Edgar Filing: DTE ENERGY CO

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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
ACT OF 1934


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


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

For the fiscal year ended December 31, 2007

Commission file number 1-11607

DTE ENERGY COMPANY

(Exact name of registrant as specified in its charter)


Michigan		38-3217752
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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

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

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


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 Stock Exchange 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. o

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


Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller Reporting Company o

(Do not check if a smaller reporting company)

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

On June 29, 2007, the aggregate market value of the Registrant’s voting and non-voting common equity held by non-affiliates was approximately $8.2 billion (based on the New York Stock Exchange closing price on such date). There were 163,229,692 shares of common stock outstanding at January 31, 2008.

Certain information in DTE Energy Company’s definitive Proxy Statement for its 2008 Annual Meeting of Common Shareholders to be held May 15, 2008, 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.

DTE Energy Company
Annual Report on Form 10-K
Year Ended December 31, 2007
TABLE OF CONTENTS


		PAGE
Definitions			1

Forward-Looking Statements			3

Part I
Items 1., 1A., 1B. & 2.	Business, Risk Factors, Unresolved Staff Comments and Properties		5

Item 3.	Legal Proceedings		27

Item 4.	Submission of Matters to a Vote of Security Holders		27

Part II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		28

Item 6.	Selected Financial Data		30

Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations		30

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		66

Item 8.	Financial Statements and Supplementary Data		69

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		138

Item 9A.	Controls and Procedures		138

Item 9B.	Other Information		138

Part III
Item 10.	Directors, Executive Officers and Corporate Governance		138

Item 11.	Executive Compensation		138

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		138

Item 13.	Certain Relationships and Related Transactions, and Director Independence		138

Item 14.	Principal Accountant Fees and Services		138
Part IV
Item 15.	Exhibits and Financial Statement Schedules		139

Signatures			145
First Amendment DTE Energy Company 2006 Long-Term Incentive Plan
Second Amendment DTE Energy Company 2006 Long-Term Incentive Plan
Computation of Ratio of Earnings to Fixed Charges
Subsidiaries of the Company
Consent of Deloitte & Touche LLP
Chief Executive Officer Section 302 Certification
Chief Financial Officer Section 302 Certification
Chief Executive Officer Section 906 Certification
Chief Financial Officer Section 906 Certification
Sixteenth Amendment to Master Trust Agreement
Eighteenth Amendment to Master Trust
Nineteenth Amendment to Master Trust

DEFINITIONS


Company		DTE Energy Company and any subsidiary companies

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

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

FASB		Financial Accounting Standards Board

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)

MDEQ		Michigan Department of Environmental Quality

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

MISO		Midwest Independent System Operator, a Regional Transmission Organization

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.

Production tax credits		Tax credits as authorized under Sections 45K and 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.

Subsidiaries		The direct and indirect subsidiaries of DTE Energy Company

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 through December 31, 2007 generated 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.

GWh		Gigawatthour of electricity

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 or the potential requirement to refund proceeds received from synfuel partners;

	•		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, including potential new federal and state requirements that could include carbon and more stringent mercury emission controls, a renewable portfolio standard and energy efficiency mandates;

	•		nuclear regulations and operations associated with nuclear facilities;

	•		impact of electric and gas utility restructuring in Michigan, including legislative amendments and Customer Choice programs;

	•		employee relations and the impact of collective bargaining agreements;

	•		unplanned outages;

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

	•		the timing and extent of changes in interest rates;

	•		the level of borrowings;

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

	•		effects of competition;

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

	•		contributions to earnings by non-utility subsidiaries;

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

	•		the ability to recover costs through rate increases;

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

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

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

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

	•		amounts of uncollectible accounts receivable;

	•		binding arbitration, litigation and related appeals;

	•		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; and

	•		timing, terms and proceeds from any asset sale or monetization.

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

Part I

Items 1. and 2. Business 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 four non-utility segments that are engaged in a variety of energy related businesses.

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 four non-utility segments are involved in 1) coal transportation and marketing, gas pipelines processing and storage; 2) unconventional gas project development and production; 3) power and industrial projects; and 4) energy marketing and trading operations.

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, 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). Our previously filed reports and statements are also available at the SEC’s website: www.sec.gov.

The Company’s Code of Ethics and Standards of Behavior, Board of Directors Mission and Guidelines, Board Committee Charters, and Categorical Standards of Director Independence are also posted on its website. The information on the Company’s website is not part of this or any other report that the Company files with, or furnishes to, the SEC.

Additionally, the public may read and copy any materials the Company files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov.

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

Corporate Structure

Based on the following structure, we set strategic goals, allocate resources, and evaluate performance. See Note 19 of the Notes to Consolidated Financial Statements in Item 8 of this Report for financial information by segment for the last three years.

Electric Utility

•

Consists of Detroit Edison, our 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, transports 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 to approximately 17,000 customers.

Non-Utility Operations

	•		Coal and Gas Midstream, primarily consisting of coal transportation and marketing, and gas pipelines, processing and storage;

	•		Unconventional Gas Production, primarily consisting of unconventional gas project development and production;

	•		Power and Industrial Projects, primarily consisting of on-site energy services, steel-related projects and power generation with services; and

	•		Energy Trading, primarily consisting of energy marketing and trading operations.

Corporate & Other, primarily consisting of corporate staff functions that are fully allocated to the various segments based on services utilized. Additionally, Corporate & Other holds certain non-utility debt and energy-related investments.

Refer to our Management’s Discussion and Analysis in Item 7 of this Report 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. Our generating plants are regulated by numerous federal and state governmental agencies, including, but not limited to, the MPSC, the FERC, the NRC, the EPA and the MDEQ. Electricity is generated from our several fossil plants, a hydroelectric pumped storage plant and a nuclear plant, and is purchased from electricity generators, suppliers and wholesalers.

