plan Assets		191			172			—			—
Company Contributions		—			170			2			2
Benefits Paid		(153	)		(136	)		(2	)		(2	)

Plan Assets at Fair Value-End of Period	$	2,273		$	2,235		$	—		$	—


Funded Status of the Plans	$	(465	)	$	(408	)	$	(41	)	$	(36	)
Unrecognized
Net loss		773			790			15			11
Prior service cost		34			41			1			2
Net transition assets		—			(1	)		—			—

Net Amount Recognized-End of Period	$	342		$	422		$	(25	)	$	(23	)


Amount Recorded as
Accrued pension liability	$	(224	)	$	(212	)	$	(37	)	$	(35	)
Regulatory asset		532			594			11			10
Intangible asset		34			40			1			2

	$	342		$	422		$	(25	)	$	(23	)

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


	2005			2004			2003
Projected Benefit Obligation
Discount rate		5.90	%		6.00	%		6.25	%
Annual increase in future compensation levels		4.0	%		4.0	%		4.0	%

Net Pension Costs
Discount rate		6.00	%		6.25	%		6.75	%
Annual increase in future compensation levels		4.0	%		4.0	%		4.0	%
Expected long-term rate of return on Plan assets		9.0	%		9.0	%		9.0	%

At December 31, 2005, 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)
2006	$	158
2007		162
2008		167
2009		171
2010		176
2011 - 2015		954

Total	$	1,788

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:


	2005			2004
Equity Securities		68	%		69	%
Debt Securities		27			26
Other		5			5

		100	%		100	%

Our plans’ weighted-average asset target allocations by asset category at December 31, 2005 were as follows:


Equity Securities	65	%
Debt Securities	28
Other	7

	100	%

In December 2002, we recognized an additional minimum pension liability as required under SFAS No. 87, Employers’ Accounting for Pensions. An additional pension liability may be required when the accumulated benefit obligation of the plan exceeds the fair value of plan assets. Under SFAS No. 87, we recorded an additional minimum pension liability, an intangible asset and other comprehensive loss. In 2003, we reclassified $572 million of other comprehensive loss related to the minimum pension liability to a regulatory asset after the MPSC Staff provided an opinion that the MPSC’s traditional rate setting process allowed for the recovery of pension costs as measured by SFAS No. 87. The additional minimum pension liability, regulatory asset and intangible asset are adjusted in December of each year based on the plans’ funded status.

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 2005, $22 million in 2004 and $21 million in 2003.

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. At the discretion of management, we may make up to a $80 million contribution to our VEBA trusts in 2006.

Net postretirement cost includes the following components:


(in Millions)	2005			2004			2003
Service Cost	$	44		$	33		$	31
Interest Cost		80			69			66
Expected Return on Plan Assets		(58	)		(45	)		(36	)
Amortization of
Net loss		44			33			23
Prior service costs		3			—			—
Net transition obligation		7			8			13

Net Postretirement Cost	$	120		$	98		$	97

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)	2005			2004
Accumulated Postretirement Benefit Obligation-Beginning of Period	$	1,361		$	1,192
Service Cost		44			33
Interest Cost		80			69
Actuarial Loss		111			106
Plan Amendments		(5	)		21
Benefits Paid		(66	)		(60	)

Accumulated Postretirement Benefit Obligation-End of Period	$	1,525		$	1,361


Plan Assets at Fair Value-Beginning of Period	$	551		$	468
Actual Return on Plan Assets		49			43
Company Contributions		40			40
Benefits Paid		(59	)		—

Plan Assets at Fair Value-End of Period	$	581		$	551


Funded Status of the Plans	$	(944	)	$	(810	)
Unrecognized
Net loss		670			594
Prior service cost		26			30
Net transition obligation		46			58

Accrued Postretirement Liability at Measurement Date		(202	)		(128	)
December Adjustments		(50	)		(14	)

Accrued Postretirement Liability-End of Period	$	(252	)	$	(142	)

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


	2005			2004			2003
Projected Benefit Obligation
Discount rate		5.90	%		6.00	%		6.25	%

Net Benefit Costs
Discount rate		6.00	%		6.25	%		6.75	%
Expected long-term rate of return on Plan assets		9.0	%		9.0	%		9.0	%

Benefit costs were calculated assuming health care cost trend rates beginning at 9.0% for 2006 and decreasing to 5.0% in 2011 and thereafter for persons under age 65 and decreasing from 8.0% to 5.0% 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 $24 million and increased the accumulated benefit obligation by $186 million at December 31, 2005. 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 $15 million and would have decreased the accumulated benefit obligation by $155 million at December 31, 2005.

