DETROIT EDISON CO - 10-K Annual Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

FOR ANNUAL REPORT & TRANSITION REPORTS 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, 2004

Commission file number 1-2198

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

THE DETROIT EDISON COMPANY

(Exact name of registrant as specified in its charter)


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


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

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

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered


Quarterly Income Debt Securities (QUIDS)		New York Stock Exchange
(Junior Subordinated Deferrable Interest
Debentures – 7.625%, 7.54% and 7.375% Series)

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

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 registrants’ 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 an accelerated filer (as defined in Exchange Act Rule 12b-2)


		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 clause was suspended under Michigan’s restructuring legislation (signed into law June 5, 2000), which lowered and froze electric customer rates. The clause 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 expect to be recoverable if customers switch to alternative energy suppliers.

Units of Measurement

gWh		Gigawatthour of electricity

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 in such forward-looking statements. 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 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 borrowings;

•   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; 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. & 2. Business 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 and is engaged in the generation, purchase, distribution and sale of electric energy to 2.1 million customers in a 7,600 square mile area in southeastern Michigan.

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

We currently operate our businesses through two segments, Energy Resources – Power Generation and Energy Distribution – Power Distribution. Based on this structure, we set strategic goals, allocate resources and evaluate performance. A discussion of each segment follows.

ENERGY RESOURCES

Power Generation

Description

Power Generation comprises our utility power generation business and plants within Detroit Edison. These 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 Detroit Edison’s numerous fossil plants, its hydroelectric pumped storage plant and its 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, the Midwest and Ontario, Canada.

Weather, economic factors 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. Power generation sales are made to a diverse base of customers in both type and number; sales levels are not dependent on any small market segment. Customers who elect to purchase their electricity from alternative energy suppliers by participating in the electric Customer Choice program have an unfavorable effect on our financial performance.

Our power is generated from a variety of fuels and is supplemented with market purchases. The following table details our energy supply mix and average cost per unit:



	2004				2003				2002
(in Thousands of MWh)
Power Generated and Purchased
Power Plant Generation
Fossil		39,432	75	%		38,052	72	%		39,017	67	%
Nuclear (Fermi 2)		8,440	16			8,114	16			9,301	16

		47,872	91			46,166	88			48,318	83
Purchased Power		4,650	9			6,354	12			9,807	17

System Output		52,522	100	%		52,520	100	%		58,125	100	%


Average Unit Cost ($/MWh)

Generation (1)	$	12.98			$	12.89			$	12.53

Purchased Power (2)	$	37.06			$	41.73			$	39.16

Overall Average Unit Cost	$	15.11			$	16.38			$	17.02

(1)		Represents fuel costs associated with power plants.

(2)		Includes amounts associated with hedging activities.

We expect an adequate supply of fuel and purchased power to meet our obligation to serve customers. The effect of lost sales due to the electric Customer Choice program has reduced our need for purchased power and increased our ability to sell power in the wholesale market. We have short and long-term supply contracts for expected fuel and purchased power requirements as detailed in the following table:



	2005
Expected Supply	Contracted			Open
Coal		84	%		16	%
Natural Gas		26	%		74	%
Oil		20	%		80	%
Purchased Power		75	%		25	%

Power Generation’s 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. Detroit Edison expects to obtain the majority of its coal requirements through long-term contracts with the balance to be obtained through short-term agreements and spot purchases. Detroit Edison has contracts with five coal suppliers and several over-the-counter brokers for a total purchase of up to 35 million tons of low-sulfur western coal to be delivered through 2008. Detroit Edison also has contracts with four suppliers for the purchase of approximately 6 million tons of Appalachian coal to be delivered through 2006. These existing long-term coal contracts either have fixed prices or include provisions for price escalation as well as de-escalation. Given the geographic diversity of supply, Detroit Edison believes it can meet the expected generation requirements. We own and 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.

We purchase power from other electricity generators, suppliers and wholesalers. These purchases supplement 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 power facilities.

Regulation

Detroit Edison’s Power Generation 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 Fermi 2 nuclear plant.

Since 1996 there have been several important acts, orders, court rulings and legislative actions in the State of Michigan that affect our Power Generation operations. In 1996, the MPSC began an initiative designed to give all of Michigan’s electric customers access to electricity supplied by other generators and marketers. In 1998, the MPSC authorized the electric Customer Choice program that allowed for a limited number of customers to purchase electricity from suppliers other than their local utility. The local utility would continue 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 Power Supply Cost Recovery (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. The final order addressed numerous issues relating to regulatory assets, including the actual amounts recoverable and the recovery mechanism.

See Note 4 – Regulatory Matters for additional information regarding the 2004 rate orders and our regulatory environment.

Properties

Detroit Edison owns generating properties and facilities that are primarily located in the State of Michigan. Substantially all the net utility properties of Detroit Edison are subject to the lien of its mortgage. Power Generation plants owned and in service as of December 31, 2004 are as follows:



	Location by	Summer Net
	Michigan	Rated Capability (1) (2)
Plant Name	County	(MW)		(%)			Year in Service
Fossil-fueled Steam-Electric
Belle River (3)	St. Clair		1,026		9.3	%	1984 and 1985
Conners Creek	Wayne		215		1.9		1951
Greenwood	St. Clair		785		7.1		1979
Harbor Beach	Huron		103		0.9		1968
Marysville	St. Clair		84		0.7		1943 and 1947
Monroe (4)	Monroe		3,080		27.8		1971, 1973 and 1974
River Rouge	Wayne		510		4.6		1957 and 1958
St. Clair	St. Clair		1,415		12.8		1953, 1954, 1959, 1961 and 1969
Trenton Channel	Wayne		730		6.6		1949 and 1968

			7,948		71.7
Oil or Gas-fueled Peaking Units	Various		1,102		10.0		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

			11,078		100.0	%

(1)		Summer net rated capabilities of generating units 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 35% of Detroit Edison’s total 2004 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.

Strategy and Competition

We strive to be the preferred electricity supplier in southeast Michigan. We believe that we can accomplish our 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 will continue to make investments in our generating plants that will improve both plant availability and 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 whereby all of the Company’s electric customers can choose to purchase their electricity from alternative suppliers of generation services. Detroit Edison lost 18% of retail sales in 2004, 12% in 2003 and 5% of such sales in 2002 as a result of customers choosing to purchase power from alternative suppliers. Customers participating in the electric Customer Choice program consist primarily of industrial and commercial customers whose MPSC-authorized full service rates exceed the cost of service. We will continue to utilize the wholesale market to sell the generation made available by the electric Customer Choice program, in order to lower costs for full service customers.

ENERGY DISTRIBUTION

Power Distribution

Description

The electric distribution services of Detroit Edison comprise our utility Power Distribution business. This business distributes electricity generated by Energy Resources’ Power Generation business and alternative energy suppliers to Detroit Edison’s 2.1 million customers in southeastern Michigan.

In January 2003, we sold the steam heating business of Detroit Edison to Thermal Ventures II, LP.

Weather and economic factors affect our sales and revenues. Similar to the Power Generation business, 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. Power Distribution’s sales are not dependent upon a limited number of customers. Although customers participating in the electric Customer Choice program do not impact the total number of Power Distribution customers, they do impact operating revenues. Electric Choice customers currently pay a lower distribution rate than full service customers. Accordingly, customers participating in the electric Customer Choice program unfavorably affect revenues. Detroit Edison filed a rate restructuring proposal in February 2005 to eliminate this intra class rate subsidy (Note 4). The loss of any one or a few customers is not reasonably likely to have a material adverse effect on Power Distribution.



(in thousands of MWh)	2004		2003		2002
Electric Deliveries
Residential		15,081		15,074		15,958
Commercial		13,425		15,942		18,395
Industrial		11,472		12,254		13,590
Wholesale		2,197		2,241		2,249
Other		401		402		403

		42,576		45,913		50,595
Electric Choice		9,245		6,193		2,967
Electric Choice – Self Generators*		595		1,088		543

Total Electric Deliveries		52,416		53,194		54,105

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

Regulation

Detroit Edison’s Power Distribution is subject to the jurisdiction of the MPSC, which has regulatory authority over rates, conditions of service and other operating-related matters. As previously discussed, Michigan legislation prevents Detroit Edison from increasing rates to residential customers through 2005 and prevented rate increases for small business customers through 2004.

In January 2004, the MPSC issued an order adopting rules governing service quality and reliability standards for electric distribution systems. The reliability standards establish performance levels for service restoration, wire-down relief requests, customer call answer time, customer complaint response, meter reading and new service installations. The order also establishes penalties for delays in service restoration during normal conditions, catastrophic storms and repetitive outages. Detroit Edison is required to file an annual report providing information regarding performance against the measures provided and any penalties incurred.

The final order addressed numerous issues relating to regulatory assets, including the actual amounts recoverable and the recovery mechanism.

See Note 4 – Regulatory Matters for additional information regarding the 2004 rate orders and our regulatory environment.

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 are working with the State of Michigan and others to increase the share of funding allocated to our customers to be representative of the number of low-income individuals in our service territory.

Properties

Detroit Edison owns and operates 667 distribution substations with a capacity of approximately 31,381,500 kilovolt-amperes (kVA) and approximately 415,000 line transformers with a capacity of approximately 24,792,000 kVA. Substantially all of the net utility properties of Detroit Edison are subject to the lien of its mortgage. Circuit miles of distribution lines owned and in service as of December 31, 2004 are as follows:



Electric Distribution	Circuit Miles
Operating Voltage-Kilovolts (kV)	Overhead		Underground
4.8 kV to 13.2 kV		28,060		12,929
24 kV		101		690
40 kV		2,322		326
120 kV		70		13

		30,553		13,958

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.

Strategy and Competition

Our strategy focuses on improving reliability, restoration time and the quality of customer service and lowering operating costs by improving operating efficiencies. We also are targeting capital investments in areas that have the greatest impact on reliability improvements with the goal of managing distribution rates charged to utility customers.

