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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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


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


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

For the fiscal year ended December 31, 2005

Commission file number 1-11607

DTE ENERGY COMPANY

(Exact name of registrant as specified in its charter)


Michigan (State or other jurisdiction of incorporation or organization) 2000 2^nd Avenue, Detroit, Michigan (Address of principal executive offices)		38-3217752 (I.R.S. Employer Identification No.) 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

Common Stock, without par value, with contingent preferred stock purchase rights 7.8% Trust Preferred Securities * 7.50% Trust Originated Preferred Securities**		New York and Chicago Stock Exchanges New York Stock Exchange New York Stock Exchange


*		Issued by DTE Energy Trust I. DTE Energy fully and unconditionally guarantees the payments of all amounts due on these securities to the extent DTE Energy Trust I has funds available for payment of such distributions.

**		Issued by DTE Energy Trust II. DTE Energy fully and unconditionally guarantees the payments of all amounts due on these securities to the extent DTE Energy Trust II has funds available for payment of such distributions.

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

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

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

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

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

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

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

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

On June 30, 2005, the aggregate market value of the Registrant’s voting and non-voting common equity held by non-affiliates was approximately $8.1 billion (based on the New York Stock Exchange closing price on such date). There were 177,812,509 shares of common stock outstanding at January 31, 2006.

Certain information in DTE Energy Company’s definitive Proxy Statement for its 2006 Annual Meeting of Common Shareholders to be held April 27, 2006, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, not later than 120 days after the end of the Registrant’s fiscal year covered by this report on Form 10-K, is incorporated herein by reference to Part III (Items 10, 11, 12, 13 and 14) of this Form 10-K.

definitions


Coke and Coke Battery		Raw coal is heated to high temperatures in ovens to separate impurities, leaving a carbon residue called coke. Coke is combined with iron ore to create a high metallic iron that is used to produce steel. A series of coke ovens configured in a module is referred to as a battery.

Company		DTE Energy Company and any subsidiary companies

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

Detroit Edison		The Detroit Edison Company (a direct wholly owned subsidiary of DTE Energy Company) and subsidiary companies

DTE Energy		DTE Energy Company, directly or indirectly the parent of Detroit Edison, MichCon and numerous non-utility subsidiaries

EPA		United States Environmental Protection Agency

FERC		Federal Energy Regulatory Commission

GCR		A gas cost recovery mechanism authorized by the MPSC, permitting MichCon to pass the cost of natural gas to its customers.

ITC		International Transmission Company (until February 28, 2003, a wholly owned subsidiary of DTE Energy Company)

MichCon		Michigan Consolidated Gas Company (an indirect wholly owned subsidiary of DTE Energy) and subsidiary companies

MDEQ		Michigan Department of Environmental Quality

MPSC		Michigan Public Service Commission

Non-utility		An entity that is not a public utility. Its conditions of service, prices of goods and services and other operating related matters are not directly regulated by the MPSC or the FERC.

NRC		Nuclear Regulatory Commission

PSCR		A power supply cost recovery mechanism authorized by the MPSC that allows Detroit Edison to recover through rates its fuel, fuel-related and purchased power expenses. The power supply cost recovery mechanism was suspended under Michigan’s restructuring legislation (signed into law June 5, 2000), which lowered and froze electric customer rates and was reinstated by the MPSC effective January 1, 2004.

Production tax credits		Tax credits as authorized under Section 29 (redesignated by the Energy Tax Incentives Act of 2005 as Section 45K for tax years after 2005) and Section 45 of the Internal Revenue Code that are designed to stimulate investment in and development of alternate fuel sources. The amount of a production tax credit can vary each year as determined by the Internal Revenue Service.

Proved Reserves		Estimated quantities of natural gas, natural gas liquids and crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reserves under existing economic and operating conditions.

Securitization		Detroit Edison financed specific stranded costs at lower interest rates through the sale of rate reduction bonds by a wholly-owned special purpose entity, the Detroit Edison Securitization Funding LLC.


SFAS		Statement of Financial Accounting Standards

Stranded Costs		Costs incurred by utilities in order to serve customers in a regulated environment that absent special regulatory approval would not otherwise be recoverable if customers switch to alternative energy suppliers.

Synfuels		The fuel produced through a process involving chemically modifying and binding particles of coal. Synfuels are used for power generation and coke production. Synfuel production generates production tax credits.

Unconventional Gas		Includes those oil and gas deposits that originated and are stored in coal bed, tight sandstone and shale formations.

Units of Measurement


Bcf		Billion cubic feet of gas

Bcfe		Conversion metric of natural gas, the ratio of 6 Mcf of gas to 1 barrel of oil.

kWh		Kilowatthour of electricity

Mcf		Thousand cubic feet of gas

MMcf		Million cubic feet of gas

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 presently contemplated, projected, estimated or budgeted. Many factors may impact forward-looking statements including, but not limited to, the following:

	•		the higher price of oil and its impact on the value of production tax credits, and the ability to utilize and/or sell interests in facilities producing such credits;

	•		the uncertainties of successful exploration of gas shale resources and inability to estimate gas reserves with certainty;

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

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

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

	•		nuclear regulations and operations associated with nuclear facilities;

	•		implementation of electric and gas Customer Choice programs;

	•		impact of electric and gas 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 which can be affected by credit agency ratings;

	•		the timing and extent of changes in interest rates;

	•		the level of borrowings;

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

	•		effects of competition;

	•		impact of regulation by the FERC, MPSC, NRC and other applicable governmental proceedings and regulations;

	•		contributions to earnings by non-utility subsidiaries;

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

	•		the ability to recover costs through rate increases;

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

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

	•		changes in accounting standards and financial reporting regulations;

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

	•		uncollectible accounts receivable;

	•		litigation and related appeals; and

	•		changes in the economic and financial viability of our suppliers, customers and trading counterparties, and the continued ability of such parties to perform their obligations to the Company.

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.

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

General

In 1995, DTE Energy incorporated in the State of Michigan. Our utility operations consist primarily of Detroit Edison and MichCon. We also have three non-utility segments that are engaged in a variety of energy related businesses such as synfuels, energy services, natural gas exploration and production, energy marketing and trading, coal transportation and gas storage and transportation. In August 2005, the Energy Policy Act of 2005 repealed the Public Utility Holding Company Act of 1935 (PUHCA), effective February 8, 2006. As a result of the repeal of PUHCA, DTE Energy no longer has to claim itself as an exempt holding company. A discussion of the Energy Policy Act of 2005 is in the Management’s Discussion and Analysis section of this Form 10-K.

Detroit Edison is a Michigan corporation organized in 1903 and is a public utility subject to regulation by the MPSC and the FERC. Detroit Edison is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.2 million customers in southeastern Michigan.

MichCon is a Michigan corporation organized in 1898 and is a public utility subject to regulation by the MPSC. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.3 million customers throughout Michigan.

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to such reports are available free of charge through the Investor Relations page of our website: www.dteenergy.com, as soon as reasonably practicable after they are filed with or furnished to the Securities and Exchange Commission (SEC). The information on our website is not, and shall not be deemed to be, a part of this Form 10-K or any other filing we make with the SEC. Our previously filed reports and statements are also available at the SEC’s website: www.sec.gov.

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

Corporate Structure

Through 2004, we operated our businesses through three strategic business units (Energy Resources, Energy Distribution and Energy Gas). Each business unit had utility and non-utility operations. The balance of our business consisted of Corporate & Other. See Note 16 for financial information by segment for the last three years. Beginning in the second quarter of 2005, we realigned our operations into the following business units to strengthen the Company’s focus on customer relationships and growth within our non-utility businesses. Based on this structure, we set strategic goals, allocate resources and evaluate performance.

Electric Utility

•

Consists of Detroit Edison, the company’s electric utility whose operations include the power generation and electric distribution facilities that service approximately 2.2 million residential, commercial, industrial and wholesale customers throughout southeastern Michigan.

Gas Utility

•

Consists of the gas distribution services provided by MichCon, a gas utility that purchases, stores and distributes natural gas throughout Michigan to approximately 1.3 million residential, commercial and industrial customers and Citizens Gas Fuel Company (Citizens), a gas utility that distributes natural gas in Adrian, Michigan.

Non-Utility Operations

•

Power and Industrial Projects, primarily consisting of synfuel projects, on-site energy services, steel-related energy projects, power generation with services, and waste coal recovery operations;

	•		Unconventional Gas Production, primarily consisting of natural gas exploration, development and production; and

	•		Fuel Transportation and Marketing, primarily consisting of energy marketing and trading operations, coal transportation and marketing, and gas pipelines, processing and storage.

Corporate & Other, primarily consisting of corporate support functions and certain energy related investments.

Refer to our Management’s Discussion and Analysis for an in-depth analysis of each segment’s financial results. A description of each business unit follows.

ELECTRIC UTILITY

Description

Our Electric Utility segment consists of Detroit Edison, an electric utility subject to regulation by the MPSC and FERC. Detroit Edison is engaged in the generation, purchase, distribution and sale of electric energy to approximately 2.2 million customers in a 7,600 square mile area in southeastern Michigan.

Our plants are regulated by numerous federal and state governmental agencies, including the MPSC, the FERC, the NRC, the EPA and the MDEQ. Electricity is generated from our numerous fossil plants, a hydroelectric pumped storage plant and a nuclear plant, and is purchased from electricity generators, suppliers and wholesalers. The electricity we produce and purchase is sold to four major classes of customers: residential, commercial, industrial and wholesale, principally throughout Michigan.

Revenue by Service


(in Millions)	2005		2004		2003

Residential	$	1,517	$	1,345	$	1,351

Commercial		1,331		1,123		1,308

Industrial		697		557		634

Wholesale		73		65		67

Other		464		234		201


Subtotal		4,082		3,324		3,561

Interconnection sales (1)		380		244		134


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


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

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

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

Fuel Supply and Purchased Power

Our power is generated from a variety of fuels and is supplemented with purchased power. We expect an adequate supply of fuel and purchased power to meet our obligation to serve customers. Our generating capability is heavily dependent upon the availability of coal. Coal is purchased from various sources in different geographic areas under agreements that vary in both pricing and terms. We expect to obtain the majority of our coal requirements through long-term contracts with the balance to be obtained through short-term agreements and spot purchases. We have several long-term and short-term contracts for a total purchase of approximately 26 million tons of low-sulfur western coal to be delivered from 2006 to 2008. We also have contracts with several suppliers for the purchase of approximately 7 million tons of Appalachian coal to be delivered from 2006 through 2008. These existing long-term coal contracts have fixed prices except for a single contract that has provisions for price escalation as well as de-escalation. We have approximately 90% of our 2006 expected coal requirements under contract. Given the geographic diversity of supply, we believe we can meet our expected generation requirements. We lease a fleet of rail cars and have long-term transportation contracts with companies to provide rail and vessel services for delivery of purchased coal to our generating facilities.

Detroit Edison participates in the energy market through the Midwest Independent System Operator, a Regional Transmission Organization. We offer our generation in the market on a day-ahead and real-time basis and bid for power in the market to serve our load. We are a net purchaser of power which supplements our generation capability to meet customer demand during peak cycles. For example, when high temperatures occur during the summer, we require additional electricity to meet demand. This access to additional power is an efficient and economical way to meet our obligation to customers without increasing capital expenditures to build additional base-load power plants.

Properties

Detroit Edison owns generating plants and facilities that are located in the State of Michigan. Substantially all of our property is subject to the lien of a mortgage. Generating plants owned and in service as of December 31, 2005 are as follows:


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

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

			11,113		100.0	%


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

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

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

(4)		The Monroe Power Plant provided 38% of Detroit Edison’s total 2005 power plant generation.

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

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

Detroit Edison owns and operates 670 distribution substations with a capacity of approximately 32,489,000 kilovolt-amperes (kVA) and approximately 421,000 line transformers with a capacity of approximately 25,345,000 kVA. Circuit miles of distribution lines owned and in service as of December 31, 2005 are as follows:


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

		30,598		14,409

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

Regulation

Detroit Edison’s business is subject to the regulatory jurisdiction of various agencies, including the MPSC, the FERC and the NRC. The MPSC issues orders pertaining to rates, recovery of certain costs, including the costs of generating facilities and regulatory assets, conditions of service, accounting and operating-related matters. Detroit Edison’s MPSC-approved rates charged to customers have historically been designed to allow for the recovery of costs, plus an authorized rate of return on our investments. The FERC regulates Detroit Edison with respect to financing authorization and wholesale electric activities.

The NRC has regulatory jurisdiction over all phases of the operation, construction, licensing and decommissioning of Detroit Edison’s nuclear plant operations. We are subject to the requirements of other regulatory agencies with respect to safety, the environment and health.

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

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

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

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

See Note 4.

Energy Assistance Programs

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

Strategy and Competition

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

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

Effective January 2002, the electric Customer Choice program expanded in Michigan so that all of the Company’s electric customers can choose to purchase their electricity from alternative electric suppliers of generation services. Detroit Edison lost 12% of retail sales in 2005, 18% in 2004 and 12% of such sales in 2003 as a result of customers choosing to purchase power from alternative electric suppliers. Customers participating in the electric Customer Choice program consist primarily of industrial and commercial customers whose MPSC-authorized full service rates exceed their cost of service. Customers who elect to purchase their electricity from alternative electric suppliers by participating in the electric Customer Choice program have an unfavorable effect on our financial performance. The effect of lost sales due to the electric Customer Choice program has reduced our need for purchased power and when market conditions are favorable we sell power into the wholesale market, in order to lower costs to full service customers.

Detroit Edison acquires transmission services from ITC, a wholly owned subsidiary of DTE Energy until February 2003. By FERC order, rates charged by ITC to Detroit Edison were frozen through December 2004. Thereafter, rates became subject to normal FERC regulation. With the MPSC’s November 2004 final rate order, transmission costs are recoverable through Detroit Edison’s PSCR mechanism.

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

GAS UTILITY

Description

Our Gas Utility segment consists of MichCon and Citizens, natural gas utilities subject to regulation by the MPSC. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.3 million residential, commercial and industrial customers in the State of Michigan. MichCon also has subsidiaries involved in the gathering and transmission of natural gas in northern Michigan. MichCon operates one of the largest natural gas distribution and transmission systems in the United States. Citizens distributes natural gas in Adrian, Michigan.

Revenue by Service


(in Millions)	2005		2004		2003

Gas Sales	$	1,860	$	1,435	$	1,242
End User Transportation		134		119		136
Intermediate Transportation		58		56		51
Other		86		72		69

Total Revenue	$	2,138	$	1,682	$	1,498

•		Gas Sales — Includes the sale and delivery of natural gas primarily to residential and small-volume commercial and industrial customers.