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

Revenue by Service


(in Millions)	2007		2006		2005
Residential	$	1,739	$	1,671	$	1,517
Commercial		1,723		1,603		1,331
Industrial		854		835		697
Wholesale		125		109		73
Other		259		350		464

Subtotal		4,700		4,568		4,082
Interconnection sales (1)		200		169		380

Total Revenue	$	4,900	$	4,737	$	4,462


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

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

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

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

Fuel Supply and Purchased Power

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

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

Properties

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

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


	Location by	Summer Net
	Michigan	Rated Capability (1) (2)
Plant Name	County	(MW)		(%)		Year in Service
Fossil-fueled Steam-Electric
Belle River (3)	St. Clair		1,026		9.3	1984 and 1985
Conners Creek	Wayne		230		2.1	1951
Greenwood	St. Clair		785		7.1	1979
Harbor Beach	Huron		103		0.9	1968
Monroe (4)	Monroe		3,115		28.3	1971, 1973 and 1974
River Rouge	Wayne		523		4.8	1957 and 1958
St. Clair	St. Clair		1,368		12.4	1953, 1954, 1959, 1961 and 1969
Trenton Channel	Wayne		730		6.6	1949 and 1968

			7,880		71.5
Oil or Gas-fueled Peaking Units	Various		1,101		10.0	1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric Fermi 2 (5)	Monroe		1,122		10.2	1988
Hydroelectric Pumped Storage Ludington (6)	Mason		917		8.3	1973

			11,020		100.0


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

(2)		Excludes one oil-fueled unit, St. Clair Unit No. 5 (250 MW), and one coal-fired unit, Marysville (84 MW), in cold standby status.

(3)		The Belle River capability represents Detroit Edison’s entitlement to 81.39% of the capacity and energy of the plant. See Note 7 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.

(4)		The Monroe Power Plant provided 39% of Detroit Edison’s total 2007 power plant generation.

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

(6)		Represents Detroit Edison’s 49% interest in Ludington with a total capability of 1,872 MW. See Note 7 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.

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

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

Electric Distribution


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

		30,697		15,023

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

Regulation

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

See Note 5 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Energy Assistance Programs

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

Strategy and Competition

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

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

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

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

GAS UTILITY

Description

Our Gas Utility segment consists of MichCon and Citizens.

Revenue is generated by providing the following major classes of service: gas sales, end user transportation, intermediate transportation, and gas storage.

Revenue by Service


(in Millions)	2007		2006		2005
Gas sales	$	1,536	$	1,541	$	1,860
End user transportation		140		135		134
Intermediate transportation		59		69		58
Storage and other		140		104		86

Total Revenue	$	1,875	$	1,849	$	2,138

•		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.

•		Storage and other — Includes revenues from gas storage, providing appliance maintenance, facility development 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 72% of the volume coming from underground storage for 2007. Peak-use requirements are met through utilization of our storage facilities, pipeline transportation capacity, and purchased gas supplies. 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 NYMEX and 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 19,000 miles of distribution mains, approximately 1,193,000 service lines and approximately 1,316,000 active meters. We own approximately 2,400 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 129 Bcf. These facilities are important in providing reliable and cost-effective service to our customers. In addition, we sell storage services to third parties. Most of our distribution and transmission property is located on property owned by others and used by us 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.

Our 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		51		2010
TransCanada PipeLines Limited		53		2010
Great Lakes Gas Transmission L.P.		30		2011
ANR Pipeline Company		245		2011
Vector Pipeline L.P.		50		2012

We own 831 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 14 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

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.

See Note 5 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.

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 be 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 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 for end user transportation 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 storage capacity.

Our extensive transmission pipeline system has enabled us to market 500 to 600 Bcf annually for intermediate transportation services and storage 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 Canada.

MichCon’s storage capacity is used to store natural gas for delivery to MichCon’s customers as well as sold to third parties, under a variety of arrangements for periods up to 3 years. Prices for storage arrangements for shorter periods are generally higher, but more volatile than for longer periods. Prices are influenced primarily by market conditions and natural gas pricing.

NON-UTILITY OPERATIONS

Coal and Gas Midstream

Description

Coal and Gas Midstream primarily consists of the operations of Coal Transportation and Marketing and the Pipelines, Processing and Storage businesses.

Coal Transportation and Marketing

Coal Transportation and Marketing provides fuel, transportation, storage, blending and rail equipment management services. 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 marketing and trading and coal-to-power tolling transactions, as well as the purchase and sale of emissions credits. We perform 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.


(in Millions)	2007		2006		2005
Tons of Coal Shipped (1)		35		34		42


(1)		Includes intercompany transactions of 19 million, 14 million, and 20 million tons in 2007, 2006, and 2005, respectively.

Pipelines, Processing and Storage

The Pipelines, Processing and Storage business owns a partnership interest in two interstate transmission pipelines, four carbon dioxide processing facilities, and two natural gas storage fields. The pipeline and storage assets are primarily supported by stable, long-term, fixed-price revenue contracts. We have a partnership interest in Vector Pipeline (Vector), an interstate transmission pipeline, which connects Michigan to Chicago and Ontario. We have storage assets in Michigan capable of storing up to 80 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 centers.

Properties

The Pipelines, Processing and Storage business holds the following property:


Property Classification	% Owned	Description	Location
Pipelines
Vector Pipeline	40%	348-mile pipeline with 1,200 MMcf per day capacity	Midwest

Millennium Pipeline (under construction during 2008)	26%	182-mile pipeline with 525 MMcf per day capacity	New York

Processing Plants	100%	197 MMcf per day capacity	Northern Michigan

Storage
Washington 28	50%	14 Bcf of storage capacity	Washington Twp, MI
Washington 10	100%	66 Bcf of storage capacity	Washington Twp, MI

The assets of these businesses are well integrated with other DTE Energy operations. Pursuant to an operating agreement, MichCon provides physical operations, maintenance, and technical support for the Washington 28 and Washington 10 storage facilities.