Detroit Edison acquires transmission services from International Transmission Company (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 chemicals 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. 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

Detroit Edison is subject to applicable permit requirements, and to potentially increased stringent federal, state and local standards covering, among other things, particulate and gaseous stack emission limitations, the discharge of wastewater into lakes and streams and the handling and disposal of waste material.

Air - The U.S. Environmental Protection Agency (EPA) has ozone transport and acid rain regulations and, in December 2003, proposed additional emission regulations relating to ozone, fine particulate and mercury air pollution. The new rules would lead to additional controls on fossil-fueled power plants to reduce nitrogen oxides, sulfur dioxide and mercury emissions. To comply with existing requirements, Detroit Edison has spent approximately $580 million through December 2004 and estimates that it will spend up to $100 million in 2005. Detroit Edison will incur from $700 million to $1.3 billion of additional future capital expenditures over the next five to eight years to satisfy both the existing and proposed new control requirements.

The EPA initiated enforcement actions against several major electric utilities citing violations of new source provisions of the Clean Air Act. Detroit Edison received and responded to information requests from the EPA on this subject. The EPA has not initiated proceedings against Detroit Edison. In October 2003, the EPA promulgated revised regulations to clarify new source review provisions going forward. Several states and environmental organizations have challenged these regulations and, in December 2003, the Court stayed the implementation of the regulations until the U.S. Court of Appeals D.C. Circuit renders an opinion in the case. We cannot predict the future impact of this issue upon Detroit Edison.

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 studies to be conducted over the next several years, Detroit Edison may be required to install additional control technologies to reduce the environmental impact of the intakes. Detroit Edison estimates that it will incur up to $50 million over the next five to seven years in additional capital expenditures to comply with these requirements.

Contaminated Sites - Detroit Edison conducted remedial investigations at contaminated sites, including two former manufactured gas plant 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 $8 million, which is expected to be incurred over the next several years. As a result of the investigation, Detroit Edison accrued an $8 million liability during 2004.

Various state and federal laws regulate our handling, storage and disposal of waste materials. The EPA and the MDEQ have aggressive programs to manage the clean up of contaminated property. We have extensive land holdings and, from time to time, must investigate claims of improperly disposed contaminants. We anticipate our utility and non-utility companies may periodically be included in various types of environmental proceedings.

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 businesses. Although we have tried to identify and discuss key risk factors, others could emerge in the future. Each of the following risks could affect our performance.

Michigan’s electric Customer Choice program is negatively impacting our financial performance. Even with the Customer Choice-related rate relief received in Detroit Edison’s 2004 rate orders, there continues to be considerable financial risk associated with the Customer Choice program. Choice migration is sensitive to market price, transition charges and electric bundled 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.

Our operations continue to be negatively affected by competition. Deregulation and restructuring in the electric industry has resulted in increased competition and unrecovered costs that have affected and may continue to affect our financial condition, results of operations or cash flows. We are a regulated public utility, and this regulation has hindered our ability to retain customers in a competitive marketplace.

We are subject to rate regulation. We operate in a regulated industry. 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. A credit agency currently has a “negative outlook” on our ratings. 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 may unfavorably impact 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 because of our emission of gases that may cause changes in the climate. The regulatory environment is subject to significant change and, therefore, we cannot predict future issues.

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 Detroit Edison to significant additional risks. These risks among others, include plant security, environmental regulation and remediation, and operational factors that can significantly impact the performance and cost of operating a nuclear facility. While Detroit Edison maintains 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 fluctuation and coal and other fuel supply disruptions could have a negative impact on our ability to profitably generate electricity. We have hedging strategies in place to mitigate negative fluctuations in commodity supply prices but there can be no assurances that our financial performance will not be negatively impacted by price fluctuations.

A work interruption may adversely affect us. Unions represent a majority of our employees. A union choosing to strike as a negotiating tactic would have an impact on our business.

Unplanned power plant outages may be costly. Unforeseen maintenance may be required to safely produce electricity or comply with environmental regulations. 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.

Property tax reform may be costly. We are one of the largest payers of property taxes in the State of Michigan. Should the legislature change how schools are financed, we could face increased property taxes on our Michigan facilities.

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 terrorist groups would impact our operations. We have increased security as a result of recent events and further security increases are expected.

Failure to successfully implement new information systems could interrupt our operations. Our business depends on numerous information systems for operations and financial information and billings. We are in the process of launching the first phase of our DTE2 project, a multiyear Company-wide initiative to improve existing processes and implement new core information systems. Failure to successfully implement DTE2 could interrupt our operations.

EMPLOYEES

We had 7,838 employees at December 31, 2004, of which 3,918 were represented by unions. Of the represented employees, 3,434 are under a three-year contract that was ratified in 2004. The contract of the remaining represented employees expires in 2005.

Item 3. Legal Proceedings

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

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


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

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

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

Part II

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

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

We paid cash dividends of $303 million in 2004 and $295 million in 2003 and 2002.

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 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).

We had net income of $150 million in 2004, compared to net income of $246 million in 2003 and $356 million in 2002. As subsequently discussed, the comparability of earnings was impacted by the adoption of a new accounting rule in 2003.

The following sections provide a detailed discussion of our segments, operating performance and future outlook.

Segment Performance & Outlook – We operate our business through two segments, Energy Resources – Power Generation and Energy Distribution – Power Distribution.



(in Millions)	2004		2003			2002
Net Income

Energy Resources — Power Generation	$	62	$	235		$	245
Energy Distribution — Power Distribution		88		17			111

Income Before Accounting Change		150		252			356
Cumulative Effect of Accounting Changes		—		(6	)		—

Net Income	$	150	$	246		$	356

ENERGY RESOURCES

Power Generation

The power generation plants of Detroit Edison comprise our regulated power generation business. Detroit Edison’s numerous fossil plants, its hydroelectric pumped storage plant and its nuclear plant generate electricity. The generated electricity, supplemented with purchased power, is sold principally throughout Michigan and the Midwest to residential, commercial, industrial and wholesale customers.

Factors impacting income: Power Generation earnings decreased $173 million in 2004 and $10 million in 2003, compared to the prior year. As subsequently discussed, these results primarily reflect reduced gross margins and increased operation and maintenance expenses.



(in Millions)	2004			2003			2002
Operating Revenues	$	2,210		$	2,448		$	2,711
Fuel and Purchased Power		868			920			1,048

Gross Margin		1,342			1,528			1,663
Operation and Maintenance		672			628			622
Depreciation and Amortization		272			224			331
Taxes Other Than Income		147			157			156

Operating Income		251			519			554
Other (Income) and Deductions		166			149			189
Income Tax Provision		23			135			120

Net Income	$	62		$	235		$	245

Operating Income as a Percent of Operating Revenues		11	%		21	%		20	%

Gross margins declined $186 million during 2004 and $135 million in 2003. The declines were due primarily to lost margins from retail customers choosing to purchase power from alternative suppliers under the electric Customer Choice program as well as reduced cooling demand resulting from mild summer weather. As a result of electric Customer Choice penetration, Detroit Edison lost 18% of retail sales in 2004, compared to 12% of such sales during 2003. 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 previously discussed, 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 Power Supply Cost Recovery (PSCR) revenues, which were partially offset by increased base rate and transition charge revenues.

Weather in 2004 was 3% milder than 2003, resulting in lost margins of $25 million. Weather in 2003 was also milder than the prior year, resulting in lost margins of $114 million. The decline in margins and revenues in 2004 was also due to the allocation of a smaller portion of Detroit Edison’s billings to Power Generation.

(BAR CHART)

Operating revenues and fuel and purchased power costs decreased in 2004 and 2003 reflecting a $1.27 per megawatt hour (MWh) (8%) decline in fuel and purchased power costs during 2004 and a $.64 per MWh (4%) decline during 2003. Fuel and purchased power costs are a pass-through with the reinstatement of the PSCR in 2004, and therefore do 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. The comparison was also affected by higher costs associated with substitute power purchased to meet customer demand during the August 2003 blackout. We were required to purchase additional power during the 36-day period it took for our generation fleet to return to pre-blackout capacity.



	2004		2003		2002
Electric Sales and Use
(in Thousands of MWh)
Retail		40,379		43,672		48,346
Wholesale and Other		8,569		5,600		6,128

		48,948		49,272		54,474
Internal Use and Line Loss		3,574		3,248		3,651

		52,522		52,520		58,125


	2004				2003				2002
Power Generated and Purchased
(in Thousands of MWh)
Power Plant Generation
Fossil		39,432	75	%		38,052	72	%		39,017	67	%
Nuclear (Fermi 2)		8,440	16			8,114	16			9,301	16

		47,872	91			46,166	88			48,318	83
Purchased Power		4,650	9			6,354	12			9,807	17

System Output		52,522	100	%		52,520	100	%		58,125	100	%


Average Unit Cost ($/MWh)
Generation (1)	$	12.98			$	12.89			$	12.53

Purchased Power (2)	$	37.06			$	41.73			$	39.16

Overall Average Unit Cost	$	15.11			$	16.38			$	17.02

(1)		Represents fuel costs associated with power plants.

(2)		Includes amounts associated with hedging activities.

Operation and maintenance expense increased $44 million in 2004 and $6 million in 2003. 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, a Company-wide initiative to improve existing processes and to implement new core information systems, including finance, human resources, supply chain and work management. 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 trend rates. Expenses in 2003 were also affected by $5 million in costs associated with the August 2003 blackout.

Depreciation and amortization expense increased $48 million in 2004 and decreased $107 million in 2003. The variations reflect the income effect of recording regulatory assets, which lowered depreciation and amortization expenses. The regulatory asset deferrals totaled $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.

Other income and deductions expense increased $17 million in 2004 and decreased $40 million in 2003. 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. The 2003 decrease is attributable to lower interest expenses and increased interest income. Interest expense reflects lower borrowing levels and rates, and interest income includes the accrual of carrying charges on environmental-related regulatory assets.