At December 31, 2005, 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)
2006	$	83
2007		88
2008		90
2009		95
2010		98
2011 - 2015		507

Total	$	961

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:


	2005			2004
Equity Securities		68	%		68	%
Debt Securities		28			28
Other		4			4

		100	%		100	%

Our plans’ weighted-average asset target allocations by asset category at December 31, 2005 were as follows:


Equity Securities	65	%
Debt Securities	28
Other	7

	100	%

In December 2003, the Medicare Act was signed into law which provides for a non-taxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least “actuarially equivalent” to the benefit established by law. 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 $15 million in 2005 and $12 million in 2004.

At December 31, 2005, 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)
2006	$	4
2007		4
2008		3
2009		4
2010		5
2011 - 2015		27

Total	$	47

NOTE 15 — RELATED PARTY TRANSACTIONS

We have agreements with affiliated companies to sell energy for resale, purchase power, provide fuel supply services, and provide power plant operation and maintenance services. We have an agreement with certain DTE Energy affiliates where we charge them for their use of the shared capital assets of the Company. 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. The following is a summary of transactions with affiliated companies:


(in Millions)	2005			2004			2003
Revenues
Energy sales	$	192		$	206		$	58
Other services		5			37			2
Shared capital assets		14			12			11

Costs
Power purchases		102			61			36
Other services and interest		7			5			9
Corporate expenses and merger costs (net) (1)		(97	)		(19	)		(18	)


	December 31,
(in Millions)	2005		2004
Assets
Accounts receivable	$	27	$	29
Notes receivable		—		85

Liabilities & Equity
Accounts payable		51		56
Dividends payable		76		76
Dividends declared		305		305
Dividends paid		305		303
Capital contribution		—		170


(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.

Under an inter-company credit agreement, we had a short-term note receivable from DTE Energy. Short-term excess cash or cash shortfalls are remitted to or funded by DTE Energy. This credit arrangement involves the charge and payment of interest at rates that approximate market.

In 2004, DTE Energy contributed 4,344,492 shares of its common stock, valued at $170 million, to our defined benefit retirement plan.

NOTE 16 — SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)


	First		Second		Third		Fourth
(in Millions)	Quarter		Quarter		Quarter		Quarter		Year
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

2004
Operating Revenues		886		835		958		889		3,568
Operating Income		145		92		169		111		517
Net Income		44		8		62		36		150

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, 2005, 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 2005 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 and Executive Officers of the Registrant

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

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, 2005 and 2004, 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, 2005 and December 31, 2004, and fees billed for other services rendered by Deloitte during those periods.


	2005		2004
Audit fees (1)	$	1,978,724	$	1,571,645
Audit-related fees (2)(3)		13,000		59,750
Tax fees (3)		—		—
All other fees		—		—

Total	$	1,991,724	$	1,631,395


(1)		Represents the aggregate 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 aggregate 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.


		12-23		Computation of Ratio of Earnings to Fixed Charges.

		23-18		Consent of Deloitte & Touche LLP.

		31-21		Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report.

		31-22		Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report.

(ii) Exhibits incorporated herein by reference.


September 1, 1947		Exhibit B-20 to Registration Statement No. 2-7136.

November 15, 1971		Exhibit 2-B-38 to Registration Statement No. 2-42160.

January 15,1973		Exhibit 2-B-39 to Registration Statement No. 2-46595.

June 1, 1978		Exhibit 2-B-51 to Registration Statement No. 2-61643.