Strategy and Competition

Our Coal Transportation and Marketing business is one of the leading North American coal marketers. We have a 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. A portion of our Coal Transportation and Marketing revenues and net income were dependent upon our Synfuel operations that ceased at the end of 2007. We will seek to build our capacity to transport greater amounts of western coal and we have expanded our coal storage and blending capacity with the start of commercial operation of our coal terminal in Chicago in April 2007. Beyond 2008, we expect to continue to grow our Coal Transportation and Marketing business in a manner consistent with, and complementary to, the growth of our other business segments.

Our Pipeline, Processing and Storage business expects to continue its steady growth plan. The Pipelines, Processing and Storage business 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. We forecast these regions will require incremental 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 facilities. In April 2007, Washington 28 received MPSC approval to increase working gas storage capacity by over 6 Bcf to a total of 16 Bcf, which will be phased in over

the next two years. In June 2007, Washington 10 received MPSC approval to develop the Shelby 2 storage field which will increase the working gas storage capacity of Washington 10 over the next two years by 8 Bcf to a total of 74 Bcf. In November 2007, Vector Pipeline placed into service its 200 MMcf per day Phase I capacity expansion which consisted of two additional compressor stations. This expansion is fully subscribed by customers, under long-term, fixed-price contracts. In addition, Vector Pipeline requested permission from the FERC in the fourth quarter of 2007 to build one more compressor station and to expand the Vector Pipeline by approximately 100 MMcf/d to 1.3 Bcf/d, with a proposed in-service date of November 1, 2009. Pipeline, Processing and Storage has a 26 percent ownership interest in Millennium Pipeline that received FERC approval for construction and operation in December 2006. Millennium Pipeline commenced construction in June 2007 and is scheduled to be in service in late 2008. We plan to expand existing assets and develop new assets that are typically supported with long-term customer commitments.

Unconventional Gas Production

Description

Our Unconventional Gas Production business is engaged in natural gas exploration, development and production primarily within the Barnett shale in north Texas. On June 29, 2007, we sold our Antrim shale gas exploration and production business in the northern lower peninsula of Michigan for gross proceeds of $1.262 billion. On January 15, 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $250 million, subject to standard post-closing adjustments. The properties in the 2008 sale include 186 Bcfe of proved and probable reserves on approximately 11,000 net acres in the core area of the Barnett shale.

In 2007, we added proved reserves of 48 Bcfe in the Barnett shale (15 Bcfe of which is classified as held for sale), resulting in year-end total proved reserves of 219 Bcfe, of which 75 Bcfe were sold in January 2008. The Barnett shale wells yielded 7.7 Bcfe of production in 2007. Barnett shale leasehold acres increased to 63,541 gross acres (58,742 net of interest of others), after adjustment for the January 2008 sale. We drilled a total of 54 wells (50 net of interest of others) in the Barnett shale acreage with a success rate of 100% in 2007. Included were five test wells (4.8 net of interest of others) in unproved areas of the southern and western portions of our Barnett shale acreage holdings. While we do not expect further investment in the southern portion of the Barnett shale, development of our Barnett western acreage is ongoing and will continue in 2008.

Properties

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


	2007				2006				2005
	Gross		Net (1)		Gross		Net (1)		Gross		Net (1)
Producing Wells and Acreage Producing Wells (2) (6)
Barnett shale (3)		120		120		83		83		47		47
Core shale held for sale		53		33		41		27		18		8

		173		153		124		110		65		55


Developed Lease Acreage (4) (6)
Barnett shale (3)		9,922		9,880		10,759		10,693		13,018		13,018
Core shale held for sale		7,379		4,987		5,679		3,977		2,506		1,349

		17,301		14,867		16,438		14,670		15,524		14,367


Undeveloped Lease Acreage (5) (6)
Barnett shale (3)		38,793		38,066		30,649		27,613		13,839		13,495
Core shale held for sale		7,447		5,809		7,073		6,164		9,639		7,801

		46,240		43,875		37,722		33,777		23,478		21,296


(1)		Excludes the interest of others.

(2)		Producing wells are the number of wells that are found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

(3)		Excludes Core portion of Barnett shale classified as held for sale.

(4)		Developed lease acreage is the number of acres that are allocated or assignable to productive wells or wells capable of production.

(5)		Undeveloped lease acreage is the number of acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

(6)		Excludes sold and impaired properties in the southern expansion area of the Barnett shale.

Strategy and Competition

We manage and operate our 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.

Long-term fixed price obligation data for the next three years follows:


	2008		2009		2010
Long-term fixed price obligations

Barnett
Volume- Bcf		2.3		2.0		1.2
Price- $/Mcf	$	7.70	$	7.42	$	7.16

We plan to retain our holdings in the Western portion of the Barnett shale and anticipate significant opportunities to develop our current position while accumulating additional acreage in and around our existing assets.

Current natural gas prices and successes within the Barnett shale are resulting in additional capital being invested into the area. The competition for goods and services may result in increased operating costs. However, our experienced Barnett shale personnel provide an advantage in addressing potential cost increases. We invested approximately $140 million in the Barnett shale in 2007.

In 2008, we expect to drill approximately 30 to 40 wells in the Barnett shale. Investment for the area is expected to be approximately $90 million to $100 million during 2008. Successful testing on unproved acreage may yield additional significant investment opportunities.