Outlook – Future operating results are expected to vary as a result of external factors such as regulatory proceedings, new legislation, changes in market prices of power, coal and gas, plant performance, changes in economic conditions, weather and the 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 addressed. We will accrue as regulatory assets our unrecovered generation-related fixed costs (stranded costs) due to electric Customer Choice that we believe are recoverable under Michigan legislation and MPSC orders. We have addressed certain issues of the electric Customer Choice program in our February 2005 rate restructuring proposal. We cannot predict the outcome of these matters.

In conjunction with DTE Energy’s sale of the transmission assets of ITC in February 2003, the Federal Energy Regulatory Commission (FERC) froze ITC’s transmission rates through December 2004. It is expected that annual rate adjustments pursuant to a formulistic pricing mechanism beginning in January 2005 will result in an estimated increase in Detroit Edison’s transmission expense of $50 million annually. Additionally, in a proceeding before the FERC, several Midwest utilities seek to recover transmission revenues lost as a result of a FERC order modifying the pricing of transmission service in the Midwest. Detroit Edison estimates that its potential obligation as a result of this proceeding could be $2.2 million per month from December 2004 through March 2005 and $1 million per month from April 2005 through March 2006. Detroit Edison is expected to incur an additional $15 million in 2005 for charges related to the implementation of Midwest Independent Transmission System Operator’s open market. As previously discussed, Detroit Edison received rate orders in 2004 that allow for the recovery of increased transmission expenses through the PSCR mechanism.

See Note 4 – Regulatory Matters.

ENERGY DISTRIBUTION

Power Distribution

Power Distribution operations include the electric distribution services of Detroit Edison. Power Distribution distributes electricity generated and purchased by Energy Resources and alternative energy suppliers to Detroit Edison’s 2.1 million customers.

Factors impacting income: Power Distribution earnings increased $71 million during 2004 and decreased $94 million in 2003, compared to the prior year. As subsequently discussed, these results primarily reflect varying operating revenues and operation and maintenance expenses, as well as a non-recurring loss recorded in 2003.



	2004			2003			2002
(in Millions)
Operating Revenues	$	1,358		$	1,247		$	1,343
Fuel and Purchased Power		17			19			26
Operation and Maintenance		723			724			649
Depreciation and Amortization		251			249			246
Taxes Other Than Income		101			100			117

Operating Income		266			155			305
Other (Income) and Deductions		137			128			136
Income Tax Provision		41			10			58

Net Income	$	88		$	17		$	111


Operating Income as a Percent of Operating Revenues		20	%		12	%		23	%

Electric Deliveries


	2004		2003		2002
(in Thousands of MWh)
Residential		15,081		15,074		15,958
Commercial		13,425		15,942		18,395
Industrial		11,472		12,254		13,590
Wholesale		2,197		2,241		2,249
Other		401		402		403

		42,576		45,913		50,595
Electric Choice		9,245		6,193		2,967
Electric Choice – Self Generations*		595		1,088		543

Total Electric Deliveries		52,416		53,194		54,105

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

Operating revenues increased $111 million in 2004, primarily due to an increase in base rates resulting from the interim and final rate orders. The 2004 improvement is also attributable to residential sales growth and the allocation of a higher portion of Detroit Edison’s billings to Power Distribution, partially offset by the effects of milder weather. Operating revenues decreased $96 million in 2003, reflecting mild summer weather and the impact of slower economic conditions.

Operation and maintenance expense decreased $1 million in 2004 and increased $75 million in 2003. The operation and maintenance expense comparability was affected by 2003 restoration costs associated with three catastrophic storms and the August 2003 blackout. Both years were also affected by an increase in reserves for uncollectible accounts receivable, reflecting high past due amounts attributable to economic conditions, and an increase in employee benefit costs. Additionally, the comparisons were affected by incremental costs associated with our DTE2 project implementation, a $22 million pre-tax loss in 2003 from the sale of our steam heating business, and the accrual of refunds in 2004 and 2003 associated with transmission services.

(BAR CHART)

Outlook – Operating results are expected to vary as a result of external factors such as weather, changes in economic conditions and the severity and frequency of storms.

We experienced numerous catastrophic storms over the past few years. The effect of the storms on annual earnings was partially offset by storm insurance. We have been unable to obtain storm insurance at economical rates and as a result, we do not anticipate having insurance coverage at levels that would significantly offset unplanned expenses from ice storms, tornadoes, or high winds that damage our distribution infrastructure.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES

As required by U.S. generally accepted accounting principles, 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 for further discussion.

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 purchase of 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 (Note 1).

See Note 12 – Financial and Other Derivative Instruments for further discussion.

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, 2004 would decrease $189 million and increase $200 million, respectively.

Credit Risk

We purchase and sell electricity from and to numerous companies operating in the steel, automotive, energy, retail and other industries. A number of customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We have negotiated or are currently involved in negotiations with each of the companies, or

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

/S/ DELOITTE & TOUCHE LLP

Detroit, Michigan
March 15, 2005

The Detroit Edison Company

Consolidated Statement of Operations


	Year Ended December 31
	2004			2003			2002
(in Millions)
Operating Revenues	$	3,568		$	3,695		$	4,054


Operating Expenses
Fuel and purchased power		885			939			1,074
Operation and maintenance		1,394			1,352			1,271
Depreciation and amortization		523			473			577
Taxes other than income		249			257			273

		3,051			3,021			3,195


Operating Income		517			674			859


Other (Income) and Deductions
Interest expense		280			284			311
Interest income		—			(7	)		(1	)
Other income		(66	)		(93	)		(36	)
Other expenses		89			93			51

		303			277			325


Income Before Income Taxes		214			397			534


Income Tax Provision		64			145			178


Income Before Accounting Change		150			252			356

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


Net Income	$	150		$	246		$	356

See Notes to Consolidated Financial Statements

The Detroit Edison Company

Consolidated Statement of Financial Position


	December 31
	2004			2003
(in Millions)
Assets
Current Assets
Cash and cash equivalents	$	6		$	6
Restricted cash		75			82
Accounts receivable
Customer (less allowance for doubtful accounts of $55 and $51, respectively)		258			291
Accrued unbilled revenues		207			196
Other		120			169
Inventories
Fuel		100			108
Materials and supplies		118			124
Notes receivable from affiliate (Note 15)		85			7
Other		46			22

		1,015			1,005


Investments
Nuclear decommissioning trust funds		590			518
Other		55			54

		645			572


Property
Property, plant and equipment		12,931			12,671
Less accumulated depreciation (Note 2)		(5,354	)		(5,339	)

		7,577			7,332


Other Assets
Regulatory assets (Note 4)		2,053			2,000
Securitized regulatory assets (Note 4)		1,438			1,527
Other		114			113

		3,605			3,640

Total Assets	$	12,842		$	12,549

See Notes to Consolidated Financial Statements

The Detroit Edison Company

Consolidated Statement of Financial Position


	December 31
	2004			2003
(in Millions, Except Shares)
Liabilities and Shareholder’s Equity
Current Liabilities
Accounts payable	$	346		$	211
Accrued interest		79			76
Dividends payable (Note 15)		76			74
Accrued payroll		12			27
Accrued vacations		76			76
Short-term borrowings		—			100
Accrued PSCR refund		112			—
Current portion long-term debt, including capital leases		499			144
Other		130			213

		1,330			921


Other Liabilities
Deferred income taxes		1,941			1,783
Regulatory liabilities (Notes 2 and 4)		253			254
Asset retirement obligations (Note 2)		869			819
Unamortized investment tax credit		125			135
Nuclear decommissioning (Notes 2 and 5)		77			67
Accrued pension liability		247			321
Other		676			639

		4,188			4,018


Long-Term Debt (net of current portion) (Note 9)
Mortgage bonds, notes and other		2,879			3,076
Securitization bonds		1,400			1,496
Capital lease obligations		66			75

		4,345			4,647


Commitments and Contingencies (Notes 4, 5 and 13)

Shareholder’s Equity
Common stock, $10 par value, 400,000,000 shares authorized, 138,632,324 and 134,287,832 shares issued and outstanding		1,386			1,343
Premium on common stock		1,104			977
Common stock expense		(44	)		(44	)
Retained earnings		531			686
Accumulated other comprehensive income		2			1

		2,979			2,963


Total Liabilities and Shareholder’s Equity	$	12,842		$	12,549

See Notes to Consolidated Financial Statements

The Detroit Edison Company

Consolidated Statement of Cash Flows


	Year Ended December 31
	2004			2003			2002
(in Millions)
Operating Activities
Net Income	$	150		$	246		$	356
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		523			473			577
Deferred income taxes		142			32			(52	)
Loss (gain) on sale of assets		(1	)		21			—
Cumulative effect of accounting change		—			6			—
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		376			(13	)		(123	)

Net cash from operating activities		1,190			765			758

Investing Activities
Plant and equipment expenditures		(702	)		(580	)		(685	)
Proceeds from sale of assets		1			2			—
Restricted cash for debt redemptions		6			49			(63	)
Notes receivable from affiliate		(78	)		50			(57	)
Other investments		(66	)		(126	)		(86	)

Net cash used for investing activities		(839	)		(605	)		(891	)

Financing Activities
Issuance of long-term debt		266			49			570
Redemption of long-term debt		(206	)		(504	)		(318	)
Short-term borrowings, net		(100	)		100			—
Capital contribution by parent company		—			470			—
Repurchase of common stock		—			—			—
Dividends on common stock		(303	)		(295	)		(295	)
Other		(8	)		(10	)		(3	)

Net cash used for financing activities		(351	)		(190	)		(46	)

Net Increase (Decrease) in Cash and Cash Equivalents		—			(30	)		(179	)
Cash and Cash Equivalents at Beginning of the Period		6			36			215

Cash and Cash Equivalents at End of the Period	$	6		$	6		$	36

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, 2001		134,288	$	1,343	$	507	$	(44	)	$	675		$	(23	)	$	2,458

Net income		—		—		—		—			356			—			356
Dividends declared on Common stock		—		—		—		—			(296	)		—			(296	)
Net change in unrealized losses on derivatives, net of tax		—		—		—		—			—			21			21
Pension obligation (Note 14)		—		—		—		—			—			(417	)		(417	)

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

The following table displays comprehensive income (loss):


(in Millions)	2004		2003			2002
Net income	$	150	$	246		$	356

Other comprehensive income (loss), net of tax:
Net unrealized losses on derivatives:
Gains or (losses) arising during the period, net of taxes of $-, $4 and $-		—		8			(1	)
Amounts reclassified to earnings, net of taxes of $-, $(3) and $11		—		(5	)		22

		—		3			21

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

Comprehensive income (loss)	$	151	$	666		$	(40	)

See Notes to Consolidated Financial Statements

The Detroit Edison Company

Notes to Consolidated Financial Statements

NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure

Detroit Edison is a Michigan public utility engaged in the generation, purchase, distribution and sale of electric energy to 2.1 million customers in a 7,600 square-mile area in southeastern Michigan. Detroit Edison is regulated by the Michigan Public Service Commission (MPSC) and the Federal Energy Regulatory Commission (FERC).