•		End User Transportation — Gas delivery service provided primarily to large-volume commercial and industrial customers. Additionally, the service is provided to residential customers, and small-volume commercial and industrial customers who have elected to participate in our Customer Choice program. End user transportation customers purchase natural gas directly from producers or brokers and utilize our pipeline network to transport the gas to their facilities or homes.

•		Intermediate Transportation — Gas delivery service provided to producers, brokers and other gas companies that own the natural gas, but are not the ultimate consumers. Intermediate transportation customers utilize our gathering and high-pressure transmission system to transport the gas to storage fields, processing plants, pipeline interconnections or other locations.

•		Other — Includes revenues from providing appliance maintenance, facility development, gas storage and other energy-related services.

Our gas sales, end user transportation and intermediate transportation volumes, revenues and net income are impacted by weather. Given the seasonal nature of our business, revenues and net income are concentrated in the first and fourth quarters of the calendar year. By the end of the first quarter, the heating season is largely over, and we typically realize substantially reduced revenues and earnings in the second quarter and losses in the third quarter.

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

Natural Gas Supply

Our gas distribution system has a planned maximum daily send-out capacity of 2.8 Bcf, with approximately 67% of the volume coming from underground storage for 2005. Peak-use requirements are met through utilization of our storage facilities, pipeline transportation capacity, and purchased storage services. Because of our geographic diversity of supply and our pipeline transportation and storage capacity, we are able to reliably meet our supply requirements. We believe natural gas supply and pipeline capacity will be sufficiently available to meet market demands in the foreseeable future.

We purchase natural gas supplies in the open market by contracting with producers and marketers, and we maintain a diversified portfolio of natural gas supply contracts. Supplier, producing region, quantity, and available transportation diversify our natural gas supply base. We obtain our natural gas supply from various sources in different geographic areas (Gulf Coast, Mid-Continent, Canada and Michigan) under agreements that vary in both pricing and terms. Gas supply pricing is generally tied to published price indices to approximate current market prices.

Properties

We own distribution, transmission and storage properties that are located in the State of Michigan. Our distribution system includes approximately 18,000 miles of distribution mains, approximately 1,179,000 service lines and approximately 1,320,000 active meters. We own approximately 2,600 miles of transmission lines that deliver natural gas to the distribution districts and interconnect our storage fields with the sources of supply and the market areas.

We own properties relating to four underground natural gas storage fields with an aggregate working gas storage capacity of approximately 124 Bcf. These facilities are important in providing reliable and cost-effective service to our customers. Most of the company’s distribution and transmission property are located on property owned by others and used by the company through easements, permits or licenses. Substantially all of our property is subject to the lien of a mortgage.

We are directly connected to interstate pipelines, providing access to most of the major natural gas producing regions in the Gulf Coast, Mid-Continent and Canadian regions. The company’s primary long-term transportation contracts are as follows:


	Availability (MMcf/d)		Contract expiration
Panhandle Eastern Pipeline Company		75		2009
Trunkline Gas Company		10		2009
Viking Gas Transmission Company		50		2010
TransCanada PipeLines Limited		50		2010
Great Lakes Gas Transmission L.P		30		2011
ANR Pipeline Company		245		2011
Vector Pipeline L.P		50		2012

We own 840 miles of transportation and gathering pipelines in the northern lower peninsula of Michigan. We lease a portion of our pipeline system to the Vector Pipeline Partnership (an affiliate) through a capital lease arrangement. See Note 11. We also own a 2,400 horsepower compressor station located in northern Michigan.

Regulation

We are subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to rates, recovery of certain costs, including the costs of regulatory assets, conditions of service, accounting and other operating-related matters. We are subject to the requirements of other regulatory agencies with respect to safety, the environment and health.

In the late 1990s, the MPSC began an initiative designed to give all of Michigan’s natural gas customers added choices and the opportunity to benefit from lower gas costs resulting from competition. In 1999, the MPSC approved a comprehensive experimental three-year gas Customer Choice program that allowed an increasing number of customers to purchase natural gas from suppliers other than their local utility. In December 2001, the MPSC issued an order that continued the gas Customer Choice program on a permanent and expanding basis. The permanent gas Customer Choice program was phased in over a three-year period, with all customers having the option to choose their gas supplier by April 2004. Since MichCon continues to transport and deliver the gas to the participating customer premises at prices comparable to margins earned on gas sales, customers switching to other suppliers have little impact on MichCon’s earnings.

In April 2005, the MPSC issued a final rate order which increased MichCon’s base rates by $61 million annually effective April 29, 2005. See Note 4.

Energy Assistance Program

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

Strategy and Competition

Our strategy is to expand our role as the preferred provider of natural gas in Michigan. As a result of more efficient furnaces and appliances, and customer conservation due to high natural gas prices, we expect future sales volumes to remain at current levels or slightly decline. We continue to provide energy-related services that capitalize on our expertise, capabilities and efficient systems. We anticipate revenue growth through increased rates authorized by the MPSC in April 2005. See Note 4. We continue to focus on lowering our operating costs by improving operating efficiencies.

Competition in the gas business primarily involves other natural gas providers, as well as providers of alternative fuels and energy sources. The primary focus of competition in the end user transportation market is cost and reliability. Some large commercial and industrial customers have the ability to switch to alternative fuel sources such as coal, electricity, oil and steam. If these customers were to choose an alternative fuel source, they would not have a need for our end-user transportation service. In addition, some of these customers could bypass our pipeline system and have their gas delivered directly from an interstate pipeline. We compete against alternative fuel sources by providing competitive pricing and reliable service, supported by our extensive storage capacity.

Our extensive transmission pipeline system has enabled us to develop a 600 to 700 Bcf annual market for intermediate transportation services for Michigan gas producers, marketers, distribution companies and other pipeline companies. We operate in a central geographic location with connections to major Mid-western interstate pipelines that extend throughout the Midwest, eastern United States and eastern Canadian markets.

NON-UTILITY OPERATIONS

Power and Industrial Projects

Description

Power and Industrial Projects is comprised of Coal-Based Fuels, On-Site Energy Projects, Non-Utility Power Generation, Landfill Gas Recovery, and Waste Coal Recovery.

Coal-Based Fuels

Coal-based fuels operations include producing synthetic fuel from our nine synfuel plants and producing coke from two coke battery plants. The production of synfuel from all of the synfuel plants and the production of coke from one of the coke battery plants generate production tax credits. Production tax credits are designed to stimulate investment in and development of alternate fuel sources. We have private letter rulings from the IRS for all of our synfuel plants. Production tax credits for synfuel-related facilities and one coke battery expire in 2007. Production tax credits were reinstated for one coke battery for the years 2006 through 2009.

The synthetic fuel process involves chemically modifying and binding particles of coal to produce a fuel that is used for power generation and coke production. Since 2002, we have sold interests in all nine of our synfuel plants, ranging from a 49%-99% share in each, or approximately 91% of our total production

capacity. We will continue evaluating opportunities to sell additional interests in our synfuel plants. We consolidate these projects due to our controlling influence and continuing involvement.

The coke battery facilities produce coke that is used in blast furnaces within the steel industry.


(Dollars in Millions)	2005		2004		2003
Production Tax Credits Generated
Synfuel Plants
Allocated to DTE Energy	$	45	$	29	$	228
Allocated to partners		562		411		146

	$	607	$	440	$	374

Coke Batteries:
Allocated to DTE Energy	$	2	$	2	$	3

On-Site Energy Projects

We own and/or operate on-site facilities, including pulverized coal injection, power generation, steam production, chilled water, wastewater treatment, pulverized petroleum coke and compressed air. Many of these facilities deliver utility-type services to industrial, commercial and institutional customers. In 2005, we executed an agreement to purchase five on-site energy projects. The purchase of three of the projects closed in 2005. We expect the purchases of the two remaining projects will close early in 2006. We also began commercial operations of a petroleum coke pulverizing facility located in Vicksburg, Mississippi.

Non-Utility Power Generation

We operate peaking, gas-fired and biomass-fired electric generating plants. We have four natural gas-fired electric generating plants that are located in the Great Lakes region, and in 2005 we acquired a 99% interest in one biomass-fired electric generating plant in California.

Landfill Gas Recovery

We develop, own and operate landfill gas recovery systems in the U.S. Landfill gas, a byproduct of solid waste decomposition, is composed of approximately equal portions of methane and carbon dioxide. We develop landfill gas recovery systems that capture the gas and use it productively. Landfill gas recovery systems provide local utilities, industry and consumers with an opportunity to use a competitive, renewable source of energy. During 2005, we acquired and placed in commercial operation a coal mine gas processing facility in southern Illinois. This processed methane is sold into the natural gas transmission system. Converting the methane into a renewable energy resource conserves fossil fuels. Many of our facilities generate production tax credits that will expire in 2007.

Landfill gas recovery has operations in 13 states.


(Dollars in Millions)	2005		2004		2003

Landfill Sites		32		29		31
Gas Produced (in Bcf)		20.2		23.2		26.8
Tax Credits Generated (1)	$	8.3	$	7.7	$	10.5


(1)		DTE Energy’s portion of total tax credits generated.

Waste Coal Recovery

We own the rights to a proprietary technology that produces high quality coal products from fine coal slurries that are typically discarded from coal mining operations. The technology produces a fine-coal fuel by removing impurities from waste coal material. The fine-coal fuel can be used in power plants, as

a feedstock for synthetic fuel production and for other industrial applications. Our first facility in Ohio became operational in late-2003. Certain problems were encountered in the excavation of the waste material and delivery to the cleaning plant. We are in a testing phase of a proprietary slurry mining system designed to allow us to economically produce a consistent product at a rate of 300,000 tons of fine coal per year.

In late 2005, we completed construction of an “in-line” demonstration waste coal recovery facility at an active coal preparation plant in Virginia. This facility is designed to increase the recovery of high value coal while reducing the amount of discarded waste coal. We are currently conducting preliminary testing. If the demonstration project proves successful, this may lead to additional opportunities for similar projects in 2006.

Properties

The following are significant Coal-Based Fuels properties:


Facility	Location	% Owned	Industry Served

Synthetic Fuels
DTE Red Mountain, LLC	Tarrant, AL	51%	Foundry Coke/Steel
DTE Belews Creek, LLC	Belews Creek, NC	1%	Utility
DTE Utah Synfuels, LLC	Price, UT	1%	Industrial/Utility
DTE Indy Coke, LLC	Moundsville, WV	1%	Utility
DTE Clover, LLC	Bledsoe, KY	5%	Utility
DTE Smith Branch, LLC	Pineville, WV	1%	Steel/Export
DTE River Hill, LLC	Karthaus, PA	51%	Utility
DTE Buckeye, LLC (2 plants)	Cheshire, OH	1%	Utility
Coke Battery
EES Coke Battery LLC (1)	River Rouge, MI	51%	Steel
Indiana Harbor Coke Co., LP	East Chicago, IN	5%	Steel


(1)		Effective January 1, 2006, we purchased an additional 49% interest in EES Coke Battery LLC.

The following are significant On-Site Energy Projects:


Facility	Location	% Owned	Type

PCI Enterprises	River Rouge, MI	100%	Pulverized Coal
DTE Sparrows Point	Sparrows Point, MD	100%	Pulverized Coal
DTE Northwind	Detroit, MI	100%	Steam and Chilled Water
DTE Moraine	Moraine, OH	100%	Compressed Air
DTE Tonawanda	Tonawanda, NY	100%	Chilled and Waste Water
Metro Energy	Romulus, MI	100%	Electricity, Hot and Chilled Water
Lordstown Energy	Lordstown, OH	100%	Steam, Chilled Water, Compressed Air and Reverse Osmosis Water
Defiance Energy	Defiance, OH	100%	Steam, Cooling Tower Water, Chilled Water, Compressed Air
DTE PetCoke	Vicksburg, MS	100%	Pulverized Petroleum Coke
Mobile Energy Services	Mobile, AL	50%	Electric Generation, Electric Distribution, and Steam
DTE Energy Center	Various sites in		Electric Distribution, Chilled Water, Waste Water,
	MI, IN, OH	50%	Lighting, Compressed Air, Mist and Dust Collectors

The following are significant properties operated by Non-Utility Power Generation:


			Capacity
Facility	Location	% Owned	(in MW)

DTE Georgetown	Indianapolis, IN	100%		80
DTE River Rouge	River Rouge, MI	100%		240
Crete Energy Ventures	Crete, IL	50%		320
DTE East China	East China Twp, MI	100%		320
Woodland Biomass	Woodland, CA	99%		25

				985

Strategy and Competition

Power and Industrial Projects will continue leveraging its extensive energy-related operating experience and project management capability to develop and grow our on-site energy business. We will continue to evaluate opportunities to sell interests in our two remaining majority-owned synfuel plants in 2006. We also will continue to pursue opportunities to provide asset management and operations services to third parties.

We anticipate building around our core strengths in the markets where we operate. In determining the markets in which to compete, we examine closely the regulatory and competitive environment, the number of competitors and our ability to achieve sustainable margins. We plan to maximize the effectiveness of our inter-related businesses as we expand from our current regional focus. As we pursue growth opportunities, our first priority will be to achieve value-added returns.

We intend to focus on the following areas for growth:

	•		Optimizing our synfuel portfolio;

	•		Providing operating services to owners of industrial and power plants;

	•		Acquiring and developing solid fuel-fired power plants and landfill gas recovery facilities;

	•		Expanding on-site energy projects; and

	•		Developing new tax advantaged opportunities.

Landfill gas recovery’s strategy capitalizes upon our industry experience of over 15 years. We are evaluating business growth through both development and acquisitions. We compete primarily with fossil fuels such as natural gas and coal. However, we believe the environmental benefits of landfill gas recovery along with reasonable and economic access to landfill sites provide a platform for future growth.

We believe that the waste coal recovery business has the potential to contribute to future earnings and provide significant environmental benefits.

Unconventional Gas Production

Description

Our Unconventional Gas Production business is engaged in natural gas exploration, development and production primarily within the Antrim shale in the northern lower peninsula of Michigan and the Barnett shale in north central Texas. We are experienced in Antrim shale where we manage one of the industry’s largest inventories of proved gas shale reserves. We are developing a significant presence in the emerging Barnett shale.