Power and Industrial Projects

Description

Power and Industrial Projects is comprised primarily of projects that deliver utility-type services to industrial, commercial and institutional customers, and biomass energy projects. This segment provides utility-type services using project assets usually located on the customers’ premises in the steel, automotive, pulp and paper, airport and other industries. These services include pulverized coal and petroleum coke supply, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. At December 31, 2007, this segment owned and operated one gas-fired peaking electric generating plant and a biomass-fired electric generating plant and operated one coal-fired power plant under contract. This segment develops, owns and operates landfill gas recovery systems throughout the United States. In addition, this segment produces metallurgical coke from two coke batteries. The production of coke from these coke batteries generates production tax credits.

We expect to sell a 50 percent interest in a portfolio of select Power and Industrial Projects. In addition to the proceeds that the Company will receive from the sale of the 50 percent equity interest, the company that will own the Projects will obtain debt financing and the proceeds will be distributed to DTE Energy immediately prior to the sale of the equity interest. The total gross proceeds the Company will receive are expected to approximate $650 million. The Company expects to complete the transaction in the first half of 2008. This timing, however, is highly dependent on availability of acceptable financing terms in the credit markets. As a result, the Company cannot predict the timing with certainty. The Company expects to recognize a gain upon completion of the transaction. In conjunction with the sale, the Company will enter into a management services agreement to manage the day-to-day operations of the Projects and to act as the managing member of the company that owns the Projects. We plan to account for our 50 percent ownership interest in the company that will own the portfolio of projects using the equity method. See Note 3 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

In July 2007, we sold Georgetown, an 80 MW natural gas-fired peaking electric generating plant for approximately $23 million, which approximated our carrying value. In October 2007, we sold our 50 percent interest in Crete, a 320 MW natural gas-fired peaking electric generating plant for approximately $37 million, and recognized a pre-tax gain of approximately $8 million ($5 million after-tax). See Note 3 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Properties

The following are significant Power and Industrial Projects:


Facility	Location	% Owned			Service Type

Steel
DTE PCI Enterprises Company	River Rouge, MI		100	%		(1	)	Pulverized Coal
DTE Sparrows Point	Sparrows Point, MD		100	%		(1	)	Pulverized Coal
EES Coke Battery, LLC	River Rouge, MI		100	%		(1	)	Metallurgical Coke Supply
Indiana Harbor Coke Co., LP	East Chicago, IN		5	%		(1	)	Metallurgical Coke Supply

Automotive
DTE Energy Center	Various sites in MI, IN, OH		50	%				Electric Distribution, Chilled Water, Waste Water, Compressed Air, Mist and Dust Collectors
DTE Northwind	Detroit, MI		100	%		(1	)	Steam and Chilled Water
DTE Moraine	Moraine, OH		100	%		(1	)	Compressed Air
DTE Tonawanda	Tonawanda, NY		100	%		(1	)	Chilled and Waste Water
DTE Defiance	Defiance, OH		100	%		(1	)	Steam, Cooling Tower Water, Chilled Water, Compressed Air
DTE Heritage	Dearborn, MI		100	%		(1	)	Electric Distribution
DTE Dearborn	Dearborn, MI		100	%				Steam, Chilled Water, Compressed Air, Waste Water
DTE Pontiac North	Pontiac, MI		100	%		(1	)	Electric Generation and Steam
DTE Lordstown	Lordstown, OH		100	%		(1	)	Steam, Chilled Water, Compressed Air and Reverse Osmosis Water

Pulp and Paper
Mobile Energy Services	Mobile, AL		50	%				Electric Generation and Steam

Airport
Metro Energy	Romulus, MI		100	%		(1	)	Electricity, Hot and Chilled Water
DTE Pittsburgh	Pittsburgh, PA		100	%		(1	)	Hot and Chilled Water

Other Industries
DTE PetCoke	Vicksburg, MS		100	%				Pulverized Petroleum Coke


(1)		Classified as held for sale at December 31, 2007.

Pursuant to an operating agreement with DTE PCI Enterprises Company, Detroit Edison provides operations and maintenance services for the pulverized coal facility located at Detroit Edison’s River Rouge power plant.

Production tax credits related to one coke battery that expired in 2002 were reinstated for the years 2006 through 2009. The coke battery facilities produce coke that is used in blast furnaces within the steel industry.


(in Millions)	2007		2006		2005
Production Tax Credits Generated
Allocated to DTE Energy	$	5	$	6	$	2

Non-Utility Power Generation

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


					Capacity
Facility (1)	Location	% Owned			(in MW)
\| \| \|
DTE East China	East China Twp, MI		100	%		320
Woodland Biomass	Woodland, CA		99	%		25

						345


(1)		Excludes DTE River Rouge (240 MW), no longer in service effective September 2006.

Production tax credits are available at one Non-Utility Power Generation facility. The facility produces electricity using renewable resources.


(in Millions)	2007		2006		2005
Production Tax Credits Generated
Allocated to DTE Energy	$	2	$	1	$	—

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 provide local utilities, industry and consumers with an opportunity to use a competitive, renewable source of energy, in addition to providing environmental benefits by reducing greenhouse gas emissions. We also co-own, with the Coal Transportation and Marketing segment, a coal mine methane gathering system and gas processing facility in southern Illinois. This processed methane is sold into the natural gas transmission system. Many of our facilities generated production tax credits that expired at the end of 2007.


(Dollars in Millions)	2007		2006		2005
Landfill Sites		28		26		32
Gas Produced (in Bcf)		23.5		22.9		20.2
Tax Credits Generated (1)	$	3	$	5	$	8


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

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 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:

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

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

	•		Expanding energy projects.