June 30, 1982		Exhibit 4-30 to Registration Statement No. 2-78941. (reconfirming obligations following merger)

August 15, 1982		Exhibit 4-32 to Registration Statement No. 2-79674.

February 15, 1990		Exhibit 4-212 to Form 10-K for year ended December 31, 2000. (1990 Series A, B, C, D, E and F)


April 1, 1991		Exhibit 4-15 to Form 10-K for year ended December 31, 1995. (1991 Series AP)

May 1, 1991		Exhibit 4-178 to Form 10-K for year ended December 31, 1996. (1991 Series BP and 1991 Series CP)

May 15, 1991		Exhibit 4-179 to Form 10-K for year ended December 31, 1996. (1991 Series DP)

February 29, 1992		Exhibit 4-187 to Form 10-Q for quarter ended March 31, 1998. (1992 Series AP)

January 1, 1993		Exhibit 4-131 to Registration Statement No. 33-56496.

April 26, 1993		Exhibit 4-215 to Form 10-K for year ended December 31, 2000. (amending indenture)

May 31, 1993		Exhibit 4-148 to Registration Statement No. 33-64296.

June 30, 1993		Exhibit 4-216 to Form 10-K for year ended December 31, 2000. (1993 Series AP)

August 15, 1994		Exhibit 4-219 to Form 10-K for year ended December 31, 2000. (1994 Series C)

August 1, 1999		Exhibit 4-204 to Form 10-Q for quarter ended September 30, 1999. (1999 Series AP, 1999 Series BP and 1999 Series CP)

January 1, 2000		Exhibit 4-205 to Form 10-K for year ended December 31, 1999. (2000 Series A)

April 15, 2000		Exhibit 206 to Form 10-Q for quarter ended March 31, 2000. (relating to successor trustee)

August 1, 2000		Exhibit 4-210 to Form 10-Q for quarter ended September 30, 2000. (2000 Series BP)

March 15, 2001		Exhibit 4-222 to Form 10-Q for quarter ended March 31, 2001. (2001 Series AP)

May 1, 2001		Exhibit 4-226 to Form 10-Q for quarter ended June 30, 2001. (2001 Series BP)

August 15, 2001		Exhibit 4-227 to Form 10-Q for quarter ended September 30, 2001. (2001 Series CP)

September 15, 2001		Exhibit 4-228 to Form 10-Q for quarter ended September 30, 2001. (2001 Series D and 2001 Series E)

September 17, 2002		Exhibit 4-1 to Registration Statement No. 333-100000. (relating to successor trustee)

October 15, 2002		Exhibit 4-230 to Form 10-Q for quarter ended September 30, 2002. (2002 Series A and 2002 Series B)

December 1, 2002		Exhibit 4-232 to Form 10-K for year ended December 31, 2002. (2002 Series C and 2002 Series D)

August 1, 2003		Exhibit 4-235 to Form 10-Q for quarter ended September 30, 2003. (2003 Series A)

March 15, 2004		Exhibit 4-238 to Form 10-Q for quarter ended March 31, 2004. (2004 Series A and 2004 Series B)

July 1, 2004		Exhibit 4-240 to Form 10-Q for quarter ended June 30, 2004. (2004 Series D)

February 1, 2005		Exhibit 4.2 to Form 8-K dated February 7, 2005. (2005 Series A and 2005 Series B)

April 1, 2005		Exhibit 4.3 to Registration Statement No. 333-123926. (2005 Series AR and 2005 Series BR)

August 1, 2005		Exhibit 4.2 to Form 8-K dated August 17, 2005. (2005 Series DT)

September 15, 2005		Exhibit 4.1 to Form 8-K dated September 29, 2005. (2005 Series C)

September 30, 2005		Exhibit 4-248 to Form 10-Q dated November 8, 2005. (2005 Series E)

4(b)		Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and Bankers Trust Company, as trustee. (Exhibit 4-152 to Registration Statement No. 33-50325)

4(c)		First Supplemental Indenture, dated as of June 30, 1993. (Exhibit 4-153 to Registration Statement No. 33-50325)