During 2005, we invested $144 million acquiring, testing, developing and producing our Antrim and Barnett shale acreage. In 2005, we added proved reserves of 76 Bcfe in both the Antrim and Barnett shales, resulting in year end total proved reserves of 397 Bcfe. The Barnett shale wells yielded 0.7 Bcfe of production in 2005. Barnett shale leasehold acres increased to 87,804 gross acres (75,994 net of interest

of others) primarily through the acquisition of a 100% interest in 44 wells and 18,000 acres in one transaction. We drilled 17 development wells (11.2 net of interest of others) in the Barnett shale acreage with a success rate of 100% in 2005. We also drilled 3 test wells (100% gross and net of interest of others) in an unproved area of the southern portion of our Barnett shale acreage holdings. Testing of the southern acreage is ongoing and will continue in 2006.

Properties

Unconventional Gas Production owns interests in the following producing wells and acreage as of December 31.


	2005				2004				2003
	Gross		Net (1)		Gross		Net (1)		Gross		Net (1)
Producing Wells and Acreage Producing Wells
Antrim shale		2,010		1,630		1,878		1,523		1,814		1,471
Barnett shale		65		55		5		1		—		—

		2,075		1,685		1,883		1,524		1,814		1,471

Developed Lease Acreage
Antrim shale		278,789		217,643		266,064		213,959		262,321		212,067
Barnett shale		15,524		14,367		1,262		316		—		—

		294,313		232,010		267,326		214,275		262,321		212,067

Undeveloped Lease Acreage
Antrim shale		86,028		73,056		92,328		79,025		94,866		81,133
Barnett shale		72,280		61,627		54,530		48,541		4,034		3,156

		158,308		134,683		146,858		127,566		98,900		84,289


(1)		Excludes the interest of others.

Strategy and Competition

We manage and operate our Antrim and Barnett shale gas properties to maximize returns on investment and increase earnings with the overriding goal of optimizing the cost of producing reserves and adding additional proved reserves. Some of our long-term contracts that fixed the prices of gas sold from production of Antrim shale gas begin to expire in 2006. This will create opportunities to remarket Antrim shale gas production at current higher market rates.

High natural gas prices and the potential for successes within the Barnett shale are resulting in more capital being invested into the region. This competition for opportunities, goods and services increases costs. However, our experience in the Antrim shale and our experienced Barnett shale personnel provide an advantage in addressing potential cost increases.

In 2006, we expect to drill 130 wells in the Antrim shale and 55 wells in the Barnett shale. Combined investment for both areas is expected to be approximately $100 million to $130 million during 2006. Successful testing on unproved acreage may yield additional significant investment opportunities.

Fuel Transportation and Marketing

Description

Fuel Transportation and Marketing consists of the electric and gas marketing and trading operations of DTE Energy Trading, Coal Transportation and Marketing, and the Pipelines, Processing and Storage businesses.

DTE Energy Trading

DTE Energy Trading focuses on physical power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s power plants and the optimization of contracted natural gas pipelines and storage capacity positions. Our customer base is predominantly utilities, local distribution companies, large industrials, and other marketing and trading companies. We enter into derivative financial instruments as part of our marketing and hedging activities. Most of the derivative financial instruments are accounted for under the mark-to-market method, which results in earnings recognition of unrealized gains and losses from changes in the fair value of the derivatives. We utilize forwards, futures, swaps and option contracts to mitigate risk associated with our marketing and trading activity as well as for proprietary trading within defined risk guidelines. DTE Energy Trading is integral in providing commodity risk management services to the other unregulated businesses within DTE Energy.

Coal Transportation and Marketing

Coal Transportation and Marketing provides fuel, transportation, and equipment management services tailored to the individual requirements of each customer. We specialize in minimizing fuel costs and maximizing reliability of supply for energy-intensive customers. Our external customers include electric utilities, merchant power producers, integrated steel mills and large industrial companies with significant energy requirements. Additionally, we participate in coal trading, coal-to-power tolling transactions and the purchase and sale of emissions credits. Coal-to-power tolling is another facet of the trading function, where we buy and arrange transportation of coal to a power plant that has excess generating capacity. The plant then burns the coal and produces electricity for a fee and returns it via the grid to DTE Energy Trading, which uses the power to fulfill contracts or meet market needs.


(in Millions)	2005		2004		2003
Tons of Coal Shipped (1)		42		40		32


(1)		Includes intercompany transactions of 20 tons, 18 tons and 14 tons in 2005, 2004 and 2003, respectively.

We also provide rail car equipment management services tailored to the individual requirements of each customer. We operate a number of railcar maintenance and repair facilities in Nebraska and Indiana serving coal transporters, as well as other industries and rail car types.

Pipelines, Processing and Storage

The Pipelines, Processing and Storage business owns and manages a network of natural gas transmission pipelines, storage facilities and gas processing facilities. We have a partnership interest in Vector Pipeline (Vector), an interstate transmission pipeline, which connects Michigan to Chicago and Ontario market centers. We specialize in providing natural gas storage and transportation services in the Midwest and Northeast markets.

Pipelines, Processing and Storage has interests in seven processing plants that extract carbon dioxide from Antrim gas production in northern Michigan, making it suitable for transportation to nearby markets. Additionally, we have storage capacity rights capable of storing up to 75.7 Bcf in natural gas storage fields located in Michigan. The Washington 10 storage facility is a 66 Bcf high deliverability storage field having bi-directional interconnections with Vector Pipeline and MichCon providing customers access to the Chicago, Michigan and Ontario market hubs.

Properties

The assets of these businesses are complementary with other DTE Energy assets. The Pipelines, Processing and Storage business holds the following property:


Property Classification	% Owned			Description	Location
Pipelines
Vector Pipeline		40	%	348-mile pipeline with
				1,000 MMcf per day capacity	Midwest
Processing Plants		90	%	197 MMcf per day capacity	Northern Michigan

Storage
Washington 28		50	%	9.7 Bcf of storage capacity	Washington Twp, MI
Washington 10	Leased			66 Bcf of storage capacity	Washington Twp, MI

Strategy and Competition

DTE Energy Trading focuses on physical gas, power marketing and structured transactions for large customers, as well as the enhancement of returns from other DTE Energy assets including natural gas production, power plants, and pipeline and storage assets.

Our strategy for our trading business is to deliver value-added services to our customers. We seek to manage this business in a manner consistent with and complementary to the growth of our other business segments. We focus on physical marketing and the optimization of our portfolio of energy assets. We compete with electric and gas marketers, traders, utilities and other energy providers. We have risk management and credit processes to monitor and mitigate risk.

Our Coal Transportation and Marketing business continues to leverage our position as one of the top North American coal marketers and our reputation as an efficient manager of transportation assets. Trends such as railroad and mining consolidation and the lack of certainty in developing new mines by many mining firms could have an impact on how we compete in the future. We will continue to work with suppliers and the railroads to promote secure and competitive access to coal to meet the energy requirements of our customers.

Pipelines, Processing and Storage focuses on asset development opportunities in the Midwest-to-Northeast region to supply natural gas to meet growing demand. We expect much of the growth in the demand for natural gas in the U.S. to occur within the Mid-Atlantic and New England regions. These regions currently lack the pipeline and gas storage infrastructure necessary to deliver gas volumes to meet growing demand. Vector is an interstate pipeline that is filling a large portion of that need, and is complemented by our Michigan storage business. Vector is awaiting FERC approval for a 200 MMcf per day expansion of long-haul capacity scheduled to be in service by November 2007. The Washington 10 storage facility received MPSC approval for a project, which expands working capacity from 51.4 to 66 Bcf. This additional working gas capacity, added to the unutilized working gas capacity previously unavailable due to lack of compression, will create additional high deliverability firm storage service which is expected to be in service by April 2006. Another opportunity is Millennium Pipeline, in which we have a 10.5% interest. Upon finalizing market support and receiving required federal and regulatory approvals, the Millennium Pipeline could be in service by 2007 and would be able to transport up to 500 MMcf per day. The gas supply for Millennium could be sourced from Michigan storage facilities or from Vector Pipeline for consumption by the higher value markets in the Northeast U.S.

CORPORATE & OTHER

Description

Corporate & Other includes various corporate support functions such as accounting, legal and information technology. Because these functions essentially support the entire Company, their costs are allocated to

the various segments based on services utilized. Therefore, the effect of the allocation on each segment can vary from year to year. Additionally, Corporate & Other holds certain non-utility debt, assets held for sale and investments in energy related funds.

Strategy and Competition

Our energy related investment strategy is to create a profitable portfolio by investing in companies that facilitate the creation of new businesses, expand growth opportunities for existing businesses or enable performance improvements in our existing businesses. We seek to gain early experience in emerging energy sectors where energy trends and technologies may create potentially profitable opportunities. The investment portfolio consists of direct investments in energy related companies and venture funds.

ENVIRONMENTAL MATTERS

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


					Non-
(in Millions)	Electric		Gas		Utility		Total
Air	$	2,385	$	—	$	10	$	2,395
Water		50		—		15		65
MGP Sites		3		35		—		38
Other Clean Up Sites		10		1		—		11

Estimated total expenditures	$	2,448	$	36	$	25	$	2,509


Estimated 2006 expenditures	$	224	$	5	$	21	$	250

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

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 four to six years, Detroit Edison may be required to install additional control technologies to reduce the environmental impact of the intake structures.

MGP Sites - Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. The facilities, which produced gas for heating and other uses, have been designated as MGP sites. Gas Utility owns, or previously owned, fifteen such former MGP sites. In addition to the MGP sites, the company is also in the process of cleaning up other contaminated sites. As a result of these determinations, we have recorded liabilities related to these sites. Cleanup activities associated with these sites will be conducted over the next several years.

Detroit Edison conducted remedial investigations at contaminated sites, including two MGP sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of

these investigations indicated that the estimated cost to remediate these sites is expected to be incurred over the next several years.

Non-utility – Our non-utility affiliates are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants. We are in the process of installing new environmental equipment at our coke battery facilities in Michigan. We expect the projects to be completed within two years. Our other non-utility affiliates are substantially in compliance with all environmental requirements.

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


Note		Title

4		Regulatory Matters
5		Nuclear Operations
13		Commitments and Contingencies

Item 1A. Company Risk Factors

There are various risks associated with the operations of DTE Energy’s utility and non-utility businesses. To provide a framework to understand the operating environment of DTE Energy, 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.

Our ability to utilize production tax credits may be limited. We have generated production tax credits from our synfuel, coke battery, landfill gas recovery and gas production operations. We have received favorable private letter rulings on all of our synfuel facilities. All production tax credits taken after 2001 are subject to audit by the Internal Revenue Service (IRS). If our production tax credits were disallowed in whole or in part as a result of an IRS audit, there could be additional tax liabilities owed for previously recognized tax credits that could significantly impact our earnings and cash flows. The value of future credits generated may be affected by new tax legislation. Moreover, production tax credits related to generation of synfuels expire at the end of 2007. The combination of IRS audits of production tax credits, supply and demand for investment in credit producing activities and new tax legislation could have an impact on our earnings and cash flows. We have also provided certain guarantees and indemnities in conjunction with the sales of interests in our synfuel facilities.

The value of a production tax credit can vary each year and is adjusted annually by an inflation factor as published by the IRS in April of the following year. Additionally, the value of the production tax credit in a given year is reduced if the Reference Price of oil within the year exceeds a threshold price and is eliminated entirely if the Reference Price exceeds a phase-out price. The Reference Price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil. For 2005, the monthly average wellhead prices were approximately $6 lower than the New York Mercantile Exchange (NYMEX) price for light, sweet crude oil. The 2006 realized and unrealized NYMEX price was $65.08 as of February 28, 2006, equating to an estimated Reference Price of $59, which is within the phase-out range. If during 2006 or 2007, the annual average wellhead price for a barrel of domestic crude oil exceeds the threshold price, our synthetic fuel business would be adversely affected for those years and, depending on the magnitude of increases in oil prices, the adverse effect for that year could be material and could have an impact on our synthetic fuel production plans which, in turn, may have a material impact on our results of operations, cash flow, and financial condition.

Our estimates of gas reserves are subject to change. We cannot assure that our estimates of our Antrim and Barnett gas reserves are accurate. Estimates of proved gas reserves and the future net cash flows attributable to those reserves are prepared by independent engineers. There are numerous uncertainties inherent in estimating quantities of proved gas reserves and cash flows attributable to such reserves, including factors beyond our control and that of our engineers. Reserve engineering is a subjective process of estimating underground accumulations of gas that cannot be measured in an exact manner. The

accuracy of an estimate of quantities of reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding expenditures for future development and exploration activities, and of engineering and geological interpretation and judgment. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based upon production history, development and exploration activities and prices of gas. Actual future production, revenue, taxes, development expenditures, operating expenses, underlying information, quantities of recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and underlying information we used. In addition, different reserve engineers may make different estimates of reserves and cash flows based on the same available data.

Failure to successfully implement new processes and information systems could interrupt our operations. Our businesses depend on numerous information systems for operations and financial information and billings. DTE2 is a multi-year Company-wide initiative to improve existing processes and implement new core information systems. We launched the first phase of our DTE2 project in 2005. Additional phases of implementation are planned for 2007. Failure to successfully implement new processes and new core information systems could interrupt our operations.

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

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

We are subject to rate regulation. Electric and gas rates for our utilities are set by the MPSC and the FERC and cannot be increased without regulatory authorization. We may be 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.

Our non-utility operations may not perform to our expectations. We rely on our non-utility operations for a significant portion of our earnings. If our current and contemplated non-utility investments do not perform at expected levels, we could experience diminished earnings potential and a corresponding decline in our shareholder value.

We rely on cash flows from subsidiaries. Cash flows from our utility and non-utility subsidiaries are required to pay interest expenses and dividends on DTE Energy debt and securities. Should a major subsidiary not be able to pay dividends or transfer cash flows to DTE Energy, our ability to pay interest and dividends would be restricted.

Adverse changes in our credit ratings may negatively affect us. Increased scrutiny of the energy industry and regulatory changes, as well as changes in our economic performance, could result in credit agencies reexamining our credit rating. While credit ratings reflect the opinions of the credit agencies issuing such

ratings and may not necessarily reflect actual performance, a downgrade in our credit rating could restrict or discontinue our ability to access capital markets at attractive rates and increase our borrowing costs. In addition, a reduction in credit rating may require us to post collateral related to various trading contracts, which would impact our liquidity.

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

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

Additionally, we may become a responsible party for environmental clean up at sites identified by a regulatory body. We cannot predict with certainty the amount and timing of future expenditures related to environmental matters because of the difficulty of estimating clean up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on potentially responsible parties.