References in this report to “we,” “us” and “our” 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.

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 – New Accounting Pronouncements.

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 Power Supply Cost Recovery (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. See Note 4 for further discussion. Accordingly, Detroit Edison did not accrue revenues under the PSCR mechanism prior to 2004.

Comprehensive Income

We comply with Statement of Financial Accounting Standards (SFAS) No. 130, “Reporting Comprehensive Income,” that established standards for reporting comprehensive income. SFAS No. 130

defines comprehensive income as 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, 2004 include: unrealized gains and losses from derivatives accounted for as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.”




	Net		Net		Accumulated
	Unrealized		Unrealized		Other
	Gain on		Losses on		Comprehensive
(in Millions)	Investments		Derivatives		Income (Loss)
Beginning balance	$	—	$	1	$	1
Current-period change		1		—		1

Ending balance	$	1	$	1	$	2

Cash Equivalents and Restricted Cash

Cash and cash equivalents include cash on hand, cash in banks and temporary investments 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)	2004			2003
Property, Plant and Equipment
Electric Utility
Generation	$	7,100		$	6,938
Distribution		5,831			5,733

Total		12,931			12,671


Less Accumulated Depreciation and Depletion
Electric Utility
Generation		(3,277	)		(3,231	)
Distribution		(2,077	)		(2,108	)

Total		(5,354	)		(5,339	)


Net Property, Plant and Equipment	$	7,577		$	7,332

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

Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2. Approximately $3.8 million of expenses related to the anticipated Fermi 2 refueling outage scheduled for 2006 were accrued at December 31, 2004. 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 2004, 2003 and 2002.

The average estimated useful life for each class of property, plant and equipment as of December 31, 2004 follows:




Estimated Useful Lives in Years
Generation		Distribution
	39		37

We credit depreciation and amortization expense when we establish regulatory assets for stranded costs related to the electric Customer Choice program and deferred environmental expenditures.

Long-Lived Assets

Long-lived assets that we own 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 expected periods of benefit. Intangible assets amortization expense was $32 million in 2004, $30 million in 2003 and $36 million in 2002. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2004 were $253 million and $88 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2003 were $352 million and $250 million, respectively. Amortization expense of intangible assets is estimated to be $27 million annually for 2005 through 2009.

Excise and Sales Taxes

We record the billing of excise and sales taxes as receivables with an offsetting payable to the applicable taxing authority, with no impact on the 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 applicable to Detroit Edison, 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

We have a comprehensive insurance program in place to provide coverage for various types of risks. Our insurance policies cover risk of loss from various events, including property damage, general liability, workers’ compensation, auto liability 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 periodically review our insurance coverage. During 2003, we reviewed our process for estimating and recognizing reserves for self-insured risks. As a result of this review, we revised the process for estimating liabilities under our self-insured layers to include an actuarially determined estimate of “incurred but not reported” (IBNR) claims. We have an actuarially determined estimate of our IBNR liability prepared annually and adjust the related reserve 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 (Note 5).

Consolidated Statement of Cash Flows

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




(in Millions)	2004			2003			2002
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	91		$	13		$	40
Accrued unbilled receivables		(11	)		(19	)		(47	)
Inventories		14			18			34
Accrued pensions		123			(179	)		(44	)
Accounts payable		135			(27	)		(78	)
Accrued PSCR refund		112			—			—
Accrued payroll		(15	)		3			(65	)
Income taxes payable		(14	)		(24	)		(75	)
General taxes		(13	)		(7	)		(2	)
Risk management and trading activities		(1	)		(7	)		(32	)
Postretirement obligation		11			93			60
Other		(56	)		123			86

	$	376		$	(13	)	$	(123	)

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




(in Millions)	2004		2003		2002
Cash Paid for
Interest (excluding interest capitalized)	$	277	$	291	$	312
Income taxes		2		153		308
Non-cash Financing Activity
Common stock issued to parent company in conjunction with parent company common stock contribution to pension plan		170		—		—

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


Note		Title

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

NOTE 2 – NEW ACCOUNTING PRONOUNCEMENTS

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 2 nuclear plants. We believe that adoption of SFAS No. 143 results primarily in timing differences in the recognition of legal asset retirement costs that we are currently recovering in rates and are deferring such differences under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.”

As a result of adopting SFAS No. 143 on January 1, 2003, we recorded a plant asset of $278 million with offsetting accumulated depreciation of $103 million, a retirement obligation liability of $771 million and reversed previously recognized obligations of $366 million, principally nuclear decommissioning liabilities. We also recorded a cumulative effect amount related to utility operations as a regulatory asset of $221 million, and a cumulative effect charge against earnings of $6 million (net of tax of $4 million) for 2003.

If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, such as assets with an indeterminate life, the liability is to be recognized when a reasonable estimate of fair value can be made. Generally, distribution assets have an indeterminate life, retirement cash flows cannot be determined and there is a low probability of retirement, therefore no liability has been recorded for these assets.

The impact on the twelve-month period of 2003 of SFAS No. 143 and the pro-forma effect for the comparable 2002 periods as if SFAS No. 143 had been adopted at January 1, 2002 are immaterial.

A reconciliation of the asset retirement obligation for 2004 follows:



(in Millions)
Asset retirement obligations at January 1, 2004	$	819
Accretion		55
Liabilities settled		(5	)

Asset retirement obligations at December 31, 2004	$	869

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.

SFAS No. 143 also requires the quantification of the estimated cost of removal obligations, arising from other than legal obligations, which have been accrued through depreciation charges. At December 31, 2003, we reclassified approximately $238 million of previously accrued asset removal costs, which had been previously netted against accumulated depreciation to regulatory liabilities. There is a generic case

before the MPSC to determine the accounting and regulatory treatment of removal costs for Michigan utilities.

Consolidation of Variable Interest Entities

In January 2003, FASB Interpretation No. (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 $12 million in 2004.

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. The steam heating business had assets of $6

million at December 31, 2002, and had net losses of $12 million in 2002. See Note 13 – Commitments and Contingencies.

NOTE 4 - REGULATORY MATTERS

Regulation

Detroit Edison is subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to retail 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)	2004			2003
Assets
Securitized regulatory assets	$	1,438		$	1,527


Recoverable income taxes related to securitized regulatory assets	$	788		$	837
Recoverable minimum pension liability		604			583
Asset retirement obligation		183			192
Other recoverable income taxes		109			114
Recoverable costs under PA 141
Net stranded costs		122			68
Excess capital investment		7			—
Deferred Clean Air Act expenditures		76			54
Midwest Independent System Operator charges		27			21
Transmission integration costs		—			10
Electric Customer Choice implementation costs		95			84
Enhanced security costs		8			6
Unamortized loss on reacquired debt		29			28
Other		5			3

	$	2,053		$	2,000


Liabilities
Asset removal costs	$	250		$	238
Excess securitization savings		—			14
Customer refund – 1997 storm		2			2
Accrued PSCR refund		112			—
Other		1			—

		365			254
Less amount included in current liabilities		(112	)		—

	$	253		$	254

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.

•   Recoverable minimum pension liability — An additional minimum pension liability was recorded under generally accepted accounting principles (Note 14) 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.

•   Asset retirement obligation — Asset retirement obligations were recorded pursuant to adoption of SFAS No. 143 in 2003. 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.

•   Transmission integration costs —The MPSC’s November 2004 final rate order denied recovery and determined these costs to be transaction expenses in DTE Energy’s sale of ITC.

•   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 141 permits, after MPSC authorization, the recovery of enhanced homeland 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.

LIABILITIES

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

•   Excess securitization savings — Savings associated with the 2001 securitization of Fermi 2 and other costs are refundable to Detroit Edison’s customers.

•   Customer refund – 1997 storm — The over collection of 1997 storm costs, which will be refunded in accordance with the MPSC’s November 2004 rate order.

•   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.

Electric Rate Case

Rate Request- In June 2003, Detroit Edison filed an application with the MPSC requesting a change in retail electric rates, resumption of the PSCR mechanism, and recovery of net stranded costs. The application and subsequent revisions resulted in a request to increase base rates by $583 million annually.

In addition, Detroit Edison requested recovery of certain regulatory assets. As subsequently discussed, Detroit Edison received interim and final rate orders relating to its June 2003 rate application.

A summary of the rate orders follows:




	Interim			Final
	Rate			Rate
	Increase (1)			Increase (1)
(in Millions)
Base Rate Revenue Deficiency	$	248		$	336
Recovery of SMC Discounts		—			38

Overall Base Rate Increase		248			374
PSCR Savings		(126	)		(126	)

Total	$	122		$	248


	Actual			Estimate
	2004			2005 (2)		Total
Cumulative Recoverable Regulatory Assets
Clean Air Act	$	76		$	68	$	144
MISO Transmission Costs		27			49		76
Excess Capital Expenditures		7			15		22
Customer Refund – 1997 Storm		(2	)		—		(2	)

		108			132		240
Electric Choice Implementation Costs		95			6		101
Net Stranded Costs		44			—		44

Total	$	247		$	138	$	385

(1)		The impact of rate caps not included.