4(d)		First Amendment, dated as of July 17, 2000, to the First Supplemental Indenture amending the Multi-Mode Remarketed Secured Notes 1993 Series A due 2028. (Exhibit 4-209 to Form 10-Q for quarter ended September 30, 2000)

4(e)		Second Supplemental Indenture, dated as of September 15, 1993, providing for


		Remarketed Secured Notes 1993 Series B due 2033. (Exhibit 4-159 to Form 10-Q for quarter ended September 30, 1993)

4(f)		First Amendment, dated as of August 15, 1996, to Second Supplemental Indenture. (Exhibit 4-177 to Form 10-Q for quarter ended September 30, 1996)

4(g)		Third Supplemental Indenture, dated as of August 15, 1994, providing for Remarketed Secured Notes 1994 Series C due 2034. (Exhibit 4-169 to Form 10-Q for quarter ended September 30, 1994)

4(h)		First Amendment, dated as of December 12, 1995, to Third Supplemental Indenture, dated as of August 15, 1994. (Exhibit 4-13 to Registration Statement No. 333-00023)

4(i)		Eighth Supplemental Indenture, dated as of April 15, 2000, appointing Bank One Trust Company, National Association, as successor trustee. (Exhibit 4-207 to Form 10-Q for quarter ended March 31, 2000)

4(j)		Ninth Supplemental Indenture, dated as of October 10, 2001, providing for 5.050% Senior Notes due 2005 and 6.125% Senior Notes due 2010. (Exhibit 4-229 to Form 10-Q for quarter ended September 30, 2001)

4(k)		Tenth Supplemental Indenture, dated as of October 23, 2002, providing for 5.20% Senior Notes due 2012 and 6.35% Senior Notes due 2032. (Exhibit 4-231 to Form 10-Q for quarter ended September 30, 2002)

4(l)		Eleventh Supplemental Indenture, dated as of December 1, 2002, providing for 5.45% Senior Notes due 2032 and 5.25% Senior Notes due 2032. (Exhibit 4-233 to Form 10-Q for quarter ended March 31, 2003)

4(m)		Twelfth Supplemental Indenture, dated as of August 1, 2003, providing for 5 1/2% Senior Notes due 2030. (Exhibit 4-236 to Form 10-Q for quarter ended September 30, 2003)

4(n)		Thirteenth Supplemental Indenture, dated as of April 1, 2004, between J.P. Morgan Trust Company, National Association as successor trustee, providing for 4.875% Senior Notes due 2029 and 4.65% Senior Notes due 2028. (Exhibit 4-237 to Form 10-Q for quarter ended March 31, 2004)

4(o)		Fourteenth Supplemental Indenture, dated as of July 15, 2004, providing for 2004 Series D 5.40% Senior Notes due 2014. (Exhibit 4-239 to Form 10-Q for quarter ended June 30, 2004)

4(p)		Fifteenth Supplemental Indenture, dated as of February 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, providing for 2005 Series A 4.80% Senior Notes due 2015 and 2005 Series B 5.45% Senior Notes due 2035. (Exhibit 4.1 to Form 8-K dated February 7, 2005)


4(q)		Supplemental Indenture, dated as of February 1, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 2004, between The Detroit Edison Company and J.P. Morgan Trust Company, National Association, as successor trustee, providing for General and Refunding Mortgage Bonds 2005 Series A and 2005 Series B. (Exhibit 4.2 to Form 8-K dated February 7, 2005)

4(r)		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, providing for 2005 Series AR 4.80% Senior Notes due 2015 and 2005 Series BR 5.45% Senior Notes due 2035. (Exhibit 4.1 to Registration Statement (File No. 333-123926)


4(s)		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, providing for 2005 Series DT Variable Rate Senior Notes due 2029 (Exhibit 4.1 to Form 8-K dated August 17, 2005)

4(t)		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, providing for 2005 Series C, 5.19% Senior Notes due October 1, 2023. (Exhibit No. 4.1 to Form 8-K dated September 29, 2005)