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

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

The supply and price of fuel and other commodities may impact our financial results. We are dependent on coal for much of our electrical generating capacity. Price fluctuations and fuel supply disruptions could have a negative impact on our ability to profitably generate electricity. Our access to natural gas supplies is critical to ensure reliability of service for our utility gas customers. 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. The price of natural gas also impacts the market for other non-utility businesses that compete with utilities and alternative electric suppliers.

A work interruption may adversely affect us. Unions represent approximately 5,800 of our employees. A union choosing to strike as a negotiating tactic would have an impact on our business. We are unable to predict the effects a work stoppage would have on our costs of operation and financial performance.

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

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

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

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

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

Our participation in energy trading markets subjects us to additional risk. Events in the energy trading industry have increased the level of scrutiny on the energy trading business and the energy industry as a whole. In certain situations we may also be required to post collateral to support trading operations. We have established risk policies to manage the business.

EMPLOYEES

The following table shows our employees as of December 31, 2005 :


	Represented		Non-represented		Total
Detroit Edison		3,961		4,019		7,980
MichCon		1,501		797		2,298
Other		309		823		1,132

Total		5,771		5,639		11,410

There are several bargaining units for our represented employees. Approximately 4,590 of our represented employees are under three-year contracts that expire in 2007. The contracts of the remaining represented employees expire in 2008 and 2009.

EXECUTIVE OFFICERS OF DTE ENERGY


				Present
				Position
Name	Age (1)		Present Position	Held Since
Anthony F. Earley, Jr.		56	Chairman of the Board and Chief Executive Officer	8-1-98
Gerard M. Anderson		47	Chief Operating Officer and President	10-31-05 6-23-04
Stephen E. Ewing		61	Vice Chairman, DTE Energy	10-31-05
			President and Chief Operating Officer, MichCon	4-28-05
Robert J. Buckler		56	President and Chief Operating Officer, Detroit Edison	10-31-05
			Group President, DTE Energy	5-31-05
David E. Meador		48	Executive Vice President and Chief Financial Officer	6-23-04
Lynne Ellyn		54	Senior Vice President and Chief Information Officer	12-31-01
Paul C. Hillegonds		56	Senior Vice President	5-16-05
Ron A. May		54	Senior Vice President	1-22-04
Bruce D. Peterson		49	Senior Vice President and General Counsel	6-25-02
Peter B. Oleksiak		39	Controller	12-05-05
Sandra K. Ennis		49	Corporate Secretary	8-4-05


(1)		As of December 31, 2005

Under our Bylaws, the officers of DTE Energy are elected annually by the Board of Directors at a meeting held for such purpose, each to serve until the next annual meeting of directors or until their respective successors are chosen and qualified. With the exception of Messrs. Ewing, Hillegonds, Peterson and Ms. Ellyn, all of the above officers have been employed by DTE Energy in one or more management capacities during the past five years.

Stephen E. Ewing was elected Vice Chairman of DTE Energy on October 31, 2005 and President and Chief Operating Officer of MichCon on April 28, 2005. He previously served as group president for DTE Energy Gas since May 31, 2001. He joined DTE Energy having previously served as president and chief operating officer of MCN Energy and president and chief executive officer of MichCon during the previous five years.

Paul C. Hillegonds was elected Senior Vice President effective May 16, 2005. Mr. Hillegonds was president of Detroit Renaissance for eight years prior to joining DTE Energy.

Bruce D. Peterson was elected Senior Vice President and General Counsel on June 25, 2002. Mr. Peterson was a partner with Hunton & Williams in Washington, D.C. prior to joining DTE Energy.

Lynne Ellyn was elected Senior Vice President and Chief Information Officer on December 31, 2001. Ms. Ellyn returned to DTE Energy after spending a year serving as chief information officer of the San Francisco-based Organic Online Internet media services company. She originally joined DTE Energy in 1998 as vice president, information systems.

Pursuant to Article VI of our Articles of Incorporation, directors of DTE Energy will not be personally liable to the Company or its shareholders in the performance of their duties to the full extent permitted by law.

Article VII of our Articles of Incorporation provides that each current or former director or officer of DTE Energy, or each current and former employee or agent of the Company or a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise (including the heirs, executors, administrators or estate of such person), shall be indemnified by the Company to the full extent permitted by the Michigan Business Corporation Act or any other applicable laws as presently or hereafter in effect. In addition, we have entered into indemnification agreements with all of our officers and directors; these agreements set forth procedures for claims for indemnification as well as contractually obligating us to provide indemnification to the maximum extent permitted by law.

We and our directors and officers in their capacities as such are insured against liability for alleged wrongful acts (to the extent defined) under seven insurance policies providing aggregate coverage in the amount of $165 million.

Item 3. Legal Proceedings

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

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

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


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

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

We did not submit any matters to a vote of security holders in the fourth quarter of 2005.

Part II

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

Our common stock is listed on the New York Stock Exchange, which is the principal market for such stock, and the Chicago Stock Exchange. The following table indicates the reported high and low sales prices of our common stock on the Composite Tape of the New York Stock Exchange and dividends paid per share for each quarterly period during the past two years:


							Dividends
							Paid
Calendar		Quarter	High		Low		Per Share
	2005
		First	$	46.99	$	42.40	$	0.515
		Second	$	48.31	$	44.40	$	0.515
		Third	$	48.22	$	44.11	$	0.515
		Fourth	$	46.65	$	41.39	$	0.515

	2004
		First	$	42.29	$	37.92	$	0.515
		Second	$	41.58	$	37.88	$	0.515
		Third	$	42.21	$	39.31	$	0.515
		Fourth	$	45.49	$	41.44	$	0.515

At December 31, 2005, there were 177,814,429 shares of our common stock outstanding. These shares were held by a total of 94,981 shareholders of record.

Our Bylaws nullify Chapter 7B of the Michigan Business Corporation Act (Act). This Act regulates shareholder rights when an individual’s stock ownership reaches 20% of a Michigan corporation’s outstanding shares. A shareholder seeking control of the Company cannot require our Board of Directors to call a meeting to vote on issues related to corporate control within 10 days, as stipulated by the Act. See Note 8 – Common Stock and Earnings Per Share for information concerning the Shareholders’ Rights Agreement.

We paid cash dividends on our common stock of $360 million in 2005, $354 million in 2004 and $346 million in 2003. The amount of future dividends will depend on our earnings, cash flows, financial condition and other factors that are periodically reviewed by our Board of Directors. Although there can be no assurances, we anticipate paying dividends at the current rate of $0.515 per quarter for the foreseeable future.

All of our equity compensation plans that provide for the annual awarding of stock-based compensation have been approved by shareholders. See Note 15 — Stock Based Compensation for additional detail. See the following table for information as of December 31, 2005.

Number of

securities

securities to be

remaining available

issued upon

Weighted-average

for future issuance

exercise of

exercise price of

under equity

outstanding options

compensation plans

Plans approved by shareholders

6,236,343

41.31

6,270,941

Item 6. Selected Financial Data

The following selected financial data should be read with the accompanying Management’s Discussion and Analysis and Notes to the Financial Statements.


(in Millions, except per share amounts)	2005			2004			2003			2002		2001(1)

Operating Revenues	$	9,022		$	7,071		$	7,005		$	6,694	$	5,771

Net Income (Loss)
Total from continuing operations	$	576		$	461		$	494		$	599	$	317
Discontinued operations		(36	)		(30	)		54			33		12
Cumulative effect of accounting changes		(3	)		—			(27	)		—		3

Net Income	$	537		$	431		$	521		$	632	$	332

Diluted Earnings Per Share
Total from continuing operations	$	3.27		$	2.66		$	2.93		$	3.63	$	2.06
Discontinued operations		(.20	)		(.17	)		.32			.20		.08
Cumulative effect of accounting changes		(.02	)		—			(.16	)		—		.02

Diluted Earnings Per Share	$	3.05		$	2.49		$	3.09		$	3.83	$	2.16


Financial Information
Dividends declared per share of common stock	$	2.06		$	2.06		$	2.06		$	2.06	$	2.06
Total assets	$	23,335		$	21,297		$	20,753		$	19,985	$	19,587
Long-term debt, including capital leases	$	7,080		$	7,606		$	7,669		$	7,803	$	7,928
Shareholders’ equity	$	5,769		$	5,548		$	5,287		$	4,565	$	4,589


(1)		Includes the acquisition of the Gas Utility business and other non-utility gas businesses on May 31, 2001.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

DTE Energy is a growing and diversified energy company with 2005 revenues in excess of $9 billion and approximately $23 billion in assets. Since 2003, our asset base has increased by 12% and operating revenues have grown by 29%.

We are the parent company of Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales and distribution services throughout southeastern Michigan. We operate three energy-related non-utility segments with operations throughout the United States.

In 2005, our utilities and Power and Industrial Projects segment generated most of our earnings. The improvement in earnings was due to rate increases at our Michigan utilities, favorable weather and continued asset gains from the synthetic fuel business. Earnings were also impacted by mark-to-market losses in our Fuel Transportation and Marketing segment and losses from discontinued operations.

Our 2005 financial performance improved over 2004. The following table summarizes our income since 2003:


(in millions, except Earnings per Share)
	2005		2004		2003
Net Income	$	537	$	431	$	521
Earnings per Diluted Share	$	3.05	$	2.49	$	3.09
*Excluding Discontinued Operations and Accounting Changes*
Income from Continuing Operations	$	576	$	461	$	494
Earnings per Diluted share	$	3.27	$	2.66	$	2.93

The items discussed below influenced our 2005 financial performance and may affect future results:

•		Effects of weather and accounts receivable on utility operations;

•		Electric rate orders, electric Customer Choice program, and coal and uranium supply;

•		Gas rate and gas cost recovery orders and gas supply;

•		Synfuel-related earnings and the impact of higher oil prices on production credit phase-outs;

•		Investments in our unconventional gas production business;

•		Mark-to-market losses in our Fuel Transportation and Marketing business; and

•		Cost reduction efforts and required capital investment.

UTILITY OPERATIONS

Weather - Earnings at our utility operations are seasonal and very sensitive to weather. Electric utility earnings are dependent on hot summer weather, while the gas utility’s results are dependent on cold winter weather. The following table explains the impact of weather relative to 30-year historical normal weather temperatures for each utility.


	Percentage change from Normal (1)						Estimated effect on Net Income
(Dollars in Millions)	Electric			Gas			Electric			Gas
Year	Utility			Utility			Utility			Utility			Total
2005		47	%		(3	)%	$	63		$	(4	)	$	59
2004		(17	)%		(4	)%	$	(40	)	$	(9	)	$	(49	)
2003		(13	)%		2	%	$	(24	)	$	3		$	(21	)


(1)		Electric Utility is based on cooling degree days and the Gas Utility is based on heating degree days.

The positive impact of warmer weather was partially mitigated by the rate cap on residential customers which prevented us from passing through increased generation and purchased power costs incurred to serve the higher demand. Additionally, we occasionally experience various types of storms that damage our electric distribution infrastructure resulting in power outages. Restoration and other costs associated with storm-related power outages lowered pretax earnings by $82 million in 2005, $48 million in 2004 and $72 million in 2003.

Receivables - Both utilities continue to experience high levels of past due receivables, especially within our Gas Utility operations. The increase is attributable to economic conditions, high natural gas prices and the lack of adequate levels of assistance for low-income customers.

We have taken aggressive actions to reduce the level of past due receivables including, increased customer disconnections, contracting with collection agencies and working with the State of Michigan and others to increase the share of low-income funding allocated to our customers. In 2005, we sold previously written-off accounts of $187 million resulting in a gain and net proceeds of $6 million. The gain was recorded as a recovery through bad debt expense, which is included within operation and maintenance expense. As a result of these factors, our allowance for doubtful accounts expense for the two utilities decreased to $98 million in 2005 from $105 million in 2004.

The April 2005 MPSC gas rate order provided for an uncollectible tracking mechanism for MichCon. We will file an annual application comparing our actual uncollectible expense to our designated revenue recovery of approximately $37 million. Ninety percent of the difference from the date of the order will be refunded or surcharged after an annual reconciliation proceeding before the MPSC.

Electric Utility

Electric rate orders — In 2004, the MPSC issued interim and final rate orders that authorized electric rate increases totaling $374 million, 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 MPSC also authorized the recovery of approximately $385 million in regulatory assets, including stranded costs. As a result of increased rates, our 2005 pretax margins were higher by $116 million.

Electric Customer Choice - Our customers have the option of participating in the electric Customer Choice program where they can select an alternative electric supplier. Due to distorted pricing mechanisms during the initial period of electric Customer Choice, many commercial customers chose alternative electric suppliers. The impact of the final rate order in 2004, that increased base rates including the recovery of lost margins and transition charges, combined with recent higher wholesale electric prices has resulted in many former electric Customer Choice customers migrating back to Detroit Edison for electrical generation service, partially mitigating the financial impact of the electric Customer Choice program.

The return of customers from the electric Customer Choice program resulted in higher gross margins during 2005. The following graph depicts the electric Customer Choice volumes:

We continue to work with the MPSC to address issues associated with the electric Customer Choice program. In February 2005, we filed a revenue-neutral rate restructuring proposal with the MPSC designed to adjust rates for each customer class to be reflective of the full costs incurred to service such customers. In December 2005, the MPSC issued an order that took some initial steps to improve the current competitive imbalance in Michigan’s electric Customer Choice program. The December 2005 order establishes cost-based power supply rates for Detroit Edison’s full service customers. Electric Customer Choice participants will pay cost-based distribution rates, while Detroit Edison’s full service commercial and industrial customers will pay cost-based distribution rates that reflect the cost of the residential rate subsidy. Residential customers pay a subsidized below cost rate for distribution service. These revenue neutral revised rates were effective February 1, 2006.

Coal Supply – Our generating fleet produces in excess of 70% of its electricity from coal. Increasing coal demand from domestic and international markets has resulted in significant price increases. In addition, difficulty in recruiting workers, obtaining environmental permits and finding economically recoverable amounts of new coal has resulted in decreasing coal output from the central Appalachian region. Furthermore, as a result of environmental regulation and declining eastern coal stocks, demand for cleaner burning western coal has increased. This increased demand for western coal has also resulted in a corresponding demand for western rail shipping, straining railroad capacity, resulting in longer lead times for western coal shipments.

Uranium Supply - We operate one nuclear facility that undergoes a periodic refueling outage approximately every eighteen months. Uranium prices have been rising due to supply concerns. In the future, there may be additional nuclear facilities constructed in the industry that may place additional pressure on uranium supplies and prices.