(2)		Represents estimated amounts to be incurred in 2005, as well as carrying costs on unrecovered balances, that were authorized for recovery by the MPSC. Actual amounts incurred are subject to review in future MPSC proceedings, and any overcollections or undercollections will be reflected in future rates.

MPSC Interim Rate Order - On February 20, 2004, the MPSC issued an order for interim rate relief. The order authorized an interim increase in base rates, a transition charge for customers participating in the electric Customer Choice program and a new PSCR factor.

The interim base rate increase totaled $248 million annually, effective February 21, 2004, and was applicable to all customers not subject to a rate cap. The increase was allocated to both full-service customers ($240 million) and electric Customer Choice customers ($8 million). However, because of the rate caps under PA 141, not all of the increase was realized in 2004. The interim order also terminated certain transition credits and authorized transition charges to electric Customer Choice customers designed to result in $30 million in additional revenues. Additionally, the MPSC authorized a reduced PSCR factor for all customers, designed to lower revenues by $126 million annually. However, the MPSC order allowed Detroit Edison to increase base rates for customers still subject to the cap in an equal and offsetting amount with the required reduction in the PSCR factor to maintain the total capped rate levels currently in effect for these customers.

The MPSC deferred addressing other items in the rate request, including a surcharge to recover regulatory assets, until a final rate order was issued.

MPSC Final Rate Order - On November 23, 2004, the MPSC issued an order for final rate relief. The MPSC determined that the base rate increase granted to Detroit Edison should be $336 million annually effective November 24, 2004 and is applicable to all customers not subject to the rate cap. The final order provides for the future recovery of losses resulting from electric Customer Choice. Additionally, beginning in 2005, the final order allows Detroit Edison to recover the discounts previously provided to special manufacturing contract (SMC) customers of $38 million, resulting in an overall base rate increase of $374 million annually. As subsequently discussed, Detroit Edison has been deferring certain costs as regulatory assets that it believes are recoverable under PA 141 once rate caps expire. The final order

addressed numerous issues relating to regulatory assets, including the amounts recoverable and the recovery mechanism. The final order authorized the recovery of a lower level of stranded costs than had been recorded through February 20, 2004, the date of the interim order. Accordingly, Detroit Edison adjusted its net stranded costs related regulatory asset, which decreased 2004 net income by $21 million.

The MPSC’s final order authorizes the recovery of approximately $385 million of regulatory assets through three mechanisms:

• The first mechanism recovers certain accrued regulatory assets over a five-year period using a regulatory asset recovery surcharge (RARS) and is collectible from all full service customers as their rate caps expire. The total amount to be collected is estimated to be $240 million, plus carrying costs of 9.74% on unrecovered balances. The recoverable regulatory assets include costs associated with Clean Air Act compliance, deferred Midwest Independent System Operator (MISO) transmission fees, and deferred excess capital expenditures. The MPSC also authorized the refunding of over collected 1997 storm costs.

• The second mechanism includes a surcharge to recover electric Customer Choice implementation costs of $101 million and is collectible from both full service and electric Customer Choice customers. This charge will not be implemented until all current rate caps expire in 2006 and will include carrying costs of 7% on unrecovered balances.

• The third mechanism includes a surcharge to recover $44 million in historical stranded costs incurred in 2002, 2003 and January and February 2004 and is collectible from electric Customer Choice customers, including carrying costs of 7% on unrecovered balances.

Other significant items authorized by the MPSC in its final order:

• Rate increase was based on a 54% debt and 46% equity capital structure, and an 11% rate of return on common equity.

• Customer rate caps do not expire until January 2006. As a result, the MPSC determined that there is a need to true-up stranded costs for at least 2004. This true-up case must be filed by March 31, 2005. The MPSC also permits Detroit Edison to file additional annual stranded cost true-up proceedings if it deems appropriate to do so pursuant to PA 141.

• Transmission and MISO costs and costs associated with nitrogen oxide (NOx) allowances will be recoverable through the PSCR mechanism and charged to full service customers; however, costs associated with sulfur dioxide (SOx) allowances will not be included in the PSCR, but recoverable through base rates.

• Full cost recovery of $550 million of Clean Air Act environmental expenditures was authorized. We believe that future mandated environmental expenditures will also be recovered through base rates.

• A pension tracking mechanism was established to manage changes in pension costs. Under the tracking mechanism, Detroit Edison would recover or refund pension costs above or below the amount reflected in base rates. Detroit Edison was also required to propose a similar tracking mechanism for retiree health care costs. In February 2005, Detroit Edison filed a request with the MPSC seeking authority to implement a tracking mechanism for retiree health care costs (Other Postemployment Benefits Costs Tracker).

• Detroit Edison was ordered to file a rate unbundling and restructuring case by March 23, 2005. As subsequently discussed, this rate restructuring proposal was filed on February 4, 2005.

• Changes to the existing electric Customer Choice program regarding customers returning to full utility service. Customers electing to participate in the electric Customer Choice program will not be permitted to return to Detroit Edison’s full service rates for two years. Electric Customer Choice customers returning to full service must remain on bundled rates for at least one year following their return. Customers who fail to give the appropriate notice or do not stay on the electric Customer Choice program for two years are required to pay the higher of the applicable tariff energy price plus 10%, or the market price of power plus 10%, for any power taken from Detroit Edison.

In December 2004, Detroit Edison and other parties filed petitions for rehearing relating to the MPSC’s November 2004 final rate order. Among other items, Detroit Edison’s petition requests a correction of the capital structure used in determination of the final order and recovery of certain disallowed costs. Detroit Edison awaits an MPSC decision on the petitions for rehearing.

Electric Rate Restructuring Proposal

On February 4, 2005, Detroit Edison filed a rate restructuring proposal with the MPSC to restructure its electric rates and begin phasing out subsidies that are part of its current pricing structure. The proposal would adjust rates for each customer class to be reflective of the full costs incurred to service such customers. Under the proposal, commercial and industrial rates would be lowered, but residential rates would increase over a five-year period beginning in 2007. The MPSC anticipates that this proceeding will be completed in time to have new rates in effect no later than January 1, 2006.

Other Postemployment Benefits Costs Tracker

On February 10, 2005, Detroit Edison filed an application requesting MPSC approval of a proposed tracking mechanism for retiree health care costs. The application was filed as required pursuant to the MPSC’s November 2004 order.

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 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. Detroit Edison has appealed. As previously discussed, the MPSC’s November 2004 final 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. Since March 1, 2004, Detroit Edison has recorded $108 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.

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 the company’s consolidated statement of financial position. The Company makes 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.

Excess Securitization Savings — In January 2004, the MPSC issued an order directing Detroit Edison to file a report by March 15, 2004, of the accounting of the savings due to securitization and the application of those savings through December 2003. In addition, Detroit Edison was requested to include in the report an estimate of the foregone carrying cost associated with the excess securitization savings. A report was filed on February 16, 2004 in compliance with the MPSC order.

DTE2 Accounting Application

In 2003, we began the implementation of DTE2, a Company-wide initiative to improve existing processes and to implement new core information systems, including finance, human resources, supply chain and work management. The new information systems are replacing systems that are approaching the end of their useful lives. We expect the benefits of DTE2 to include lower costs, faster business cycles, repeatable and optimized processes, enhanced internal controls, improvements in inventory management and reductions in system support costs.

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. Through December 2004, we have expensed approximately $12 million of training, maintenance and overhead costs pending MPSC action on our application. Detroit Edison is proposing a 15-year amortization period for the costs, exclusive of the computer equipment costs.

Power Supply Cost Recovery Proceedings

2004 Plan Year – An MPSC December 2003 order resumed the PSCR mechanism that had been suspended while rates were frozen. The order authorized a new PSCR factor for all customers effective January 1, 2004. The MPSC’s February 2004 interim order provided for a credit of 1.05 mills per kWh compared to a 2.04 mills per kWh charge previously in effect. Detroit Edison will file a 2004 PSCR reconciliation case by March 31, 2005.

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 NOx emission allowance costs. Detroit Edison self-implemented a factor of a negative 2.00 mills per kWh on January 1, 2005. The Michigan Attorney General has filed a motion for summary disposition of this proceeding based on arguments that the PSCR statute requires a fixed 48-month PSCR factor. We cannot predict the nature or timing of actions the MPSC will take on this motion.

Transmission Proceedings

On November 18, 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 would be $2.2 million per month from December 2004 through March 2005. Detroit Edison has estimated that the SECA charge for the April 2005 through March 2006 period will be approximately $1 million per month. On December 20, 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. 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, “Employers’ Accounting for Pensions,” 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. In 2004 and 2003, we reclassified approximately $604 million ($393 million net of tax) and $583 million ($379 million net of tax), respectively, of other comprehensive loss associated with the minimum pension liability to a regulatory asset (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, which may materially impact the financial position, results of operations and cash flows of the Company.

NOTE 5 – NUCLEAR OPERATIONS

General

Fermi 2, our nuclear generating plant, began commercial operation in 1988. Fermi 2 has a design electrical rating (net) of 1,150 megawatts. This plant represents approximately 10% of Detroit Edison’s summer net rated capability. The net book balance of the Fermi 2 plant was written off at December 31, 1998, and an equivalent regulatory asset was established. In 2001, the Fermi 2 regulatory asset was securitized. See Note 4 — Regulatory Matters. Detroit Edison also owns Fermi 1, a nuclear plant that was shut down in 1972 and is currently being decommissioned. The NRC has jurisdiction over the licensing and operation of Fermi 2 and the decommissioning of Fermi 1.

Property Insurance

Detroit Edison maintains several different types of property insurance policies specifically for the Fermi 2 plant. These policies cover such items as replacement power and property damage. The Nuclear Electric Insurance Limited (NEIL) is the primary supplier of these 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 Act (TRIA) of 2002 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 $28 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 1988 (Act), deferred premium charges up to $101 million could be levied against each licensed nuclear facility, but not more than $10 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. The Act expired on August 1, 2002. During 2003, the U.S. Congress extended the Act for commercial nuclear facilities through December 31, 2003. However, provisions of the Act remain in effect for existing commercial reactors. Legislation to extend the Act in conjunction with comprehensive energy legislation is currently under debate in Congress. We cannot predict whether Congress will pass the legislation.