4(u)		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, providing for 2005 Series E Senior Notes due 2037. (Exhibit 4-247 to Form 10-Q dated November 8, 2005)

4(v)		Trust Agreement of Detroit Edison Trust I. (Exhibit 4-9 to Registration Statement No. 333-100000)

4(w)		Trust Agreement of Detroit Edison Trust II. (Exhibit 4-10 to Registration Statement No. 333-100000)

4(x)		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 quarter ended March 31, 2001)

10(b)		Five-Year Credit Agreement, dated as of October 15, 2004, among The Detroit Edison Company, Citibank, N.A. as Administrative Agent and the Initial Lenders named therein ($206,250,000). (Exhibit 10-1 to Form 8-K dated October 15, 2004)

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

10(d)		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


		quarter ended March 31, 1994)

10(e)		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(f)		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 year ended December 31, 1996)

10(g)		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 quarter ended March 31, 1998)

10(h)		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 quarter ended March 31, 1998)

10(i)		Restricted Stock Agreement, dated March 23, 1998, between The Detroit Edison Company and Anthony F. Earley, Jr. (Exhibit 10-20 to Form 10-Q for quarter ended March 31, 1998)

10(j)		The Detroit Edison Company Supplemental Long-Term Disability Plan, dated January 27, 1997. (Exhibit 10-4 to Form 10-K for year ended December 31, 1996)

10(k)		Executive Vehicle Plan of The Detroit Edison Company, dated as of September 1, 1999. (Exhibit 10-41 to Form 10-Q for quarter ended March 31, 2001)

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 quarter ended March 31, 2001)

99(d)		Amendment to Trade Receivables Purchase and Sale Agreement, dated as of March 9, 2001, among The Detroit Edison Company, Citibank, N.A., and Citicorp North America, Inc. (Exhibit 99-42 to Form 10-Q for quarter ended March 31, 2001)

99(e)		Amended and Restated Trade Receivables Purchase and Sale Agreement, dated as of March 9, 2001, among The Detroit Edison Company, Corporate Asset Funding, Inc., Citibank, N.A., and Citicorp North America, Inc. (Exhibit 99-43 to Form 10-Q for quarter ended March 31, 2001)

99(f)		Amendment, dated as of May 28, 2003, to the Trade Receivables Purchase and Sale Agreement, dated as of February 28, 1989, and an Amendment and Restatement thereof, dated as of October 1, 1991, and as further amended by an Amendment dated as of February 28, 1994, an Amendment dated as of February 1, 1999, an Amendment dated as of January 27, 2000 and an Amendment dated as of January 25, 2001, among The Detroit Edison Company, Citibank, N.A., and Citicorp North America, Inc. (Exhibit 99-11 to Form 10-Q for quarter ended June 30, 2003)

99(g)		Amendment No. 2, dated as of May 28, 2003, to the Trade Receivables Purchase and Sale Agreement, dated as of February 28, 1989, an Amendment and Restatement


		thereof, dated as of October 1, 1991, an Amendment and Restatement thereof dated as of March 9, 2001 and an Amendment dated as of January 17, 2003, among The Detroit Edison Company, Corporate Asset Funding Company, Inc., Citibank, N.A., and Citicorp North America, Inc. (Exhibit 99-12 to Form 10-Q for quarter ended June 30, 2003)

99(h)		Amendment, dated as of February 25, 2004, to the Trade Receivables Purchase and Sale Agreement, dated as of February 28, 1989, and an Amendment and Restatement thereof, dated as of October 1, 1991, and as further amended by an Amendment dated as of February 28, 1994, an Amendment dated as of February 1, 1999, an Amendment dated as of January 27, 2000, and an Amendment dated as of January 25, 2001 and an Amendment dated as of May 28, 2003, among The Detroit Edison Company, Citibank, N.A. and Citicorp North America, Inc. (Exhibit 99-15 to Form 10-Q for quarter ended March 31, 2004)