Gas Utility

Gas final rate order – In April 2005, the MPSC issued a final rate order authorizing MichCon to earn a rate of return on common equity of 11% based on a 50% debt and 50% equity capital structure. Highlights of the order include:

	•		$61 million increase in annual base rates;

	•		base rate increase includes $25 million to recover safety and training costs;

	•		deferral as a regulatory liability for the non-capitalized portion of negative pension expense; and

	•		adoption of a tracking mechanism for uncollectible accounts receivable.

The final rate order from the MPSC denied recovery or required accounting impairment for the following items:

	•		$25 million of allocated merger interest from DTE Energy related to the acquisition of MCN Energy;

	•		$6 million of internal labor and legal costs to remediate MGP sites;

	•		$5 million as a result of a change to the allocation of historical MGP insurance proceeds;

	•		$6 million of computer equipment and related depreciation; and

	•		$42 million impairment related to 90% of the cost of a computer billing system in place prior to DTE Energy’s acquisition of MCN Energy. This impairment had a minimal earnings impact on DTE Energy because a valuation allowance was established for this asset at the time of the MCN acquisition in 2001.

Additionally, the rate order adjusted MichCon’s depreciation rates and the related revenue requirements with no resulting impact on net income.

Gas cost recovery order – Based on rate orders in place for 2001 and 2002, we filed a gas cost recovery case in 2002 and recorded a $26 million regulatory asset related to unbilled volumes as of December 31, 2001. Over time we recorded $3 million of interest associated with this regulatory asset. In its April 28, 2005 order, the MPSC disallowed recovery and we recorded the impact of the disallowance in the first quarter of 2005.

Natural Gas Supply – Increased demand from natural gas power plants, 2005 hurricane related supply disruptions, regulatory constraints and limited exploration have combined to strain existing natural gas supplies and caused substantial increases in prices.

NON-UTILITY OPERATIONS

We anticipate significant investment opportunities within our non-utility businesses. We employ disciplined investment criteria when assessing opportunities that will leverage our existing assets, skill and expertise. Specifically, we invest in targeted energy markets with attractive competitive dynamics where meaningful scale is in alignment with our risk profile. Assuming no phase-out of production tax credits, the source of investment capital is the estimated cumulative $1.2 billion we anticipate from synfuel cash flow which consists of cash from operations, asset sales, and the utilization of current and previously earned production tax credits to reduce tax payments. Tax credit carryforward utilization in part could be extended past 2008, if taxable income is reduced from current forecasts. However, if oil prices remain at current levels or continue to increase, the estimated cash flow from the synfuel business would be significantly less and would adversely impact the success of this strategy, unless we identify alternative sources of cash.

Power and Industrial Projects

We anticipate building around our core strengths in the markets where we operate. In determining the markets in which to compete, we closely examine the regulatory environment, the number of competitors and our ability to achieve sustainable margins. We plan to maximize the effectiveness of our inter-related businesses as we expand from our current regional focus. As we pursue growth opportunities, our first priority will be to achieve value-added returns.

We plan to focus on the following areas for growth:

	•		Optimizing the remaining life of our synfuel portfolio;

	•		Providing operating services to owners of industrial and power plants;

	•		Acquiring and developing solid fuel-fired power plants;

	•		Expanding on-site energy projects; and

	•		Developing new tax advantaged opportunities.

Synfuel-related earnings — We operate nine synthetic fuel production plants throughout the United States. Synfuel plants chemically change coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits are provided for the production and sale of solid synthetic fuel produced from coal. These tax credits expire on December 31, 2007. Our synthetic fuel plants generate operating losses which are offset by the resulting production tax credits. We have not had sufficient taxable income to fully utilize production tax credits earned in prior periods. As of December 31, 2005, we have $484 million in tax credit carry-forwards.

To optimize income and cash flow from our synfuel operations, we have sold interests in all nine of our facilities, representing 91% of our total production capacity as of December 31, 2005. We will continue to evaluate opportunities to sell additional interests in our two remaining majority-owned plants. Proceeds from the sales are contingent upon production levels and the value of such credits. When we sell an interest in a synfuel project, we recognize the gain as the facility produces and sells synfuel and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectibility is reasonably assured. In substance, we are receiving synfuel gains and reduced operating losses in exchange for tax credits associated with the projects sold. Sales of interests in synfuel projects allow us to accelerate cash flow while maintaining a stable income base.

The value of a production tax credit can vary each year and is adjusted annually by an inflation factor as published by the IRS in April of the following year. The value of the production tax credit in a given year is reduced if the Reference Price of oil within the year exceeds a threshold price and is eliminated entirely if the Reference Price exceeds a phase-out price. The Reference Price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil. During 2005, the monthly average wellhead prices were approximately $6 lower than the New York Mercantile Exchange (NYMEX) price for light, sweet crude oil. The actual or estimated Reference Price and beginning and ending phase-out prices per barrel of oil for 2004 through 2007 are as follows:


		Beginning Phase-Out		Ending Phase-Out
	Reference Price	Price		Price
2004 (actual)	$36.75	$	51.35	$	64.46
2005 (estimated)	$51	$	53	$	66
2006 (estimated)	Not Available	$	53	$	67
2007 (estimated)	Not Available	$	54	$	68

Recent events have increased domestic crude oil prices, including hurricane-related supply disruptions and continued worldwide demand. Through December 31, 2005, the NYMEX daily closing price of a barrel of oil for 2005 averaged approximately $57, which due to the uncertainty of the wellhead/NYMEX difference, is comparable to an approximate $51 Reference Price. For the remaining life of the tax credits, if the Reference Price falls within or exceeds the phase-out range, the availability of production tax credits in that year would be reduced or eliminated. Any actual tax credit phase-out for 2006 and available tax credits, if any, will not be certain until published by the IRS in April 2007. As of February 28, 2006, the realized and unrealized NYMEX daily closing price of a barrel of oil was $65.08, equating to an estimated Reference Price of $59, which is within the phase-out range. If prices remain at this level throughout 2006, we would experience a phase-out of the production tax credits and our synthetic fuel business would be adversely affected; this could have an impact on our synthetic fuel production plans which, in turn, may have a material adverse impact on our results of operations, cash flow, and financial condition. However, we cannot predict with any certainty the Reference Price for 2006 or beyond.

There is legislation pending in Congress that may impact the potential phase-out of production tax credits for 2006 and 2007. The legislation would use the prior year oil price to determine the current year Reference Price. We are unable to predict the outcome of this legislation.

The gain from the sale of synfuel facilities is comprised of fixed and variable components. The fixed component represents note payments of principal and interest, is not subject to refund, and is recognized as a gain when earned and collectibility is assured. The variable component is based on an estimate of tax credits allocated to our partners, is subject to refund based on the annual oil price phase-out, and is recognized as a gain only when the probability of refund is considered remote and collectibility is assured. Additionally, based on estimates of tax credits allocated, our partners reimburse us (through the project entity) for the operating losses of the synfuel facilities. In the event that the tax credit is phased out, we are contractually obligated to refund to our partners all or a portion of the operating losses funded by our partners. To assess the probability of refund, we use valuation and analysis models that calculate the probability of surpassing the estimated lower band of the phase-out range for the Reference Price of oil for the year. Due to the rise in oil prices, there was a possibility that the 2005 Reference Price of oil could have reached the threshold at which production tax credits would have begun to phase-out. We

deferred all variable gains for the first three quarters of 2005. However, in the fourth quarter of 2005, when there was persuasive evidence that the Reference Price of oil would not surpass the estimated lower band of the phase-out range, we recognized all the variable gains related to 2005, of which $167 million (pre-tax) were attributable to the first three quarters of 2005.

Due to changes in the agreements with certain of our synfuel partners and the exercise of existing rights by other of our synfuels partners, a higher percentage of the expected payments in 2006 may be variable note payments. As a result, a larger portion of the 2006 synfuel payments may be subject to refund should a phase-out occur. We will likely defer recognition of the quarterly variable and certain indemnified fixed note payments in 2006 until the probability of refund is remote and collectibility is assured.

As discussed in Note 12, we have entered into derivative and other contracts to economically hedge a portion of our 2006 and 2007 synfuel cash flow exposure related to the risk of oil prices increasing. The derivative contracts are marked to market with changes in fair value recorded as an adjustment to synfuel gains. We recorded a pretax mark to market gain of $48 million during 2005. As part of our synfuel-related risk management strategy, we continue to evaluate alternatives available to mitigate unhedged exposure to oil price volatility. These contracts, and other actions we can take and have taken, will protect approximately 53% of our 2006 cash flow and 31% of our 2007 cash flow. As our risk management position changes due to market volatility or legislative actions, we may adjust our hedging strategy in response to changing conditions.

In addition to entering into economic hedges, we can mitigate our exposure to a tax credit phase-out by shutting down or reducing production at our synfuel facilities, which decreases the amount of operating losses we generate. We regularly monitor oil prices and have created contingency plans to cease synfuel production.

Assuming no synfuel tax credit phase-out, we expect cash flow from our synfuel business will be approximately $1.2 billion from 2006 to 2008. If prices remain at current levels or increase throughout 2006, synfuel production levels may be reduced, which would reduce the income and cash flow from this business. If the Reference Price results in a complete phase out of the synfuel tax credits for 2006, and assuming the previously discussed current level of economic hedges and an early cessation of synfuel production to avoid operating losses, there is a potential negative impact to net income and cash flow of $160 million and $140 million, respectively, before any potential asset impairment and goodwill write-off.

Unconventional Gas Production

During the past year, natural gas prices have reached historically high levels. These high prices provide attractive opportunities for our Unconventional Gas Production business segment. We are an experienced operator with 15 years of experience in the Antrim shale in northern Michigan, and we recently expanded our operations in the Barnett shale basin in north central Texas. Recent leasehold acquisitions have increased our total leasehold acreage to 452,621 acres (366,693 net of interest of others). Over the next few years, our goal is to expand our existing leasehold acreage position and transform unproved acreage into proved reserves.

Antrim shale – We plan to grow through the extension of existing producing areas and acquisition of other producer’s properties. Additionally, we intend to develop existing acreage using the latest horizontal drilling techniques and to continue to search for expansion acreage. Some of our long-term fixed-price obligations for production of Antrim gas begin to expire in 2006. This will create opportunities to remarket Antrim production at significantly higher current market rates.


Michigan – Antrim Shale	2005		2004		2003
Net Producing Wells		1,630		1,523		1,471

Production Volume (Bcfe)		21.5		22.5		23.2

Proved Reserves (Bcfe)		338.4		335.4		351.9

Net Developed Acreage		217,643		213,959		212,067

Net Undeveloped Acreage		73,056		79,025		81,133

Capital Expenditures (in millions)	$	37	$	22	$	26
Future Net Cash Flows (in millions) (1)	$	1,307	$	760	$	485

Average gas price with hedges (per Mcf)	$	3.10	$	3.10	$	2.97
Average gas price without hedges(per Mcf) (2)	$	7.73	$	5.57	$	4.98


(1)		Represents the standardized measure of discounted future net cash flows as calculated by an independent engineering firm utilizing extensive estimates. The estimated future net cash flow computations should not be considered to represent our estimate of the expected revenues or the current value of existing proved reserves and do not include the impact of hedge contracts.

(2)		The gas produced in the Antrim shale is subject to hedges that begin to expire in 2006. In 2006, we expect to remarket 2.0 Bcf at current market pricing. For 2007, we anticipate remarketing an additional 1.8 Bcf.

Barnett shale - We anticipate significant opportunities in our existing Barnett shale acreage and expect continued extension of producing areas within the Fort Worth Basin. We are currently in the test and development phase for unproved and recently acquired Barnett shale acreage. We plan to increase our acreage through small negotiated acquisitions to build scale.


Texas – Barnett Shale	2005		2004		2003
Net Producing Wells		55		1		—

Production Volume (Bcfe)		0.7		—		—

Proved Reserves (Bcfe)		58.6		7.9		—

Net Developed Acreage		14,637		316		—

Net Undeveloped Acreage		61,627		48,541		3,156

Capital Expenditures (in millions)	$	107	$	16	$	2
Future Net Cash Flows (in millions) (1)	$	127	$	7		—

Average gas price (per Mcf)	$	9.01	$	5.70		—


(1)		Represents the standardized measure of discounted future net cash flows as calculated by an independent engineering firm utilizing extensive estimates. The estimated future net cash flow computations should not be considered to represent our estimate of the expected revenues or the current value of existing proved reserves and do not include the impact of hedge contracts.

Due to high natural gas prices and the potential for successes within the Barnett shale, more capital is being invested into the region. The competition for opportunities and goods and services may result in increased operating costs. However, our experience in the Antrim shale and our experienced Barnett shale personnel provide an advantage in addressing potential cost increases. We expect to invest a combined amount of approximately $100 million to $130 million in our unconventional gas business in 2006.

Fuel Transportation and Marketing

Pipelines, Processing and Storage is in the process of expanding our storage capacity in Michigan and expanding and building new pipeline capacity to the northeast United States. Our Coal Transportation

and Marketing business will seek to build our capacity to transport greater amounts of western coal and may seek to expand into coal terminals.

Significant portions of the electric and gas marketing and trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as owned and contracted natural gas pipelines and storage capacity positions. Most financial instruments are deemed derivatives, whereas the gas inventory, pipelines and storage assets are not derivatives. As a result, this segment may experience dramatic earnings volatility as derivatives are marked to market without revaluing the underlying non-derivative contracts and assets. This results in gains and losses that are recognized in different accounting periods. We incur gains or losses in one period that are subsequently reversed when transactions are settled.

During 2005, our earnings were negatively impacted by the economically favorable decision in early 2005 to delay previously planned withdrawals from gas storage due to a decrease in the current price for natural gas and an increase in the forward price for natural gas. The financial impact of this timing difference has begun to reverse as the gas is withdrawn from storage in the current storage cycle and is sold at prices significantly in excess of the cost of gas in storage. In addition, we entered into forward power contracts to economically hedge certain physical and capacity power contracts. Some of these underlying contracts are not derivatives, while the related economic hedges are derivatives, and therefore marked to market. As a result, these transactions produce the timing related earnings swings from period to period. We expect the timing difference on the forward power contracts will not be fully realized until 2007.

OPERATING SYSTEM AND PERFORMANCE EXCELLENCE PROCESS

We continuously review and adjust our cost structure and seek improvements in our processes. Beginning in 2002, we adopted the DTE Energy Operating System, which is the application of tools and operating practices that have resulted in operating efficiencies, inventory reductions and improvements in technology systems, among other enhancements. Some of these cost reductions may be returned to our customers in the form of lower PSCR charges and the remaining amounts may impact our profitability.