Decommissioning

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.

Detroit Edison has established a restricted external trust to hold funds collected from customers for decommissioning and the disposal of low-level radioactive waste. Detroit Edison collected $38 million in 2004, $36 million in 2003 and $42 million in 2002 from customers for decommissioning and low-level radioactive waste disposal. Net unrealized investment gains of $17 million and $62 million in 2004 and 2003, respectively, and $39 million in losses in 2002, were recorded as adjustments to the nuclear

decommissioning trust funds and regulatory assets. At December 31, 2004, investments in the external trust consisted of approximately 55% in publicly traded equity securities, 43% in fixed debt instruments and 2% in cash equivalents.

At December 31, 2004 and 2003, Detroit Edison had external decommissioning trust funds of $546 million and $474 million, respectively, for the future decommissioning of Fermi 2. At December 31, 2004 and 2003, Detroit Edison had an additional $18 million and $22 million in trust funds for the decommissioning of Fermi 1. At December 31, 2004 and 2003, Detroit Edison also had an external decommissioning trust fund for low-level radioactive waste disposal costs of $26 million and $22 million, respectively. It is estimated that the cost of decommissioning Fermi 2, when its license expires in 2025, will be $1.0 billion in 2004 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 2009.

As a result of adopting SFAS No. 143, Detroit Edison recorded a retirement obligation liability for the decommissioning of Fermi 1 and 2 and reversed previously recognized decommissioning liabilities. At December 31, 2004, we have recorded a liability for the removal of the non-nuclear portion of the plants of $77 million.

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. 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 Act.

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, 2004 was as follows:




			Ludington
			Hydroelectric
	Belle River		Pumped Storage
In-service date		1984-1985		1973
Total plant capacity	1,026 MW		1,872MW
Ownership interest		*		49	%
Investment (in Millions)	$	1,581	$	166
Accumulated depreciation (in Millions)	$	740	$	88

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)	2004			2003			2002
Effective federal income tax rate		29.9	%		36.5	%		33.3	%


Income tax expense at 35% statutory rate	$	75		$	139		$	187

Investment tax credits		(7	)		(7	)		(7	)
Depreciation		3			3			3
Employee Stock Ownership Plan dividends		(4	)		(4	)		(3	)
Other, net		(3	)		14			(2	)

Total	$	64		$	145		$	178

Components of income tax expense were as follows:




	2004			2003		2002
(in Millions)
Current federal and other income tax expense	$	(78	)	$	109	$	236
Deferred federal and other tax expense (benefit)		142			36		(58	)


Total	$	64		$	145	$	178

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:




	2004			2003
(in Millions)
Property	$	(1,147	)	$	(989	)
Securitized regulatory assets		(778	)		(827	)
Pension and benefits		26			43
Other, net		(17	)		(2	)

	$	(1,916	)	$	(1,775	)


Deferred income tax liabilities	$	(2,326	)	$	(2,117	)
Deferred income tax assets		410			342

	$	(1,916	)	$	(1,775	)

The Internal Revenue Service is currently conducting audits of Detroit Edison as a component of the DTE Energy federal income tax returns for the years 1998 through 2001. 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, 2004, the Company had accrued approximately $10 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, 2004 was:




	2004			2003
(in Millions)
Detroit Edison Taxable Debt, Principally Secured
6.1% due 2005 to 2032	$	1,672		$	1,485

Detroit Edison Tax Exempt Revenue Bonds
5.6% due 2008 to 2032		1,145			1,175
Quarterly Income Debt Securities (QUIDS)
7.5% due 2026 to 2028		385			385
Other Long-Term Debt		74			81

		3,276			3,126
Less amount due within one year		(397	)		(50	)

	$	2,879		$	3,076


Securitization Bonds	$	1,496		$	1,585
Less amount due within one year		(96	)		(89	)

	$	1,400		$	1,496

We issued and optionally redeemed long-term debt consisting of the following:

2005

• Issued $400 million of senior notes in two series, $200 million of 4.8% series due 2015 and $200 million of 5.45% series due 2035. The proceeds were used to redeem the $385 million of 7.5% Quarterly Income Debt Securities due 2026 to 2028.

• Redeemed $76 million of 7.5% senior notes and $100 million of 7.0% remarketed secured notes, which matured February 2005.

2004

• Issued $36 million of 4-7/8% tax-exempt bonds due 2029, the proceeds of which were used to redeem $36 million of 6.55% tax-exempt bonds due 2024.

• Issued $32 million of 4.65% tax-exempt bonds due in 2028, the proceeds of which were used to redeem the following tax-exempt issues: $11.5 million of 6.05% bonds due 2023, $7.5 million of 5.875% bonds due 2024, and $13 million of 6.45% bonds due 2024.

• Issued $200 million of 5.40% senior notes due in 2014. The proceeds were used to repay short-term borrowings and for general corporate purposes.

2003

• Issued $49 million of 5.5% tax exempt bonds maturing in 2030.

• Redeemed $314 million of taxable debt with an average interest rate of 7.4% and maturities from 2003-2023.

• Redeemed $34 million of 6.875% tax-exempt bonds maturing in 2022.

In the years 2005- 2009, our long-term debt maturities are $493 million, $126 million, $135 million, $178 million and $158 million, respectively.

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 utility 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 will create cross defaults in the indebtedness of DTE Energy.

Preferred and Preference Securities – Authorized and Unissued

At December 31, 2004, 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 2004, Detroit Edison entered into a $206.25 million, five-year unsecured revolving credit facility and lowered its existing three-year facility from $137.5 million to $68.75 million. The five-year facility replaces the October 2003 364-day facility, which expired. The three-year revolving credit facility expires in October 2006. The five- and three-year credit facilities are with a syndicate of banks

and may be utilized for general corporate borrowings, but primarily are intended to provide liquidity support for Detroit Edison’s commercial paper program. Borrowings under the facilities will be available at prevailing short-term interest rates. The agreements require Detroit Edison to maintain a debt to total capitalization ratio of no more than .65 to l and “earnings before interest, taxes, depreciation and amortization” (EBITDA) to interest ratio of no less than 2 to 1. Detroit Edison is currently in compliance with these financial covenants.

As of December 31, 2004, we had no outstanding commercial paper.

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, 2004.

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 2022.

Future minimum lease payments under non-cancelable leases at December 31, 2004 were:




	Capital			Operating
	Leases			Leases
(in Millions)
2005	$	11		$	32
2006		13			31
2007		10			26
2008		11			25
2009		11			23
Thereafter		38			155

Total minimum lease payments		94		$	292

Less imputed interest		(21	)

Present value of net minimum lease payments		73

Less imputed interest		(7	)

Non-current portion	$	66

Total minimum lease payments for operating leases have not been reduced by future minimum sublease rentals totaling $3 million under non-cancelable subleases expiring at various dates to 2020.

Rental expense for operating leases was $37 million in 2004, $30 million in 2003 and $26 million in 2002.

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:

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

• The 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, 2004. 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 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.

2004

2003

Fair Value

Carrying Value

Fair Value

Carrying Value

Long-Term Debt

$5.1 billion

$4.8 billion

$5.1 billion

$4.7 billion

NOTE 13 — COMMITMENTS AND CONTINGENCIES

Environmental

Air - The EPA issued ozone transport and acid rain regulations and, in December 2003, proposed additional emission regulations relating to ozone, fine particulate and mercury air pollution. The new rules have led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, carbon dioxide and particulate emissions. To comply with these new controls, Detroit Edison has spent approximately $580 million through December 2004, and estimates that it will spend up to $100 million in 2005 and incur from $700 million to $1.3 billion of additional future capital expenditures over the next five to eight years 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, in excess of current depreciation levels, could be deferred in ratemaking, until after the expiration of the rate cap period, presently expected to end on December 31, 2005 upon MPSC authorization. Under PA 141 and the MPSC’s November 2004 final rate order, we believe that prudently incurred capital expenditures, in excess of current depreciation levels, are recoverable in rates.

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 five to seven years in additional capital expenditures for Detroit Edison.

Contaminated Sites - Detroit Edison conducted remedial investigations at contaminated sites, including two former manufactured gas plant sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the cost to remediate these sites is approximately $8 million, which is expected to be incurred over the next several years. As a result of the investigation, Detroit Edison accrued an $8 million liability during 2004.

Personal Property Taxes

Prior to 1999, Detroit Edison and other Michigan utilities 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 its 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. Detroit Edison has filed motions and the MTT agreed to place the cases in abeyance pending the conclusion of settlement negotiations being conducted by State of Michigan Treasury officials. On February 14, 2005, MTT issued a scheduling order that lifts the prior abeyances in a significant number of Detroit Edison appeals. The scheduling order sets litigation calendars for these cases extending into mid-2006.

Detroit Edison continues to record property tax expense based on the new tables. Detroit Edison will continue through settlement or litigation to seek to apply the new tables retroactively and to ultimately resolve the pending tax appeals related to 1997 through 1999. This is a solution supported by the STC in the past. To the extent that settlements cannot be achieved with the jurisdictions, litigation regarding the valuation of utility property will delay any recoveries by Detroit Edison.

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 and purchased power expense with non-cash accretion expense being recorded through 2008. We purchased $42 million of steam and electricity in 2004, $39 million in 2003 and $37 million in 2002. We estimate steam and electric purchase commitments through 2024 will not exceed $472 million. As discussed in Note 3 – Dispositions, in January 2003, we sold our steam heating business 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.

At December 31, 2004, we have entered into 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 $1.4 billion through 2018. We also estimate that 2005 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 and retail industries. Several customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We have negotiated or are currently involved in negotiations with each of the companies, or their successor companies, that have filed for bankruptcy protection. We regularly review contingent matters relating to purchase and sale contracts and record provisions for amounts considered probable of 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 in the period they are resolved.