Energy Trading

Description

Energy Trading focuses on physical power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, the optimization of contracted natural gas pipelines and storage, and power transmission and generating capacity positions. Our customer base is predominantly utilities, local distribution companies, pipelines, 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. Energy Trading also provides commodity risk management services to the other businesses within DTE Energy.

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 contracted natural gas pipelines and storage and power generation capacity positions. Most financial instruments are deemed derivatives, whereas the gas inventory, power transmission, pipelines and storage assets are not derivatives. As a result, this segment may experience 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 may incur mark-to-market accounting gains or losses in one period that could reverse in subsequent periods.

Strategy and Competition

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.

CORPORATE & OTHER

Description

Corporate & Other includes various corporate staff functions. Because these functions 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 and energy-related investments.

Strategy and Competition

Our energy-related investment strategy is to create a profitable portfolio by investing in companies or funds that facilitate the creation of new businesses, expand growth opportunities for existing businesses or enable performance improvements in our existing businesses.

DISCONTINUED OPERATIONS

Synthetic Fuel

Description

The Synthetic Fuel business was presented as a non-utility segment through the third quarter of 2007. Due to the expiration of synfuel production tax credits at the end of 2007, the Synthetic Fuel business ceased operations and has been classified as a discontinued operation as of December 31, 2007. Synfuel plants chemically changed coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits were provided for the production and sale of solid synthetic fuel produced from coal and were available through December 31, 2007. To optimize income and cash flow from the synfuel operations, we had sold interests in all nine of the facilities, representing 91% of the total production capacity as of December 31, 2007. The synthetic fuel plants generated operating losses that were substantially offset by production tax credits.

The value of a production tax credit is adjusted annually by an inflation factor and published annually by the Internal Revenue Service (IRS). The value is reduced if the Reference Price of a barrel of oil exceeds certain thresholds. The actual tax credit phase-out for 2007 will not be certain until the Reference Price is published by the IRS in April 2008.

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 consolidated these projects due to our controlling influence and continuing involvement.


(in Millions)	2007		2006		2005
Production Tax Credits Generated
Allocated to DTE Energy	$	21	$	23	$	45
Allocated to partners		186		260		562

	$	207	$	283	$	607

Properties

The following were our synthetic fuels projects:


Facility	Location	% Owned			Industry Served
\| \| \|
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	Clover, VA		51	%	Utility
DTE Buckeye, LLC (2 plants)	Cheshire, OH		1	%	Utility

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 estimated significant future environmental expenditures based upon current regulations:


(in Millions)	Electric		Gas		Non- Utility		Total
Air	$	2,441	$	—	$	—	$	2,441
Water		55		—		15		70
MGP Sites		4		40		—		44
Other Clean Up Sites		11		2		—		13

Estimated total future expenditures through 2018	$	2,511	$	42	$	15	$	2,568


Estimated 2008 expenditures	$	288	$	6	$	11	$	305

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

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

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

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 facility in Michigan. We expect the project to be completed within two years. Our non-utility affiliates are substantially in compliance with all environmental requirements.

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

Greater details on environmental issues are provided in Notes 5 and 16 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

EMPLOYEES

The following table shows our employees as of December 31, 2007:


	Represented		Non-represented		Total
Detroit Edison		2,847		1,827		4,674
DTE Energy Corporate Services, LLC		1,064		1,921		2,985
MichCon		1,026		377		1,403
Other		311		889		1,200

Total		5,248		5,014		10,262

There are several bargaining units for our represented employees. In October 2007, a new three-year agreement was ratified by approximately 950 employees in our gas operations. In December 2007, a new three-year agreement was ratified by approximately 3,100 employees in our electric operations and corporate services. The contracts of the remaining represented employees expire at various dates in 2008 and 2009.

EXECUTIVE OFFICERS OF DTE ENERGY


			Present
			Position
Name	Age (1)	Present Position	Held Since
\| \| \|
Anthony F. Earley, Jr.	58	Chairman of the Board and Chief Executive Officer		8-1-98
Gerard M. Anderson	49	Chief Operating Officer and		10-31-05
		President		6-23-04
Robert J. Buckler	58	President and Chief Operating Officer, Detroit Edison		10-31-05
		Group President, DTE Energy		5-31-05
David E. Meador	50	Executive Vice President and Chief Financial Officer		6-23-04
Lynne Ellyn	56	Senior Vice President and Chief Information Officer		12-31-01
Paul C. Hillegonds	58	Senior Vice President		5-16-05
Ron A. May	56	Senior Vice President		1-22-04
Bruce D. Peterson	51	Senior Vice President and General Counsel		6-25-02
Gerardo Norcia	45	President and Chief Operating Officer, MichCon and Group President, DTE Energy		6-28-07
Larry E. Steward	55	Vice President		1-15-01
Peter B. Oleksiak	41	Vice President and Controller		2-07-07
Sandra K. Ennis	51	Corporate Secretary		8-4-05


(1)		As of December 31, 2007

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 Mr. Hillegonds, all of the above officers have been employed by DTE Energy in one or more management capacities during the past 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.

Pursuant to Article VI of our Articles of Incorporation, directors of DTE Energy will not be personally liable to us or our 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 us 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 eight insurance policies providing aggregate coverage in the amount of $185 million.

Item 1A. 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.

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

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

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

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

The supply and price of fuel and other commodities may impact our financial results. We are dependent on coal for much of our electrical generating capacity. Price fluctuations and fuel supply disruptions could have a negative impact on our ability to profitably generate electricity. 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 our non-utility businesses that compete with utilities and alternative electric suppliers.

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

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

Our non-utility operations may not perform to our expectations. We rely on our non-utility operations for a 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.