As an extension of this effort, in mid-2005, we initiated a company-wide review of our operations called the Performance Excellence Process. The overarching goal has been and remains to become more competitive by reducing costs, eliminating waste and optimizing business processes while improving customer service. Many of our customers are under intense economic pressure and will benefit from our efforts to keep down our costs and their rates. Additionally, we will need significant resources in the future to invest in the infrastructure necessary to compete. Specifically, we began a series of focused improvement initiatives within our Electric and Gas Utilities, and our corporate support function.

The process will be rigorous and challenging and seeks to yield sustainable performance to our customers and shareholders. We have identified the Performance Excellence Process as critical to our long-term growth strategy. We are entering the implementation phase and expect to begin to realize the benefits from the effort in 2006. The cost to execute the Performance Excellence Process could result in non-recurring restructuring charges in 2006.

CAPITAL INVESTMENT

We anticipate significant capital investment across all of our business segments. Most of our capital expenditures will be concentrated within our utility segments. Our electric utility currently expects to invest approximately $4 billion due to increased environmental requirements and reliability enhancement projects through 2010. Our gas utility currently expects to invest approximately $900 million on system expansion, pipeline safety and reliability enhancement projects through the same period. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base.

During 2005, we began the first wave of implementation of DTE2, an enterprise resource planning system initiative to improve existing processes and to implement new core information systems. We anticipate

spending $165 million to $190 million over the next two years as the remaining system elements are developed and business segments fully adopt DTE2.

In the future, we may build a new base-load electric generating plant. The last base load plant constructed within our electric utility service territory was approximately twenty years ago. A recently completed study, sponsored by the MPSC, projected that Michigan may need to install 7,000 MW of additional capacity over the next ten years. We estimate that a new base-load plant will cost between $1 billion and $2 billion.

OUTLOOK

The next few years will be a time of rapid change for DTE Energy and for the energy industry. Our strong utility base combined with our integrated non-utility operations position us well for long-term growth. Due to the enactment of the Energy Policy Act of 2005 and the repeal of the Public Utility Holding Company Act of 1935 there are fewer barriers to mergers and acquisitions of utility companies. We anticipate greater industry consolidation over the next few years resulting in the creation of large regional utility providers.

Looking forward, we will focus on several points that we expect will improve future performance:

	•		continuing to pursue regulatory stability and investment recovery for our utilities;

	•		managing the growth of our utility asset base;

	•		enhancing our cost structure across all business segments;

	•		improving our Electric and Gas Utility customer satisfaction;

	•		increasing the scale in our three non-utility business segments; and

	•		investing in businesses that integrate our assets and leverage our skills and expertise.

Along with pursuing a leaner organization, we expect to receive an estimated $1.2 billion (assuming no phase-out) of synfuel cash flow through 2008, which consists of cash from operations, asset sales, and the utilization of production tax credits to reduce tax payments. Tax credit utilization in part could be extended past 2008, if taxable income is reduced from current forecasts. However, if oil prices remain at current levels or continue to increase, the estimated cash flow from the synfuel business would, as a result of production tax credit phase-out, be significantly less and would adversely impact the success of this strategy, unless we identify alternative sources of cash.

Anticipated redeployment of this expected available cash will reduce DTE Energy’s debt and replace the value of synfuel operations inherent in our share price by pursuing investments in targeted energy markets. If adequate investment opportunities are not available, share repurchases may be used to build shareholder value. We remain committed to a strong balance sheet and financial coverage ratios, and paying an attractive dividend.

RESULTS OF OPERATIONS

Net income in 2005 was $537 million, or $3.05 per diluted share, compared to net income of $431 million, or $2.49 per diluted share in 2004 and net income of $521 million, or $3.09 per diluted share in 2003. The comparability of earnings was impacted by our discontinued businesses, DTE Energy Technologies (Dtech), Southern Missouri Gas Company and ITC, and the adoption of a new accounting rule in 2005 and two new accounting rules in 2003. Excluding discontinued operations and the cumulative effect of accounting changes, our income from continuing operations in 2005 was $576 million, or $3.27 per diluted share, compared to income of $461 million, or $2.66 per diluted share in 2004 and income of $494 million, or $2.93 per diluted share in 2003. The following sections provide a detailed discussion of our segments, operating performance and future outlook.


(in Millions, except per share data)	2005			2004			2003
Net Income (Loss)

Electric Utility	$	277		$	150		$	252
Gas Utility		37			20			29
Non-utility Operations:
Power and Industrial Projects		308			179			197
Unconventional Gas Production		4			6			12
Fuel Transportation and Marketing		2			118			69

Corporate & Other		(52	)		(12	)		(65	)

Income (Loss) from Continuing Operations:
Utility		314			170			281
Non-utility		314			303			278
Corporate & Other		(52	)		(12	)		(65	)

		576			461			494
Discontinued Operations		(36	)		(30	)		54
Cumulative Effect of Accounting Changes		(3	)		—			(27	)

Net Income	$	537		$	431		$	521


Diluted Earnings Per Share
Total Utility	$	1.78		$	.98		$	1.67
Non-utility Operations		1.78			1.75			1.65
Corporate & Other		(.29	)		(.07	)		(.39	)

Income from Continuing Operations		3.27			2.66			2.93
Discontinued Operations		(.20	)		(.17	)		.32
Cumulative Effect of Accounting Changes		(.02	)		—			(.16	)

Net Income	$	3.05		$	2.49		$	3.09

The earnings per share of any segment does not represent a direct legal interest in the assets and liabilities allocated to any one segment but rather represents a direct or indirect equity interest in DTE Energy’s assets and liabilities as a whole.

ELECTRIC UTILITY

Our Electric Utility segment consists of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.2 million customers in southeastern Michigan.

Factors impacting income: Our net income increased $127 million to $277 million in 2005 from $150 million in 2004. 2004 net income decreased $102 million from $252 million in 2003. These results primarily reflect higher rates due to the November 2004 MPSC final rate order, return of customers from the electric Customer Choice program, warmer weather and lower operations and maintenance expenses in 2005, partially offset by a portion of higher fuel and purchased power costs, which were unrecoverable as a result of residential rate caps (which expired January 1, 2006), and increased depreciation and amortization expenses.


(in Millions)	2005			2004			2003
Operating Revenues	$	4,462		$	3,568		$	3,695
Fuel and Purchased Power		1,590			885			939

Gross Margin		2,872			2,683			2,756
Operation and Maintenance		1,308			1,395			1,332
Depreciation and Amortization		640			523			473
Taxes Other Than Income		241			249			257
Asset (Gains) and Losses, Net		(26	)		(1	)		20

Operating Income		709			517			674
Other (Income) and Deductions		283			303			277
Income Tax Provision		149			64			145

Net Income	$	277		$	150		$	252


Operating Income as a Percent of Operating Revenues		16	%		14	%		18	%

Gross margins increased $189 million during 2005 and declined $73 million in 2004. Operating revenues increased due to higher demand resulting from warmer weather in 2005 and increased rates due to the November 2004 MPSC final rate order, partially offset by unrecovered power supply costs as a result of residential rate caps (which expired January 1, 2006) and a poor Michigan economy in 2005. Gross margins were favorably impacted by decreased electric Customer Choice penetration, whereby Detroit Edison lost 12% of retail sales to electric Customer Choice customers in 2005 and 18% of such sales during 2004 as retail customers migrated back to Detroit Edison as their electric generation provider rather than remaining with alternative suppliers. The following table displays changes in various gross margin components relative to the comparable prior period:


Increase (Decrease) in Gross Margin Components Compared to Prior Year	2005			2004
(in Millions)
Weather related margin	$	166		$	(25	)
MPSC 2004 rate orders		116			22
Unrecovered power supply costs – residential customers		(73	)		—
Transmission charges (1)		(93	)		—
Electric Customer Choice program		79			(82	)
Service territory economic performance		(23	)		9
Other, net		17			3

Increase (decrease) in gross margin	$	189		$	(73	)


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

Operating revenues and fuel and purchased power costs increased in 2005 reflecting a $8.79 per MWh (58%) increase in fuel and purchased power costs during the year. Fuel and purchased power costs are a pass-through with the reinstatement of the PSCR mechanism, except for residential customers whose rate caps expired in January 2006.

The increase in power supply costs was driven by higher seasonal demand, higher purchased power rates, higher coal prices and increased power purchases due to weather and plant outages. Pursuant to the MPSC final rate order, transmission expense, previously recorded in operation and maintenance expenses in 2004, is now reflected in purchased power expenses. The PSCR mechanism provides related revenues for the transmission expense.

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

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


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

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

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

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


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

Purchased Power	$	89.37				$	37.06				$	41.73

Overall Average Unit Cost	$	23.90				$	15.11				$	16.38


(1)		Represents fuel costs associated with power plants.


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

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

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


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

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


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

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

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

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

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

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

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

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

Outlook – We continue to improve the operating performance of Detroit Edison. During the past year we have resolved many of our regulatory issues and continue to pursue additional regulatory solutions for structural problems within our competitive environment, mainly electric Customer Choice and the need to adjust rates for each customer class to reflect the full cost of service.

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

Long term, we will be required to invest an estimated $2.4 billion on emission controls through 2018. Should we be able to recover these costs in future rate cases, we may experience a growth in earnings. Additionally, our service territory may require additional generation capacity. A new base-load generating plant has not been built within the State of Michigan in the last 20 years. Should our regulatory environment be conducive to such a significant capital expenditure, we may build or expand a new base- load facility, with an estimated cost of $1 billion to $2 billion.

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

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

	•		our ability to reduce costs;

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

	•		plant performance;

	•		economic conditions within the state of Michigan;

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

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

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

GAS UTILITY

Our Gas Utility segment consists of MichCon and Citizens Fuel Gas Company (Citizens), natural gas utilities subject to regulation by the MPSC. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.3 million residential, commercial and industrial customers in the State of Michigan. MichCon also has subsidiaries involved in the gathering and transmission of natural gas in northern Michigan. MichCon operates one of the largest natural gas distribution and transmission systems in the United States. Citizens distributes natural gas in Adrian, Michigan.

Factors impacting income: Gas Utility’s net income increased $17 million in 2005 and declined $9 million in 2004, compared to the prior year, primarily reflecting the impact of the MPSC’s April 2005 gas cost recovery and final rate orders.

The MPSC final gas rate order disallowed recovery of 90% of the costs of a computer billing system that was in place prior to DTE Energy’s acquisition of MCN Energy in 2001. MichCon impaired this asset by approximately $42 million in the first quarter of 2005. This disallowance was not reflected at the DTE Energy level since this impairment was previously reserved at the time of the MCN acquisition in 2001.


(in Millions)	2005			2004			2003
Operating Revenues	$	2,138		$	1,682		$	1,498
Cost of Gas		1,490			1,071			909

Gross Margins		648			611			589
Operation and Maintenance		424			403			371
Depreciation and Amortization		95			103			101
Taxes Other Than Income		43			49			52
Asset (Gains) and Losses, Net		4			(3	)		—

Operating Income		82			59			65
Other (Income) and Deductions		47			48			36
Income Tax Benefit		(2	)		(9	)		—

Net Income	$	37		$	20		$	29


Operating Income as a Percent of Operating Revenues		4	%		4	%		4	%

Gross margins increased $37 million in 2005 and increased $22 million in 2004, compared to the prior year. Gross margins in 2005 were favorably affected by higher base rates as a result of the interim and final gas rate orders, and revenue associated with the uncollectible expense tracking mechanism authorized by the MPSC. In April 2005, the MPSC issued an order in the 2002 GCR reconciliation case that disallowed $26 million representing unbilled revenues at December 2001. We recorded the impact of the disallowance during the first quarter of 2005. Operating revenues and cost of gas increased in 2005

reflecting higher gas prices which are recoverable from customers through the GCR mechanism. The 2004 gross margin comparison was also affected by a $26.5 million pre-tax reserve recorded in 2003 for the potential disallowance in gas costs pursuant to an MPSC order in MichCon’s 2002 GCR plan case. See Note 4.


	2005		2004		2003
Gas Markets (in Millions)
Gas sales	$	1,860	$	1,435	$	1,242
End user transportation		134		119		136

		1,994		1,554		1,378
Intermediate transportation		58		56		51
Other		86		72		69

	$	2,138	$	1,682	$	1,498


Gas Markets (in Bcf)
Gas sales		168		173		181
End user transportation		157		145		152

		325		318		333
Intermediate transportation		432		536		576

		757		854		909

Operation and maintenance expense increased $21 million in 2005 and $32 million in 2004. The 2005 increase is primarily due to the impact of the MPSC rate order that disallowed certain environmental expenses that had been recorded as a regulatory asset and its requirement to defer negative pension expense as a regulatory liability. For 2005, uncollectible accounts receivables expense remained consistent with 2004, reflecting higher past due amounts attributable to an increase in gas prices, continued weak economic conditions and inadequate government-sponsored assistance for low-income customers. The 2005 final rate order provided revenue for an uncollectible expense tracking mechanism to mitigate some of the effect of increasing uncollectible expense. The increase in operation and maintenance expense was partially offset by the DTE Energy parent company no longer allocating merger-related interest to MichCon effective in April 2005, as a result of the disallowance of those costs in the April 2005 final rate order. The increase was also partially offset by a decline in accruals for injuries and damages during 2005.

The 2004 period reflects higher reserves for uncollectible accounts receivable and pension and health care costs. The increase in uncollectible accounts expense reflects high past due amounts attributable to an increase in gas prices, continued weak economic conditions and a lack of adequate public assistance for low-income customers.

Asset (gains) and losses, net declined $7 million in 2005 as a result of a write-off of certain computer equipment and related depreciation resulting from the April 2005 final rate order.

Income taxes increased by $7 million in 2005 and decreased by $9 million in 2004 due to variations in pre-tax earnings.

Outlook – Operating results are expected to vary as a result of factors such as regulatory proceedings, weather, changes in economic conditions, cost containment efforts and process improvements. Higher gas prices and economic conditions have resulted in continued pressure on receivables and working capital requirements partially mitigated by the GCR mechanism. We believe our allowance for doubtful accounts is based on reasonable estimates. In the April 2005 final gas rate order, the MPSC adopted MichCon’s proposed tracking mechanism for uncollectible accounts receivable. Each year, MichCon will file an application comparing its actual uncollectible expense for the prior calendar year to its designated revenue recovery of approximately $37 million. Ninety percent of the difference will be refunded or surcharged after an annual reconciliation proceeding before the MPSC.