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 Note 4 and Note 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, 2004 are based on a measurement date of November 30, 2004. Amounts reported in tables for the year ended December 31, 2004 and for balances as of December 31, 2003 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

Detroit Edison has 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. Detroit Edison operates as the sponsor of the plan, which is treated as a plan covering employees of various affiliates of DTE Energy Company. The annual expense disclosed below is Detroit Edison’s 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 (ERISA) and additional amounts we deem appropriate. We do not anticipate making a contribution to our qualified pension plan in 2005.

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
	2004			2003			2002			2004		2003		2002
(in Millions)
Service Cost	$	47		$	40		$	35		$	1	$	1	$	1
Interest Cost		130			127			124			2		2		2
Expected Return on Plan Assets		(135	)		(129	)		(133	)		—		—		—
Amortization of
Net loss		49			32			2			1		1		1
Prior service cost		9			9			9			—		—		—
Net transition asset		—			—			(1	)		—		—		—

Net Pension Cost	$	100		$	79		$	36		$	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, $247 million and $219 million at December 31, 2004 and 2003, respectively.




	Qualified Pension Plans				Nonqualified Pension Plans
	2004		2003		2004		2003
(In Millions)	November 30		December 31		November 30		December 31
Measurement Date
Accumulated Benefit Obligation-End of Period	$	2,447	$	2,316	$	34	$	34


Projected Benefit Obligation-Beginning of Period	$	2,498	$	2,287	$	36	$	31




	Qualified Pension Plans						Nonqualified Pension Plans
	2004			2003			2004			2003
(In Millions)	November 30			December 31			November 30			December 31
Service Cost		53			44			1			1
Interest Cost		153			150			2			2
Actuarial Loss (Gain)		69			166			(1	)		4
Benefits Paid		(136	)		(145	)		(2	)		(2	)
Plan Amendments		6			(4	)		—			—

Projected Benefit Obligation-End of Period	$	2,643		$	2,498		$	36		$	36


Plan Assets at Fair Value-Beginning of Period	$	2,029		$	1,572		$	—		$	-
Actual Return on Plan Assets		172			380			—			-
Company Contributions		170			222			2			2
Benefits Paid		(136	)		(145	)		(2	)		(2	)

Plan Assets at Fair Value-End of Period	$	2,235		$	2,029		$	—		$	-


Funded Status of the Plans	$	(408	)	$	(469	)	$	(36	)	$	(36	)
Unrecognized
Net loss		790			753			11			13
Prior service cost		41			41			2			3
Net transition assets		(1	)		—			—			—

Net Amount Recognized-End of Period	$	422		$	325		$	(23	)	$	(20	)


Amount Recorded as
Accrued pension liability	$	(212	)	$	(288	)	$	(35	)	$	(33	)
Regulatory asset		594			572			10			11
Intangible asset		40			41			2			2

	$	422		$	325		$	(23	)	$	(20	)

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




	2004			2003			2002
Projected Benefit Obligation
Discount rate		6.00	%		6.25	%		6.75	%
Annual increase in future compensation levels		4.0	%		4.0	%		4.0	%

Net Pension Costs
Discount rate		6.25	%		6.75	%		7.25	%
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	%		9.5	%

At December 31, 2004, 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)
2005	$	156
2006		160
2007		165
2008		170
2009		175
2010 - 2014		981

Total	$	1,807

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:



	2004			2003
Equity Securities		69	%		67	%
Debt Securities		26			27
Other		5			6

		100	%		100	%

Our plans’ weighted-average asset target allocations by asset category at December 31, 2004 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 $22 million in 2004, $21 million in 2003 and $20 million in 2002.

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.

Net postretirement cost includes the following components:




	2004			2003			2002
(in Millions)
Service Cost	$	33		$	31		$	25
Interest Cost		69			66			59
Expected Return on Plan Assets		(45	)		(36	)		(44	)
Amortization of
Net loss		33			23			2
Net transition obligation		8			13			19

Net Postretirement Cost	$	98		$	97		$	61

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:




	2004			2003
(in Millions)	November 30			December 31
Measurement Date
Accumulated Postretirement Benefit Obligation-Beginning of Period	$	1,192		$	1,131
Service Cost		33			31
Interest Cost		69			66
Actuarial Loss		106			122
Plan Amendments		21			(106	)
Benefits Paid		(60	)		(52	)


Accumulated Postretirement Benefit Obligation-End of Period	$	1,361		$	1,192

Plan Assets at Fair Value-Beginning of Period	$	468		$	425
Actual Return on Plan Assets		43			91
Company Contributions		40			—
Benefits Paid		—			(48	)

Plan Assets at Fair Value-End of Period	$	551		$	468


Funded Status of the Plans	$	(810	)	$	(724	)
Unrecognized




	2004			2003
(in Millions)	November 30			December 31
Net loss		594			518
Prior service cost		30			1
Net transition obligation		58			74

Accrued Postretirement Liability at Measurement Date		(128	)		(131	)
Company Contribution And Benefit Payments in December 2004		(14	)		—

Accrued Postretirement Liability-End of Period	$	(142	)	$	(131	)

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




	2004			2003			2002
Projected Benefit Obligation
Discount rate		6.00	%		6.25	%		6.75	%

Net Benefit Costs
Discount rate		6.25	%		6.75	%		7.25	%
Expected long-term rate of return on Plan assets		9.0	%		9.0	%		9.5	%

Benefit costs were calculated assuming health care cost trend rates beginning at 9.0% for 2005 and decreasing to 5.0% in 2010 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 $15 million and increased the accumulated benefit obligation by $128 million at December 31, 2004. 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 $13 million and would have decreased the accumulated benefit obligation by $114 million at December 31, 2004.

Effective 2005, we amended our postretirement health care plan to provide for some enhancements. The changes increased our expected 2005 postretirement cost by $6 million.

At December 31, 2004, 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)
2005	$	74
2006		81
2007		84
2008		87
2009		92
2010 - 2014		504

Total	$	922

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:



	2004			2003
Equity Securities		68	%		65	%
Debt Securities		28			30
Other		4			5

		100	%		100	%

Our plans’ weighted-average asset target allocations by asset category at December 31, 2004 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 $12 million in 2004. The impact of the Medicare Act on the components of other postretirement benefit costs for the year ended December 31 was as follows:




(in Millions)	2004
Reduction in service cost	$	2
Reduction in interest cost		4
Amortization of actuarial gain		6

Decrease in postretirement benefit cost	$	12

At December 31, 2004, 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)
2005	$	—
2006		9
2007		9
2008		10
2009		10
2010 - 2014		53

Total	$	91

NOTE 15 – RELATED PARTY TRANSACTIONS

We have transactions with affiliated companies to sell energy for resale, provide fuel supply services and power plant operation and maintenance services for the delivery of electric energy. Under a service agreement with DTE Energy, various DTE Energy affiliates, including Detroit Edison provide corporate support functions consisting of financial, auditing, tax, legal, treasury, cash management, human resources, information technology, regulatory and other services, which are billed to DTE Energy corporate. As these functions essentially support the entire DTE Energy Company, their costs are fully allocated to the various DTE Energy affiliates based on services utilized. The net of these billings included in the consolidated statement of operations was income of $19 million in 2004 and $18 million in 2003, and expenses of $7 million in 2002.

In addition, we had intercompany revenue, primarily from the sale of energy to affiliates, of $255 million, $71 million and $108 million in 2004, 2003 and 2002, respectively. We had intercompany expenses, primarily for purchased power, of $66 million, $45 million and $100 million in 2004, 2003 and 2002, respectively.

Our accounts receivable from affiliated companies totaled $29 million and $34 million at December 31, 2004 and 2003, respectively. Our accounts payable to affiliated companies totaled $56 million and $67 million at December 31, 2004 and 2003, respectively.

We had a short-term note receivable from DTE Energy of $85 million and $7 million at December 31, 2004 and 2003, respectively. This note is subject to a credit agreement with DTE Energy whereby 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 market-based rates.

We declared dividends to DTE Energy of $305 million in 2004, $295 million in 2003 and $296 million in 2002. We paid dividends to DTE Energy of $303 million in 2004 and $295 million in 2003 and 2002. We received a $470 million capital contribution from DTE Energy in 2003. We issued 4,344,492 shares of our common stock to DTE Energy and in return DTE Energy contributed 4,344,492 shares of its common stock, valued at $170 million, to our defined benefit retirement plan.

NOTE 16 — SEGMENT AND RELATED INFORMATION

We operate our business through two strategic business units (Energy Resources – Power Generation and Energy Distribution – Power Distribution). Based on this structure we set strategic goals, allocate resources and evaluate performance.

Energy Resources includes the power generation services of Detroit Edison. Electricity is generated from our numerous fossil plants, our hydroelectric pumped storage plant and our nuclear plant and sold throughout Southeastern Michigan to residential, commercial, industrial and wholesale customers.

Energy Distribution includes the power distribution services of Detroit Edison. Energy Distribution distributes electricity generated by Energy Resources and alternative energy suppliers to Detroit Edison’s 2.1 million residential, commercial and industrial customers.