99(i)		Amendment, dated as of January 20, 2005, to the Trade Receivables Purchase and Sale Agreement, dated as of February 28, 1989, an Amendment and Restatement thereof, dated as of October 1, 1991, and as further amended by an Amendment dated as of February 28, 1994, an Amendment dated as of February 1, 1999, an Amendment dated as of January 27, 2000, and an Amendment dated as of January 25, 2001, an Amendment dated as of May 28, 2003 and an Amendment dated as of February 25, 2004, among The Detroit Edison Company, Citibank, N.A. and Citicorp North America, Inc. (Exhibit 99-17 to Form 10-K for year ended December 31, 2004)

99(j)		Amendment No. 4, dated as of January 20, 2005, to the Trade Receivables Purchase and Sale Agreement, dated as of February 28, 1989, an Amendment and Restatement thereof, dated as of October 1, 1991, an Amendment and Restatement thereof, dated as of March 9, 2001, an Amendment dated as of January 17, 2003, an Amendment dated as of May 28, 2003 and an Amendment dated February 25, 2004, as so amended and restated, among The Detroit Edison Company, CAFCO, LLC (successor to Corporate Asset Funding Company, Inc.), Citibank, N.A. and Citicorp North America, Inc. (Exhibit 99-18 to Form 10-K for the year ended December 31, 2004)

99(k)		Amendment No. 3, dated as of February 25, 2004, to the Trade Receivables Purchase and Sale Agreement, dated as of February 28, 1989, and an Amendment and Restatement thereof, dated as of October 1, 1991, an Amendment and Restatement thereof dated as of March 9, 2001, an Amendment dated as of January 17, 2003, and an Amendment dated as of May 28, 2003, among The Detroit Edison Company, CAFCO, LLC successor to Corporate Asset Funding Company, Inc.), Citibank, N.A., and Citicorp North America, Inc. (Exhibit 99-16 to Form 10-Q for quarter ended March 31, 2004)

99(l)		Three-Year Credit Agreement, dated as of October 24, 2003 (as amended by the Five-Year Credit Agreement identified as Exhibit 10(b) above, $68,750,000). (Exhibit 99-14 to Form 10-Q for quarter ended September 30, 2003)

99(m)		Master Trust Agreement (“Master Trust”), dated as of June 30, 1994, between The Detroit Edison Company and Fidelity Management Trust Company relating to the Savings and Investment Plans. (Exhibit 4-167 to Form 10-Q for quarter ended June 30, 1994)

99(n)		First Amendment, dated as of February 1, 1995, to Master Trust. (Exhibit 4-10 to Registration Statement No. 333-00023)


99(o)		Second Amendment, dated as of February 1, 1995, to Master Trust. (Exhibit 4-11 to Registration Statement No. 333-00023)

99(p)		Third Amendment, effective January 1, 1996, to Master Trust. (Exhibit 4-12 to Registration Statement No. 333-00023)

99(q)		Fourth Amendment, dated as of August 1, 1996, to Master Trust. (Exhibit 4-185 to Form 10-K for year ended December 31, 1997)

99(r)		Fifth Amendment, dated as of January 1, 1998, to Master Trust. (Exhibit 4-186 to Form 10-K for year ended December 31, 1997)

99(s)		Sixth Amendment, dated as of September 1, 1998, to Master Trust (Exhibit 99-19 to Form 10-K for year ended December 31, 2004)

99(t)		Seventh Amendment, dated as of December 15, 1999, to Master Trust. (Exhibit 99-20 to Form 10-K for year ended December 31, 2004)

99(u)		Eighth Amendment, dated as of February 1, 2000, to Master Trust. (Exhibit 99-21 to Form 10-K for year ended December 31, 2004)

99(v)		Ninth Amendment, dated as of April 1, 2000, to Master Trust. (Exhibit 99-22 to Form 10-K for year ended December 31, 2004)

99(w)		Tenth Amendment, dated as of May 1, 2000, to Master Trust. (Exhibit 99-23 to Form 10-K for year ended December 31, 2004)

99(x)		Eleventh Amendment, dated as of July 1, 2000, to Master Trust. (Exhibit 99-24 to Form 10-K for year ended December 31, 2004)