NON-UTILITY OPERATIONS

Power and Industrial Projects

Power and Industrial Projects is comprised of Coal-Based Fuels, On-Site Energy Projects, Non-Utility Power Generation, Landfill Gas Recovery and Waste Coal Recovery. Coal-Based Fuels operations include producing synthetic fuel from nine synfuel plants and producing coke from two coke battery plants. The production of synthetic fuel from all of our synfuel plants and the production of coke from one of our coke batteries generate production tax credits. On-Site Energy Projects include pulverized coal injection, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. Non-Utility Power Generation owns and operates four gas-fired peaking electric generating plants and manages and operates one additional gas-fired power plant under contract. Landfill Gas Recovery develops, owns and operates landfill recovery systems throughout the United States. Waste Coal Recovery uses proprietary technology to produce high quality coal products from fine coal slurries typically discarded from coal mining operations.

Factors impacting income: Net income increased $129 million in 2005 and decreased $18 million in 2004, compared to 2003. These results primarily reflect higher gains recognized from selling interests in our synfuel plants, gains and losses on synfuel hedges, and varying levels of production tax credits.


(in Millions)	2005			2004			2003
Operating Revenues	$	1,356		$	1,100		$	938
Operation and Maintenance		1,497			1,216			1,108
Depreciation and Amortization		107			89			90
Taxes other than Income		34			16			18
Asset (Gains) and Losses, Net		(368	)		(215	)		(114	)

Operating Income (Loss)		86			(6	)		(164	)
Other (Income) and Deductions		(30	)		(15	)		1
Minority Interest		(281	)		(212	)		(91	)
Income Taxes
Provision (Benefit)		144			80			(30	)
Production Tax Credits		(55	)		(38	)		(241	)

		89			42			(271	)

Net Income	$	308		$	179		$	197

Operating revenues increased $256 million in 2005 and $162 million in 2004 primarily reflecting higher synfuel sales due to increased production, and higher market prices for our coke production. Operating expenses associated with synfuel projects exceed operating revenues and therefore generate operating losses, which have been more than offset by the resulting production tax credits. When we sell an interest in a synfuel project, we recognize the gain from such sale as the facility produces and sells synfuel and

when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectibility is reasonably assured.

The improvement in 2004 synfuel revenues results from increased production due to additional sales of project interests in 2004, reflecting our strategy to produce synfuel primarily from plants in which we had sold interests in order to optimize income and cash flow.

Revenues from on-site energy projects increased in 2005, reflecting the addition of new facilities, completion of new long-term utility services contracts with a large automotive company and a large manufacturer of paper products. Revenues in 2004 include a $9 million pre-tax fee generated in conjunction with the development of a related energy project, 50% of which was sold to an unaffiliated partner.

Operation and maintenance expense increased $281 million in 2005 and $108 million in 2004, reflecting costs associated with increased synfuel production, 2005 acquisitions of three on-site energy projects and coke operations. Partially offsetting 2004 higher synfuel operating costs was the recording of insurance proceeds associated with an accident at one of our coke batteries.

Asset (gains) and losses, net increased $153 million in 2005 and $101 million in 2004. The improvements are due to increased production and sales volume from our synfuel projects. To economically hedge our exposure to the risk of an increase in oil prices that could reduce synfuel sales proceeds, we entered into derivative and other contracts. The derivative contracts are marked to market with changes in their fair value recorded as an adjustment to synfuel gains. We recorded 2005 synfuel hedge mark to market gains of $48 million, compared to 2004 mark to market losses of $12 million. See Note 12.

Minority interest increased $69 million in 2005 and $121 million in 2004, reflecting our partners’ share of operating losses associated with synfuel operations. The sale of interests in our synfuel facilities during prior periods resulted in allocating a larger percentage of such losses to our partners.

Income taxes increased $47 million in 2005 and $313 million in 2004. The increase in 2005 reflects higher taxable earnings, partially offset by higher production tax credits. The increase in 2004 reflects higher taxable earnings and a decline in the level of production tax credits due to the sale of interests in synfuel facilities.

Outlook - We may sell additional interests in our synfuel plants and take actions to protect our expected synfuel cash flows from the risk of an oil price-related phase-out. Synfuel-related tax credits expire on December 31, 2007.

In the third quarter of 2005, we executed an agreement to purchase five on-site energy projects and closed on three of the projects in 2005.

Power and Industrial Projects will continue leveraging its extensive energy-related operating experience and project management capability to develop and grow the on-site energy business. We expect solid earnings from our on-site energy business in 2006.

Production tax credits generated by our Coal-Based Fuels and Landfill Gas Recovery businesses are subject to the same phase out risk if domestic crude oil prices reach certain levels. See Note 13.

Unconventional Gas Production

Unconventional Gas Production is primarily engaged in natural gas exploration, development and production. Our Unconventional Gas Production business produces gas from the Antrim and Barnett shales and sells most of the gas to the Fuel Transportation and Marketing segment.

Factors impacting income: Net income decreased $2 million in 2005 and decreased $6 million in 2004. The decline in 2005 is due to higher operating and Michigan severance tax expenses. The decline in 2004 is due to increased interest costs and a gain that was recognized in 2003 as a result of a sale of a non-core asset.


(in Millions)	2005		2004		2003
Operating Revenues	$	74	$	71	$	70
Operation and Maintenance		30		27		22
Depreciation and Amortization		20		18		17
Taxes Other Than Income		11		7		7

Operating Income		13		19		24
Other (Income) and Deductions		8		10		7
Income Tax Provision		1		3		5

Net Income	$	4	$	6	$	12

Operating revenues increased $3 million in 2005 and increased $1 million in 2004 due primarily to higher gas prices.

Operations and maintenance expenses increased $3 million in 2005 and increased $5 million in 2004. Increases are associated with the addition of approximately 300 producing wells during the three year period. The 2004 increase is also due to a $6 million pretax gain on the sale of non-core assets recorded in 2003.

Taxes other than income increased $4 million in 2005 due to higher severance taxes associated with gas price increases.

Other (income) and deductions decreased $2 million in 2005 and increased $3 million in 2004. Interest expense was the primary contributor to the variances.

Outlook – We expect to continue to develop our proved areas, test unproved areas and prudently add new acreage in Michigan and Texas. During 2005 we increased our acreage holdings by 38,437 acres (24,852 net of the interest of others) in the Antrim and Barnett shales. Results from the Barnett shale test wells drilled during 2005 are expected during the first half of 2006. We expect to invest a combined amount of approximately $100 million to $130 million in our unconventional gas business in 2006.

Fuel Transportation and Marketing

Fuel Transportation and Marketing consists of DTE Energy Trading, Coal Transportation and Marketing and the Pipelines, Processing and Storage business.

DTE Energy Trading focuses on physical power and gas marketing, structured transactions, enhancement of returns from DTE Energy’s power plants and the optimization of contracted natural gas pipelines and storage capacity positions. Our customer base is predominantly utilities, local distribution companies, large industrials, and other marketing and trading companies. We enter into derivative financial instruments as part of our marketing and hedging activities. Most of the derivative financial instruments are accounted for under the mark-to-market method, which results in earnings recognition of unrealized gains and losses from changes in the fair value of the derivatives. We utilize forwards, futures, swaps and option contracts to mitigate risk associated with our marketing and trading activity as well as for proprietary trading within defined risk guidelines. DTE Energy Trading is integral in providing commodity risk management services to the other unregulated businesses within DTE Energy.

Coal Transportation and Marketing provides fuel, transportation and rail equipment management services. We specialize in minimizing fuel costs and maximizing reliability of supply for energy-intensive customers. Additionally, we participate in coal trading and coal-to-power tolling transactions, as well as the purchase and sale of emissions credits. We recently initiated a new business line, coal mine methane extraction, in which we recover methane gas from mine voids for processing and delivery to natural gas pipelines, industrial users, or for small power generation projects.

Pipelines, Processing and Storage has a partnership interest in an interstate transmission pipeline, seven carbon dioxide processing facilities and a natural gas storage field, as well as lease rights to another natural gas storage field. The assets of these businesses are well integrated with other DTE Energy operations.

Factors impacting income: Net income decreased $116 million in 2005, consisting primarily of a $131 million decline at DTE Energy Trading associated with mark-to-market losses on gas storage hedges. Net income increased $49 million in 2004, consisting primarily of a $47 million improvement at DTE Energy Trading. The comparability of results is impacted by a $74 million one-time pretax gain from a contract modification/termination recorded in the first quarter of 2004 and significant 2005 mark-to-market losses on derivative contracts used to economically hedge our gas in storage and forward power contracts.


(in Millions)	2005			2004			2003
Operating Revenues	$	1,684		$	1,254		$	1,061
Fuel, Purchased Power and Gas		970			473			643
Operation and Maintenance		710			596			334
Depreciation and Amortization		7			6			4
Taxes Other Than Income		3			4			2

Operating Income (Loss)		(6	)		175			78
Other (Income) and Deductions		(7	)		(7	)		(32	)
Income Tax Provision (Benefit)		(1	)		64			41

Net Income	$	2		$	118		$	69

Operating revenues increased $430 million in 2005 and increased $193 million in 2004. Both Coal Transportation and Marketing and DTE Energy Trading experienced revenue growth in 2005 due to higher demand, higher commodity pricing, the sale of emission credits and increased trading volume. Comparability of 2005 to 2004 is affected because our trading operations recorded an adjustment in 2004 that increased revenue by $86 million related to the modification of a future purchase commitment under a transportation agreement with an interstate pipeline company. See Note 13.

Coal Transportation and Marketing revenues in 2004 were affected by our strategy to produce synfuel primarily from plants in which we had sold interests. This strategy resulted in the reduction of synfuel

production levels. We were contractually obligated to supply coal to customers at certain sites that did not produce synfuel as a result of our production strategy. To meet our obligations to provide coal under long-term contracts with customers, we acquired coal that was resold to customers. The coal was sold at prices higher than the prices at which synfuel would have been sold to these customers.

Fuel, purchased power and gas increased $497 million in 2005 and decreased $170 million in 2004. During 2005, our earnings have been negatively impacted by the economically favorable decision in early 2005 to delay previously planned withdrawals from gas storage due to a decrease in the current price for natural gas and an increase in the forward price for natural gas. We anticipate the financial impact of this timing difference will reverse when the gas is withdrawn from storage in the current storage cycle and is sold at prices significantly in excess of the cost of gas in storage. In addition, we entered into forward power contracts to economically hedge certain physical and capacity power contracts. We expect the timing difference on the forward power contracts will be fully realized by the end of 2007.

In 2004, our trading operations recorded a gas inventory adjustment that increased expense by $12 million related to the termination of a long-term gas exchange agreement with an interstate pipeline company. See Note 13. Under the gas exchange agreement, we received gas from the customer during the summer injection period and redelivered the gas during the winter heating season.

Operation and maintenance expenses increased $114 million in 2005 and increased $262 million in 2004. During 2005, our Coal Transportation and Marketing business experienced higher throughput volumes and increased prices for coal. The increase in 2004 was due primarily to increased coal purchases and increased lease expense.

Other (income) and deductions for 2005 remained consistent with 2004, and decreased $25 million in 2004. The decline in 2004 is primarily due to gains recorded in 2003 from selling our 16% pipeline interest in the Portland Natural Gas Transmission System.

Income tax provision decreased $65 million in 2005 and increased $23 million in 2004 due to variations in earnings.

Outlook – We expect to continue to grow our Coal Services and DTE Energy Trading businesses in a manner consistent with, and complementary to, the growth of our other business segments. Gas storage and transportation capacity enhances our ability to provide reliable and custom-tailored bundled services to large-volume end users and utilities. This capacity, coupled with the synergies from DTE Energy’s other businesses, positions the segment to add value and mitigate risks.

We expect to continue to grow our Pipeline, Processing and Storage business by expanding existing assets and developing new assets. Pipelines, Processing and Storage received MPSC approval in September 2005 and executed long-term contracts for a capacity expansion at one of our Michigan storage fields that will facilitate an additional 14 Bcf of storage service sales starting in April 2006. Vector Pipeline has secured long-term market commitments to support an expansion project, for approximately 200 MMcf per day, with a projected in-service date of November 2007. Vector Pipeline expects to receive FERC approval in the second quarter of 2006. The Millennium Pipeline filed an application for FERC approval in August 2005. In addition, Pipeline, Processing and Storage owns a 10.5% interest in the Millennium Pipeline and is currently negotiating to increase its equity interest.

Significant portions of the Fuel Transportation and Marketing portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as capacity positions of natural gas storage and pipelines and power transmission contracts. The financial instruments are deemed derivatives, whereas the gas inventory, pipelines and storage assets are not derivatives. As a result, we will experience earnings volatility as derivatives are marked to market without revaluing the underlying non-derivative contracts and assets. The majority of such earnings volatility is associated with the natural gas storage cycle, which does not coincide with the calendar and fiscal year, but runs annually from April of one year to March of the next year. Our strategy is to economically hedge the price risk of storage with over-the-counter forwards and futures. Current accounting rules require the marking to market of forward

sales and futures, but do not allow for the marking to market of the related gas inventory. This results in gains and losses that are recognized in different interim and annual accounting periods. We generally anticipate the financial impact of this timing difference will reverse by the end of each storage cycle. See “Fair Value of Contracts” section that follows.

CORPORATE & OTHER

Corporate & Other includes various corporate support functions such as accounting, legal and information technology services. As these functions essentially support the entire Company, their costs are fully allocated to the various segments based on services utilized. Therefore the effect of the allocation on each segment can vary from year to year. Additionally, Corporate & Other holds certain non-utility debt, assets held for sale, and energy related investments.

Factors impacting income: Corporate & Other results declined $40 million in 2005, compared to a $53 million improvement in 2004. The 2005 decline was primarily a result of the parent company not allocating merger interest to Detroit Edison and MichCon. Partially offsetting 2005 increased expenses were reduced Michigan Single Business Taxes and gains on the sale of non-strategic assets. The 2004 improvement was affected by a $14 million net of tax gain from the sale of 3.5 million shares of Plug Power stock, as well as lower Michigan Single Business Taxes, resulting from tax saving initiatives. Corporate & Other also benefited from lower financing costs.

DISCONTINUED OPERATIONS

DTE Energy Technologies (Dtech) - We own Dtech, which assembles, markets, distributes and services distributed generation products, provides application engineering, and monitors and manages on-site generation system operations. In July 2005, management approved the restructuring of this business resulting in the identification of certain assets and liabilities to be sold or abandoned, primarily associated with standby and continuous duty operations. We recognized a net of tax restructuring loss of $23 million during the third quarter of 2005 primarily representing the write down to fair value of the assets of Dtech, less costs to sell, and the write-off of goodwill. As we execute the restructuring plan, there may be adjustments to amounts recorded related to the impairment and exit costs. We anticipate completing the restructuring plan by mid-2006.