Financial data of the business segments follows:



(in Millions)
			Depreciation		Interest									Capital
	Operating Revenue		And Amortization		Expense		Income Taxes		Net Income			Total Assets		Expenditures

2004
Energy Resources	$	2,210	$	272	$	167	$	23	$	62		$	8,288	$	332
Energy Distribution		1,358		251		113		41		88			4,554		370

Total	$	3,568	$	523	$	280	$	64	$	150		$	12,842	$	702



2003
Energy Resources	$	2,448	$	224	$	157	$	135	$	235		$	7,216	$	340
Energy Distribution		1,247		249		127		10		17			5,333		240
Cumulative Effect of Accounting Change		—		—		—		—		(6	)		—		—

Total	$	3,695	$	473	$	284	$	145	$	246		$	12,549	$	580



2002
Energy Resources	$	2,711	$	331	$	184	$	120	$	245		$	7,334	$	395
Energy Distribution		1,343		246		127		58		111			4,154		290

Total	$	4,054	$	577	$	311	$	178	$	356		$	11,488	$	685

NOTE 17 — SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)




	First			Second		Third		Fourth
(in Millions)	Quarter			Quarter		Quarter		Quarter		Year
2004
Operating Revenues	$	886		$	835	$	958	$	889	$	3,568
Operating Income	$	145	(1)	$	92	$	169	$	111	$	517
Net Income	$	44	(1)	$	8	$	62	$	36	$	150

2003
Operating Revenues	$	937		$	870	$	1,017	$	871	$	3,695
Operating Income	$	116		$	112	$	219	$	227	$	674
Net Income	$	15		$	30	$	96	$	105	$	246

(1)	Previously reported first quarter 2004 amounts have been adjusted to reflect the retroactive adoption of FSP No. 106-2, relating to the impact of the Medicare Act on postretirement benefit costs (Note 2).

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 Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2004, 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 effectively designed to ensure 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.

(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 2004 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, 2004 and 2003, 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, 2004 and December 31, 2003, and fees billed for other services rendered by Deloitte during those periods.


	2004		2003
Audit fees (1)	$	1,571,645	$	952,527
Audit related fees (2)		59,750		33,422
Tax fees		—		—
All other fees		—		—

Total	$	1,631,395	$	985,949

(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.

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 least quarterly.

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.

Exhibit Index


Exhibit No.		Description

(i) Exhibits filed herewith.

12-21		Computation of Ratio of Earnings to Fixed Charges.

18-1		Letter Regarding Change in Accounting Principles.

23-17		Consent of Deloitte & Touche LLP.

31-13		Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report.

31-14		Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report.

99-17		Amendment dated as of January 20, 2005, to the Trade Receivables Purchase and Sale Agreement, dated as of February 28, 1989, as Amended and Restated 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 February 25, 2004, as so amended and restated, among The Detroit Edison Company, Citibank, N.A. and Citicorp North America, Inc.

99-18		Amendment No. 4, dated as of January 20, 2005, to the Trade Receivables Purchase and Sale Agreement, dated as of February 28, 1989, as Amended and Restated as of October 1, 1991, as Amended and Restated 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.

99-19		Sixth Amendment, dated as of September 1, 1998, to Master Trust Agreement (“Master Trust”), dated as of June 30, 1994, between The Detroit Edison Company and Fidelity Management Trust Company.

99-20		Seventh Amendment, dated as of December 15, 1999, to Master Trust.

99-21		Eighth Amendment, dated as of February 1, 2000, to Master Trust.

99-22		Ninth Amendment, dated as of April 1, 2000, to Master Trust.

99-23		Tenth Amendment, dated as of May 1, 2000, to Master Trust.

99-24		Eleventh Amendment, dated as of July 1, 2000, to Master Trust.

99-25		Twelfth Amendment, dated as of August 1, 2000, to Master Trust.

99-26		Thirteenth Amendment, dated as of December 21, 2001, to Master Trust.

99-27		Fourteenth Amendment, dated as of March 1, 2002, to Master Trust.

99-28		Fifteenth Amendment, dated as of January 1, 2002, to Master Trust.

(ii) Exhibits incorporated herein by reference.

3(a)		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)

3(b)		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)

4(a)		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:


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, 1995		Exhibit 4-221 to Form 10-K for year ended December 31, 2000. (1995 Series AP and 1995 Series BP)

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)

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 51/2% 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, with 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, 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)		Trust Agreement of Detroit Edison Trust I. (Exhibit 4-9 to Registration Statement No. 333-100000)

4(r)		Trust Agreement of Detroit Edison Trust II. (Exhibit 4-10 to Registration Statement


		No. 333-100000)

4(s)		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, as seller, 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, as seller, 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, as seller, 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, as seller, 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, as so amended and restated, 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 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, 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 99-16 to Form 10-Q for quarter ended March 31, 2004)

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

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


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

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

(iii) Exhibits furnished herewith.

32-13		Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report.

32-14		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 15, 2005	By	/s/ DANIEL G. BRUDZYNSKI

		Daniel G. Brudzynski
		Chief Accounting Officer,
		Vice President and Controller

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/ DANIEL G. BRUDZYNSKI

	Anthony F. Earley, Jr.		Daniel G. Brudzynski
	Chairman of the Board,		Chief Accounting Officer,
	President, Chief Executive		Vice President and Controller
	and Chief Operating Officer

By		By	/s/ DAVID E. MEADOR

	Susan M. Beale		David E. Meador
	Director, Vice President and		Director, Executive Vice President
	Corporate Secretary		and Chief Financial Officer

Date: March 15, 2005

Exhibit Index


Exhibit
No.		Description

(i) Exhibits filed herewith.

12-21		Computation of Ratio of Earnings to Fixed Charges.

18-1		Letter Regarding Change in Accounting Principles.

23-17		Consent of Deloitte & Touche LLP.

31-13		Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report.

31-14		Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report.

99-17		Amendment dated as of January 20, 2005, to the Trade Receivables Purchase and Sale Agreement, dated as of February 28, 1989, as Amended and Restated 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 February 25, 2004, as so amended and restated, among The Detroit Edison Company, Citibank, N.A. and Citicorp North America, Inc.

99-18		Amendment No. 4, dated as of January 20, 2005, to the Trade Receivables Purchase and Sale Agreement, dated as of February 28, 1989, as Amended and Restated as of October 1, 1991, as Amended and Restated 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.

99-19		Sixth Amendment, dated as of September 1, 1998, to Master Trust Agreement (“Master Trust”), dated as of June 30, 1994, between The Detroit Edison Company and Fidelity Management Trust Company.

99-20		Seventh Amendment, dated as of December 15, 1999, to Master Trust.

99-21		Eighth Amendment, dated as of February 1, 2000, to Master Trust.

99-22		Ninth Amendment, dated as of April 1, 2000, to Master Trust.

99-23		Tenth Amendment, dated as of May 1, 2000, to Master Trust.

99-24		Eleventh Amendment, dated as of July 1, 2000, to Master Trust.

99-25		Twelfth Amendment, dated as of August 1, 2000, to Master Trust.

99-26		Thirteenth Amendment, dated as of December 21, 2001, to Master Trust.

99-27		Fourteenth Amendment, dated as of March 1, 2002, to Master Trust.

99-28		Fifteenth Amendment, dated as of January 1, 2002, to Master Trust.


			Page
Definitions				1

Forward-Looking Statements				2

Part I
	Items 1. & 2.	Business & Properties		3

	Item 3.	Legal Proceedings		12

	Item 4.	Submission of Matters to a Vote of Security Holders		12

Part II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		12

	Item 6.	Selected Financial Data		12

	Item 7.	Management’s Narrative Analysis of Results of Operations		13

	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		17

	Item 8.	Financial Statements and Supplementary Data		19

	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		57

	Item 9A.	Controls and Procedures		57

	Item 9B.	Other Information		57

Part III
	Item 10.	Directors and Executive Officers of the Registrant		58

	Item 11.	Executive Compensation		58

	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		58

	Item 13.	Certain Relationships and Related Transactions		58

	Item 14	Principal Accountant Fees and Services		58

Part IV
	Item 15.	Exhibits and Financial Statement Schedules		58

Signatures				65
Computation of Ratio of Earnings to Fixed Charges
Letter Regarding Change in Accouting Principles
Consent of Deloitte & Touche LLP
Chief Executive Officer Section 302 Form 10-K Certification
Chief Financial Officer Section 302 Form 10-K Certification
Chief Executive Officer Section 906 Form 10-K Certification
Chief Financial Officer Section 906 Form 10-K Certification
Amendment to Trade Receivables Purchase & Sale Agreement
Amendment No. 4 to Trade Receivables Purchase & Sale Agreement
Sixth Amendment to Trust Agreement
Seventh Amendment to Trust Agreement
Eighth Amendment to Trust Agreement
Ninth Amendment to Trust Agreement
Tenth Amendment to Trust Agreement
Eleventh Amendment to Trust Agreement
Twelfth Amendment to Trust Agreement
Thirteenth Amendment to Trust Agreement
Fourteenth Amendment to Trust Agreement
Fifteenth Amendment to Trust Agreement

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

•	economic climate and 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 borrowings;

•	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; 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.


			Page
Report of Independent Registered Public Accounting Firm			20

Consolidated Statement of Operations			21

Consolidated Statement of Financial Position			22

Consolidated Statement of Cash Flows			24

Consolidated Statement of Changes in Shareholder’s Equity and Comprehensive Income			25

Notes to Consolidated Financial Statements			26

Schedule II – Valuation and Qualifying Accounts			64

•	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.

•	Recoverable minimum pension liability — An additional minimum pension liability was recorded under generally accepted accounting principles (Note 14) 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.

•	Asset retirement obligation — Asset retirement obligations were recorded pursuant to adoption of SFAS No. 143 in 2003. 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.

•	Transmission integration costs —The MPSC’s November 2004 final rate order denied recovery and determined these costs to be transaction expenses in DTE Energy’s sale of ITC.

•	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 141 permits, after MPSC authorization, the recovery of enhanced homeland 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.

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

•	Excess securitization savings — Savings associated with the 2001 securitization of Fermi 2 and other costs are refundable to Detroit Edison’s customers.

•	Customer refund – 1997 storm — The over collection of 1997 storm costs, which will be refunded in accordance with the MPSC’s November 2004 rate order.

•	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.

	(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.


	Year Ending December 31,
(in Millions)	2004			2003			2002
Allowance for Doubtful Accounts (shown as Deduction from accounts receivable in the consolidated statement of financial position)
Balance at Beginning of Period	$	51		$	48		$	27
Additions:
Charged to costs and expenses		45			39			24
Charged to other accounts (1)		5			3			9
Deductions (2)		(46	)		(39	)		(12	)

Balance At End of Period	$	55		$	51		$	48

(1)		Collection of accounts previously written off.

(2)		Non-collectible accounts written off.