The inability to consummate strategic transactions for our non-utility operations could affect our expected cash flows. As part of a strategic review of our non-utility operations, we have taken and continue to pursue various actions including the acquisition, sale, restructuring or recapitalization of various non-utility businesses. If we are not able to consummate strategic transactions on favorable terms or timing, our expected cash flows could be lower than anticipated.

Our participation in energy trading markets subjects us to 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.

Our estimates of gas reserves are subject to change. We provide no assurance that our estimates of our Barnett gas reserves are accurate. We estimate proved gas reserves and the future net cash flows attributable to those reserves. There are numerous uncertainties inherent in estimating quantities of proved gas reserves and cash flows attributable to such reserves, including factors beyond our control. 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, quantities of recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and underlying information we used.

We rely on cash flows from subsidiaries. DTE Energy is a holding company. 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 and could increase our borrowing costs. In addition, a reduction in credit rating may require us to post collateral related to various trading contracts, which would impact our liquidity.

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

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

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

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

We may also incur liabilities as a result of potential future requirements to address climate change issues. Proposals for voluntary initiatives and mandatory controls are being discussed both in the United States and worldwide to reduce greenhouse gases such as carbon dioxide, a by-product of burning fossil fuels. If increased regulation of greenhouse gas emissions are implemented, the operations of our fossil-fuel generation assets may be significantly impacted.

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

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

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

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

A work interruption may adversely affect us. Unions represent approximately 5,000 of our employees. A union choosing to strike would have an impact on our business. We are unable to predict the effect a work stoppage would have on our costs of operation and financial performance.

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

Our ability to utilize production tax credits may be limited. To reduce U.S. dependence on imported oil, the Internal Revenue Code provides production tax credits as an incentive for taxpayers to produce fuels from alternative sources. We have generated production tax credits from the synfuel, coke battery, landfill gas recovery and gas production operations. We have received favorable private letter rulings on all of the synfuel facilities. All production tax credits taken after 2003 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. We have also provided certain guarantees and indemnities in conjunction with the sales of interests in the synfuel facilities.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

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

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

For additional discussion on legal matters, see Notes 5 and 16 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

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 2007.

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. 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
Year		Quarter	High		Low		Per Share
	2007
		First	$	49.42	$	45.14	$	0.530
		Second	$	54.74	$	47.22	$	0.530
		Third	$	51.74	$	45.26	$	0.530
		Fourth	$	51.19	$	43.96	$	0.530
	2006
		First	$	44.23	$	40.00	$	0.515
		Second	$	41.91	$	38.77	$	0.515
		Third	$	43.63	$	40.26	$	0.515
		Fourth	$	49.24	$	41.37	$	0.530

At December 31, 2007, there were 163,232,095 shares of our common stock outstanding. These shares were held by a total of 85,481 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.

We paid cash dividends on our common stock of $364 million in 2007, $365 million in 2006, and $360 million in 2005. 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 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 18 of the Notes to Consolidated Financial Statements in Item 8 of this Report for additional detail.

See the following table for information as of December 31, 2007.

Number of securities

to be issued upon

Weighted-average

remaining available for

exercise of

exercise price of

future issuance under equity

outstanding options

compensation plans

Plans approved by shareholders

4,394,809

42.37

6,289,136

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table provides information about our purchases of equity securities that are registered by the Company pursuant to Section 12 of the Exchange Act for the year ended December 31, 2007:


					Number
					of Shares				Maximum Dollar
					Purchased as				Value that May
	Number of		Average		Part of Publicly		Average		Yet Be
	Shares		Price		Announced		Price Paid		Purchased Under
	Purchased		Paid Per		Plans or		Per Share		the Plans or
Period	(1)		Share (1)		Programs (2)		(2)		Programs (2)
01/01/07 – 01/31/07		—		—		—		—	$	651,506,040
02/01/07 – 02/28/07		20,000	$	47.03		—		—		651,506,040
03/01/07 – 03/31/07		168,650		46.50		989,300	$	46.46		605,523,194
04/01/07 – 04/30/07		75,500		48.62		—		—		605,523,194
05/01/07 – 05/31/07		1,550		51.34		1,771,000		52.23		1,362,982,121
06/01/07 – 06/30/07		—		—		4,481,832		50.01		1,138,745,816
07/01/07 – 07/31/07		1,000		48.60		3,208,538		49.15		980,986,679
08/01/07 – 08/31/07		376,250		47.89		2,474,986		47.85		862,514,949
09/01/07 – 09/30/07		—		—		380,800		47.83		844,294,092
10/01/07 – 10/31/07		7,575		49.95		401,495		47.71		825,132,252
11/01/07 – 11/30/07		20,000		49.09		46,689		47.88		822,895,623
12/01/07 – 12/31/07		15,000		45.23		—		—		822,895,623

Total		685,525				13,754,640


(1)		Represents shares of common stock purchased on the open market to provide shares to participants under various employee compensation and incentive programs. These purchases were not made pursuant to a publicly announced plan or program.

(2)		In January 2005, the DTE Energy Board of Directors authorized the repurchase of up to $700 million of common stock through 2008. In May 2007, the DTE Energy Board of Directors authorized the repurchase of up to an additional $850 million of common stock through 2009. Through December 31, 2007, repurchases of approximately $725 million of common stock were made under these authorizations. These authorizations provide management with flexibility to pursue share repurchases from time to time and will depend on actual and future monetizations, cash flows and investment opportunities.

Item 6. Selected Financial Data

The following selected financial data should be read in conjunction with the accompanying Management’s Discussion and Analysis in Item 7 of this Report and Notes to the Consolidated Financial Statements in Item 8 of this Report.