Southern Missouri Gas Company - We owned Southern Missouri Gas Company (SMGC), a public utility engaged in the distribution, transmission and sale of natural gas in southern Missouri. In the first quarter of 2004, management approved the marketing of SMGC for sale. As of March 31, 2004, SMGC met the criteria of an asset “held for sale” and we have reported its operating results as a discontinued operation. We recognized a net of tax impairment loss of approximately $7 million, representing the write-down to fair value of the assets of SMGC, less costs to sell, and the write-off of allocated goodwill. In November 2004, we entered into a definitive agreement providing for the sale of SMGC. Regulatory approval was received in April 2005 and the sale closed in May 2005. During the second quarter of 2005, we recognized a net of tax gain of $2 million.

International Transmission Company - In February 2003, we sold International Transmission Company (ITC), our electric transmission business, to affiliates of Kohlberg Kravis Roberts & Co. and Trimaran Capital Partners, LLC. Through December 31, 2004, we recorded a gain of $58 million (net of tax). During the second quarter of 2005, the gain was adjusted to $56 million (net of tax).

See Note 3.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES

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

On January 1, 2003, we adopted new accounting rules for asset retirement obligations and energy trading activities. The cumulative effect of adopting these new accounting rules reduced 2003 earnings by $27 million.

See Note 2.

CAPITAL RESOURCES AND LIQUIDITY

DTE Energy and its subsidiaries require cash to operate and is provided by both internally and externally generated sources. We manage our liquidity and capital resources to maintain financial flexibility to meet our current and future cash flow needs.

Cash Requirements

We use cash to maintain and expand our electric and gas utilities and to grow our non-utility businesses, retire and pay interest on long-term debt and pay dividends. Our strategic direction anticipates base level capital investments and expenditures for existing businesses in 2006 of up to $1.2 billion. The capital needs of our utilities will increase due primarily to environmental related expenditures. We may spend an additional $200 million to $400 million on growth-related projects within our non-regulated businesses in 2006.

Capital spending for general corporate purposes will increase in 2006, primarily as a result of DTE2 and environmental spending. During 2005, we began the first wave of implementation of DTE2, an enterprise resource planning system initiative to improve existing processes and to implement new core information systems. We anticipate spending $165 million to $190 million over the next two years as the remaining system elements are developed and business segments fully adopt DTE2.

We anticipate environmental capital expenditures of approximately $250 million in 2006 and up to approximately $2.3 billion of future capital expenditures to satisfy both existing and proposed new requirements.

We expect non-utility capital spending will approximate $200 million to $400 million annually for the next several years. Capital spending for growth of existing or new businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria.

Debt maturing in 2006 totals approximately $682 million.

We believe that we will have sufficient internal and external capital resources to fund anticipated capital requirements.


(in Millions)	2005			2004			2003
Cash and Cash Equivalents
Cash Flow From (Used For)

Operating activities:
Net income	$	537		$	431		$	521
Depreciation, depletion and amortization		872			744			691
Deferred income taxes		147			129			(220	)
Gain on sale of ITC, synfuel and other assets, net		(405	)		(236	)		(228	)
Working capital and other		(150	)		(73	)		186

		1,001			995			950

Investing activities:
Plant and equipment expenditures – utility		(850	)		(815	)		(679	)
Plant and equipment expenditures – non-utility		(215	)		(89	)		(72	)
Business acquisitions, net of cash acquired		(50	)		—			—
Proceeds from sale of ITC, synfuels and other assets, net of cash divested		409			325			758
Restricted cash and other investments		(96	)		(102	)		3

		(802	)		(681	)		10

Financing activities:
Issuance of long-term debt and common stock		1,041			777			571
Redemption of long-term debt		(1,266	)		(759	)		(1,208	)
Short-term borrowings, net		437			33			(44	)
Repurchase of common stock		(13	)		—			—
Dividends on common stock and other		(366	)		(363	)		(358	)

		(167	)		(312	)		(1,039	)

Net Increase (Decrease) in Cash and Cash Equivalents	$	32		$	2		$	(79	)

Cash from Operating Activities

A majority of the Company’s operating cash flow is provided by our two utilities, which are significantly influenced by factors such as weather, electric Customer Choice, regulatory deferrals, regulatory outcomes, economic conditions and operating costs.

Our non-utility businesses also provide sources of cash flow to the enterprise and reflect a range of operating profiles. The profiles vary from our synthetic fuels business, which we believe will provide approximately $1.2 billion of cash during 2006-2008 (assuming no phase-out), to new startups. These new start-ups include our unconventional gas and waste coal recovery businesses, which we are growing and, if successful, could require significant investment.

Cash from operations totaling $1.001 billion in 2005 was up $6 million from the comparable 2004 period. The operating cash flow comparison reflects an increase of over $83 million in net income, after adjusting for non-cash items (depreciation, depletion, amortization, deferred taxes and gains), substantially offset by a $77 million increase in working capital and other requirements. Most of the improvement was driven by higher net income at Detroit Edison which was the result of improved revenues and gross margin stemming from higher rates granted in the 2004 rate orders, warmer weather, and lower customer choice penetration. The offsetting increase in working capital requirements was driven by a $127 million PSCR under-recovery in 2005 as compared to a $112 million over-recovery in 2004. Working capital requirements also reflect the higher cost of gas at MichCon and our Fuel Transportation and Marketing segment. MichCon’s working capital and other requirements were $136 million higher in 2005 compared to 2004 primarily due to the impact of higher gas costs. This impact was reflected by accounts receivable balances that were $198 million higher at December 31, 2005 than the previous year at MichCon. The increase in working capital requirements was mitigated by lower income tax payments in 2005 and

company initiatives to improve cash flow, including better inventory management, cash sales transactions and the utilization of letters of credit.

Our net operating cash flow in 2004 was $995 million, reflecting a $45 million increase from 2003. The operating cash flow comparison reflects an increase of over $300 million in net income, after adjusting for non-cash items (depreciation, depletion, amortization, deferred taxes and gains), substantially offset by a $259 million increase in working capital and other requirements. A portion of this improvement is attributable to the change in our strategy to primarily produce synfuel from plants in which we have sold interests. As previously discussed, synfuel projects generate operating losses, which have been more than offset by tax credits that we have been unable to fully utilize, thereby negatively affecting operating cash flow. Cash for working capital primarily reflects higher income tax payments of $172 million in 2004, reflecting a different payment pattern of taxes in 2004 compared to 2003. The increase in working capital was mitigated by Company initiatives to improve cash flow, including better inventory management, cash sales transactions, deferral of retirement plan contributions and the utilization of letters of credit. Certain cash initiatives in 2003 lowered cash flow in 2004.

Outlook – We expect cash flow from operations to increase over the long-term primarily due to improvements from utility rate increases and the sales of interests in our synfuel projects, partially offset by higher cash requirements on environmental and other utility capital as well as growth investments in our non-utility portfolio. We are likely to incur costs associated with implementation of our Performance Excellence Process, but we expect to realize long term cost savings. We also may be impacted by the delayed collection of underrecoveries of our PSCR and GCR costs and electric and gas accounts receivable as a result of recent MPSC orders. Gas prices are likely to be a source of volatility with regard to working capital requirements for the foreseeable future. We are continuing our efforts to identify opportunities to improve cash flow through working capital improvement initiatives.

Operating cash flow from our utilities is expected to increase in 2006. Due to the structure of the interim and final rate orders, we will begin to realize the full benefits of interim and final rate relief in 2006 when all customer rate caps expire. Improvements in cash flow from our utilities are also expected from better management of our working capital requirements, including the continued focus on reducing past due accounts receivable. Our emphasis in these businesses will continue to be cash generation and conservation.

Assuming no production tax credit phase-out, cash flows from our synfuel business are expected to be approximately $400 million, $500 million and $300 million in 2006, 2007 and 2008, respectively, including $300 million tax credit carryforward utilization by DTE Energy. The redeployment of this cash represents a unique opportunity to increase shareholder value and strengthen our balance sheet. We expect to use this cash to reduce debt, to continue to pursue growth investments that meet our strict risk-return and value creation criteria and to potentially repurchase common stock if adequate investment opportunities are not available. Our objectives for cash redeployment are to strengthen the balance sheet and coverage ratios to improve our current credit rating and outlook, and to replace the value of synfuel operations currently inherent in our share price. However, if oil prices remain at current levels or increase throughout 2006, the expected cash flow from the synfuel business would be less and could adversely impact the success of this strategy, unless the Company identifies alternative sources of cash. Synfuel cash flow consists of variable and fixed payments from partners, proceeds from option and other contracts used to protect us from risk of loss from a tax credit phase-out and the use of prior years’ tax credit carry-forwards. Since 2004, we have spent approximately $105 million hedging our future synfuel cash flow and may spend up to $50 million in 2006.

Our other operating non-utility businesses are expected to contribute approximately $500 million through 2008. Remaining start-up businesses such as unconventional gas production, waste coal recovery and distributed generation will continue to use cash in excess of their cash generation over the next couple of years while they are being further developed. Certain of the previously discussed cash initiatives resulted in accelerating the receipt of cash in 2005, which will have the impact of lowering cash flow in 2006.

Cash from Investing Activities

Cash inflows associated with investing activities are primarily generated from the sale of assets. In any given year, we will look to realize cash from under-performing or non-strategic assets. Capital spending within the utility business is primarily to maintain our generation and distribution infrastructure, comply with environmental regulations and gas pipeline replacements. Capital spending within our non-utility businesses is for ongoing maintenance and expansion. The balance of non-utility spending is for growth, which we manage very carefully. We look to make investments that meet strict criteria in terms of strategy, management skills, risks and returns. All new investments are analyzed for their rates of return and cash payback on a risk adjusted basis. We have been disciplined in how we deploy capital and will not make investments unless they meet our criteria. For new business lines, we invest tentatively based on research and analysis. We start with a limited investment, we evaluate results and either expand or exit the business based on those results. In any given year, the amount of growth capital will be determined by the underlying cash flows of the Company with a clear understanding of any potential impact on our credit ratings.

Net cash outflows relating to investing activities increased $121 million in 2005 and $691 million in 2004, compared to the prior year. The 2005 change was primarily due to increased capital expenditures, partially offset by higher synfuel proceeds. Spending on growth project investments increased $123 million in 2005 while spending on environmental projects was $44 million higher than the 2004 period. The 2004 change was primarily due to proceeds received in 2003 totaling $758 million from the sale of ITC, interests in three synfuel projects and non-strategic assets. Additionally, the change was due to variations in cash contractually designated for debt service.

Longer term, with the expected improvement at our utilities and assuming continued cash generation from the synfuel business, cash flows are expected to improve. We will continue to pursue opportunities to grow our businesses in a disciplined fashion if we can find opportunities that meet our strategic, financial and risk criteria.

Cash from Financing Activities

We rely on both short-term borrowing and long-term financing as a source of funding for our capital requirements not satisfied by the Company’s operations. Short-term borrowings, which are mostly in the form of commercial paper borrowings, provide us with the liquidity needed on a daily basis. Our commercial paper program is supported by our unsecured credit facilities.

Our strategy is to have a targeted debt portfolio blend as to fixed and variable interest rates and maturity. We continually evaluate our leverage target, which is currently 50% or lower, to ensure it is consistent with our objective to have a strong investment grade debt rating. We have completed a number of refinancings with the effect of extending the average maturity of our long-term debt and strengthening our balance sheet. The extension of the average maturity was accomplished at interest rates that lowered our debt costs.

Net cash used for financing activities improved $145 million in 2005 and improved $727 million in 2004, compared to the prior periods. The improvement in 2005 was primarily driven by the issuance of common stock which resulted from the conversion of our equity security units. The change in 2004 was primarily due to higher issuances of long-term debt and levels of short-term debt borrowings which exceeded the requirements of long-term debt redemptions.

See Note 9 – Long-Term Debt and Preferred Securities and Note 10 – Short-Term Credit Arrangements and Borrowings for more information regarding financing activities.

Amounts available under shelf registrations include $500 million at DTE Energy, $250 million at Detroit Edison and $200 million at MichCon. In 2006, we plan on filing new shelf registration statements for DTE Energy and Detroit Edison.

Common stock issuances or repurchases can also be a source or use of cash. In January 2005, we announced that the DTE Energy Board of Directors has authorized the repurchase of up to $700 million in common stock through 2008. The authorization provides Company management with flexibility to pursue share repurchases from time to time, and will depend on future cash flows and investment opportunities. No share repurchases were made in 2005. As of January 1, 2005, we discontinued issuing new DTE Energy shares for our dividend reinvestment plan, which generated approximately $50 million annually. We also contributed $170 million of DTE Energy common stock to our pension plan in the first quarter of 2004. In August 2005, we issued 3.7 million shares of common stock in conjunction with the settlement of the stock purchase component of our equity security units.

Contractual Obligations

The following table details our contractual obligations for debt redemptions, leases, purchase obligations and other long-term obligations as of December 31, 2005:

Less

(in Millions)

Than

After

Contractual Obligations

Total

1 Year

1-3 Years

4-5 Years

5 Years

Long-term debt:


			PAGE
Definitions				1
Forward-Looking Statements				3
Part I
	Items 1., 1A. & 2.	Business, Company Risk Factors and Properties		4
	Item 3.	Legal Proceedings		25
	Item 4.	Submission of Matters to a Vote of Security Holders		25
Part II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		26
	Item 6.	Selected Financial Data		27
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		28
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		63
	Item 8.	Financial Statements and Supplementary Data		66
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		121
	Item 9A.	Controls and Procedures		121
	Item 9B.	Other Information		122
Part III
	Item 10.	Directors and Executive Officers of the Registrant		122
	Item 11.	Executive Compensation		122
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		122
	Item 13.	Certain Relationships and Related Transactions		122
	Item 14.	Principal Accountant Fees and Services		122
Part IV
	Item 15.	Exhibits and Financial Statement Schedules		122
Signatures				128
Second Amendment to the Executive Supplemental Retirement Plan
First Amendment to the Executive Deferred Compensation Plan
Computation of Ratio of Earnings to Fixed Charges
Subsidiaries of the Company
Consent of Deloitte & Touche LLP
Chief Executive Officer Section 302
Chief Financial Officer Section 302
Chief Executive Officer Section 906
Chief Financial Officer Section 906