99(y)		Twelfth Amendment, dated as of August 1, 2000, to Master Trust. (Exhibit 99-25 to Form 10-K for year ended December 31, 2004)

99(z)		Thirteenth Amendment, dated as of December 21, 2001, to Master Trust. (Exhibit 99-26 to Form 10-K for year ended December 31, 2004)

99(aa)		Fourteenth Amendment, dated as of March 1, 2002, to Master Trust. (Exhibit 99-27 to Form 10-K for year ended December 31, 2004)

99(bb)		Fifteenth Amendment, dated as of January 1, 2002, to Master Trust. (Exhibit 99-28 to Form 10-K for year ended December 31, 2004)

(iii) Exhibits furnished herewith.


		32-21		Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report.

		32-22		Chief Financial Officer Section 906 Form 10-K Certification of Periodic Report.

Signatures

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


		THE DETROIT EDISON COMPANY
		(Registrant)

Date: March 7, 2006	By	/s/ PETER B. OLEKSIAK

		Peter B. Oleksiak
		Controller and Chief Accounting Officer

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


By	/s/ ANTHONY F. EARLEY, JR.	By	/s/ PETER B. OLEKSIAK

	Anthony F. Earley, Jr.		Peter B. Oleksiak
	Chairman of the Board and		Controller and Chief Accounting Officer
	Chief Executive Officer

By	/s/ SANDRA KAY ENNIS	By	/s/ DAVID E. MEADOR

	Sandra Kay Ennis		David E. Meador
	Director and Corporate Secretary		Director, Executive Vice President
			and Chief Financial Officer

By	/s/ BRUCE D. PETERSON
	Bruce D. Peterson
	Director

Date: March 7, 2006


		Page
Definitions		1

Forward-Looking Statements		2

Part I
Items 1., 1A. & 2.	Business, Company Risk Factors and Properties	3

Item 3.	Legal Proceedings	9

Item 4.	Submission of Matters to a Vote of Security Holders	10

Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	10

Item 6.	Selected Financial Data	10

Item 7.	Management’s Narrative Analysis of Results of Operations	11

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	15

Item 8.	Financial Statements and Supplementary Data	16

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	54

Item 9A.	Controls and Procedures	54

Item 9B.	Other Information	55

Part III
Item 10.	Directors and Executive Officers of the Registrant	55

Item 11.	Executive Compensation	55

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	55

Item 13.	Certain Relationships and Related Transactions	55

Item 14.	Principal Accountant Fees and Services	55

PART IV
Item 15.	Exhibits and Financial Statement Schedules	56

Signatures		64
Computation of Ratio of Earnings to Fixed Charges
Consent of Deloitte & Touche LLP
Chief Executive Officer Section 302 Certification
Chief Financial Officer Section 302 Certification
Chief Executive Officer Section 906 Certification
Chief Financial Officer Section 906 Certification


		Page
Report of Independent Registered Public Accounting Firm		17

Consolidated Statement of Operations		18

Consolidated Statement of Financial Position		19

Consolidated Statement of Cash Flows		21

Consolidated Statement of Changes in Shareholder’s Equity and Comprehensive Income		22

Notes to Consolidated Financial Statements		23

Schedule II – Valuation and Qualifying Accounts		63


Note		Title

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


	Year Ending December 31,
(in Millions)	2005			2004			2003
Allowance for Doubtful Accounts (shown as deduction from accounts receivable in the consolidated statement of financial position)
Balance at Beginning of Period	$	55		$	51		$	48
Additions:
Charged to costs and expenses		41			45			39
Charged to other accounts (1)		4			5			3
Deductions (2)		(46	)		(46	)		(39	)

Balance At End of Period	$	54		$	55		$	51


(1)		Collection of accounts previously written off.

(2)		Non-collectible accounts written off.


Exhibit Number		Description

(i) Exhibits filed herewith.
12-23		Computation of Ratio of Earnings to Fixed Charges.

23-18		Consent of Deloitte & Touche LLP.

31-21		Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report.

31-22		Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report.

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.

(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.