(in Millions, except per share amounts)	2007		2006		2005			2004		2003
Operating Revenues	$	8,506	$	8,159	$	8,094		$	6,419	$	6,429

Net Income (Loss)
Total from continuing operations (1)	$	787	$	389	$	272		$	265	$	275
Discontinued operations		184		43		268			166		273
Cumulative effect of accounting changes		—		1		(3	)		—		(27	)

Net Income	$	971	$	433	$	537		$	431	$	521


Diluted Earnings Per Share
Total from continuing operations	$	4.62	$	2.18	$	1.55		$	1.53	$	1.63
Discontinued operations		1.08		.24		1.52			.96		1.62
Cumulative effect of accounting changes		—		.01		(.02	)		—		(.16	)

Diluted Earnings Per Share	$	5.70	$	2.43	$	3.05		$	2.49	$	3.09


Financial Information
Dividends declared per share of common stock	$	2.12	$	2.075	$	2.06		$	2.06	$	2.06
Total assets	$	23,754	$	23,785	$	23,335		$	21,297	$	20,753
Long-term debt, including capital leases	$	6,971	$	7,474	$	7,080		$	7,606	$	7,669
Shareholders’ equity	$	5,853	$	5,849	$	5,769		$	5,548	$	5,287


(1)		2007 amounts include $580 million after-tax gain on the Antrim sale transaction and $210 million after-tax losses on hedge contracts associated with the Antrim sale. See Note 3 of Notes to Consolidated Financial Statements in Item 8 of this Report.

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

OVERVIEW

DTE Energy is a diversified energy company with 2007 operating revenues in excess of $8 billion and approximately $24 billion in assets. 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, distribution and storage services throughout southeastern Michigan. We operate four energy-related non-utility segments with operations throughout the United States.

The following table summarizes our financial results:


(in Millions, except Earnings per Share)	2007		2006		2005
Income from Continuing Operations	$	787	$	389	$	272
Earnings per Diluted Share	$	4.62	$	2.18	$	1.55

Net Income	$	971	$	433	$	537
Earnings per Diluted Share	$	5.70	$	2.43	$	3.05

The increase for 2007 was primarily due to approximately $370 million in net income resulting from the gain on the sale of the Antrim shale gas exploration and production business of $900 million ($580 million after-tax), partially offset by losses recognized on related hedges of $323 million ($210 million after-tax), including recognition of amounts previously recorded in accumulated other comprehensive income. Net income in 2006 was adversely impacted by the temporary idling of synfuel plants along with

associated impairments and reserves, and higher levels of deferrals of potential gains from selling interests in the synfuel plants. Impairments within our Power and Industrial Projects segment also had a negative impact on the results of the 2006 period. The 2006 decrease was partially offset by higher earnings at Detroit Edison, and Energy Trading segment mark-to-market losses in 2005 that did not recur in 2006.

The items discussed below influenced our current financial performance and/or may affect future results:

	•		Effects of weather and collectibility of accounts receivable on utility operations;

	•		Impact of regulatory decisions on our utility operations;

	•		Monetization of our Unconventional Gas Production business;

	•		Monetization of our Power and Industrial Projects business;

	•		Results in our Energy Trading business;

	•		Synfuel-related earnings; and

	•		Cost reduction efforts and required environmental and reliability-related capital investments.

UTILITY OPERATIONS

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.

Our Gas Utility segment consists of MichCon and Citizens. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.3 million residential, commercial and industrial customers throughout Michigan. MichCon also has subsidiaries involved in the gathering and transmission of natural gas in northern Michigan. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.

Weather - Earnings from our utility operations are seasonal and very sensitive to weather. Electric utility earnings are primarily dependent on hot summer weather, while the gas utility’s results are primarily dependent on cold winter weather. Restoration and other costs associated with storm-related power outages lowered pre-tax earnings by $68 million in 2007, $46 million in 2006 and $82 million in 2005.

Receivables - Both utilities continue to experience high levels of past due receivables, especially within our Gas Utility operations, which is primarily attributable to economic conditions and a lack of adequate levels of governmental assistance for low-income customers.

We have taken aggressive actions to reduce the level of past due receivables, including increasing 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 2006, we sold previously written-off accounts of $43 million resulting in a gain and net proceeds of $1.9 million. The gain was recorded as a recovery through doubtful accounts expense, which is included within Operation and maintenance expense.

Our doubtful accounts expense for the two utilities increased to $135 million in 2007 from $123 million in 2006 and from $98 million in 2005.

The April 2005 MPSC gas rate order provided for an uncollectible true-up mechanism for MichCon. The uncollectible true-up mechanism enables MichCon to recover ninety percent of the difference between the actual uncollectible expense for each year and $37 million after an annual reconciliation proceeding before the MPSC. The MPSC approved the 2005 annual reconciliation in December 2006, allowing

MichCon to surcharge $11 million beginning in January 2007. The MPSC approved the 2006 annual reconciliation in December 2007, allowing MichCon to surcharge $33 million beginning in January 2008. We expect to file the 2007 reconciliation in the first quarter of 2008 requesting an additional surcharge of approximately $33 million including the uncollected balance from 2005 surcharge. We accrue interest income on the outstanding balances.

Regulatory activity — Detroit Edison filed a general rate case on April 13, 2007 based on a 2006 historical test year. The filing with the MPSC requested a $123 million, or 2.9 percent, average increase in Detroit Edison’s annual revenue requirement for 2008. On August 31, 2007, Detroit Edison filed a supplement to its April 2007 rate case filing to account for certain recent events. A July 2007 decision by the Court of Appeals of the State of Michigan remanded back to the MPSC the November 2004 order in a prior Detroit Edison rate case that denied recovery of merger control premium costs. Also, the Michigan legislature enacted the Michigan Business Tax (MBT) in July 2007. The supplemental filing addressed the recovery of the merger control premium costs and the enactment of the MBT. The net impact of the supplemental changes results in an additional revenue requirement of approximately $76 million. On February 20, 2008, Detroit Edison filed an update to its April 2007 rate case filing. The update reflects the use of 2009 as the projected test year and includes a revised 2009 load forecast, and 2009 estimates on environmental and advanced metering infrastructure capital expenditures, and adjustments to the calculation of the MBT. See Note 5 of the Notes to Consolidated Financial Statements.

The MPSC issued an order on August 31, 2006 approving a settlement agreement providing for an annualized rate reduction of $53 million for 2006 for Detroit Edison, effective September 5, 2006. Beginning January 1, 2007, and continuing until April 13, 2008, one year from the filing of the general rate case on April 13, 2007, rates were reduced by an additional $26 million, for a total reduction of $79 million annually. Detroit Edison experienced a rate reduction of approximately $76 million in 2007, as a result of this order. The revenue reduction is net of the recovery of costs associated with the Performance Excellence Process. The settlement agreement provides for some level of realignment of the existing rate structure by allocating a larger percentage of the rate reduction to the commercial and industrial customer classes than to the residential customer classes.

In August 2006, MichCon filed an application with the MPSC requesting permission to sell base gas that would become accessible with storage facilities upgrades. In December 2006, MichCon filed its 2007-2008 GCR plan case proposing a maximum GCR factor of $8.49 per Mcf. In August 2007, a settlement agreement in this proceeding was approved by the MPSC that provides for a sharing with customers of the proceeds from the sale of base gas. In addition, the agreement provides for a rate case filing moratorium until January 1, 2009, unless certain unanticipated changes occur that impact income by more than $5 million. MichCon’s gas storage enhancement projects, the main subject of the aforementioned settlement, will enable 17 billion cubic feet (Bcf) of gas to become available for cycling. Under the settlement terms, MichCon delivered 13.4 Bcf of this gas to its customers through 2007 at a savings to market-priced supplies of approximately $54 million. This settlement provides for MichCon to retain the proceeds from the sale of 3.6 Bcf of gas, which MichCon expects to sell in 2007, 2008 and 2009. In the fourth quarter of 2007, MichCon sold .75 Bcf of base gas and recognized a pre-tax gain of $5 million. By enabling MichCon to retain the profit from the sale of this gas, the settlement provides MichCon with the opportunity to earn an 11% return on equity with no customer rate increase for a period of five years from 2005 to 2010.

Coal Supply - Our generating fleet produces approximately 79% 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 and resulting in longer lead times for western coal shipments.

Nuclear Fuel - 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. We have a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. We are obligated to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold. The fee is a component of nuclear fuel expense. Delays have occurred in the DOE’s program for the acceptance and disposal of spent nuclear fuel at a permanent repository. Until the DOE is able to fulfill its obligation under the contract, we are responsible for the spent nuclear fuel storage. We have begun work on an on-site dry cask storage facility. We are a party in the litigation against the DOE for both past and future costs associated with the DOE’s failure to accept spent nuclear fuel under the timetable set forth in the Federal Nuclear Waste Policy Act of 1982.

NON-UTILITY OPERATIONS

We have made significant investments in non-utility asset-intensive businesses. We employ disciplined investment criteria when assessing opportunities that leverage our assets, skills and expertise. Specifically, we invest in targeted energy markets with attractive competitive dynamics where meaningful scale is in alignment with our risk profile. A number of factors have impacted our non-utility businesses, including the effect of oil prices on the synthetic fuel business, losses and impairments from certain power generation assets, waste coal recovery and landfill gas recovery businesses, and earnings volatility in our energy trading business. As part of a strategic review of our non-utility operations, we have taken and continue to pursue various actions including the sale, restructuring or recapitalization of certain non-utility businesses that generated approximately $900 million in after-tax cash proceeds in 2007 and is expected to generate an additional $800 million in 2008. See Note 3 of the Notes to Consolidated Financial Statements in Item 8 of this Report for information on the sale of our Antrim shale gas exploration and production business in northern Michigan, the sale of a portion of our Barnett shale properties and the pending financing and sale of a 50 percent ownership interest in select projects within the Power and Industrial Projects segment.

Coal and Gas Midstream

Our Coal and Gas Midstream segment consists of Coal Transportation and Marketing and the Pipelines, Processing and Storage businesses.

Coal Transportation and Marketing provides fuel, transportation, storage, blending, 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 marketing and coal-to-power tolling transactions, as well as the purchase and sale of emissions credits. We perform 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. In 2008, we expect to see a decrease in net income since approximately $11 million of our 2007 Coal Transportation and Marketing net income was dependent upon our Synfuel operations that ceased operations at the end of 2007. We plan to continue to build our capacity to transport greater amounts of western coal, and have expanded our coal storage and blending capacity with the start of commercial operation of our coal terminal in Chicago in April 2007.

Pipelines, Processing and Storage owns a partnership interest in two interstate transmission pipelines, four carbon dioxide processing facilities and two natural gas storage fields. The pipeline and storage assets are primarily supported by stable, long-term, fixed-price revenue contracts. The assets of these businesses are well integrated with other DTE Energy operations. Pursuant to an operating agreement, MichCon provides physical operations, maintenance and technical support for the Washington 28 and Washington 10 storage facilities.

Pipelines, Processing and Storage is continuing its steady growth plan of expansion of storage capacity, with two new expansions and the expanding and building of new pipeline capacity to serve markets in the Midwest and Northeast United States.

Unconventional Gas Production

Our Unconventional Gas Production business is engaged in natural gas exploration, development and production primarily within the Barnett shale in north Texas.

In 2007, we sold our Antrim shale gas exploration and production business in the northern lower peninsula of Michigan to Atlas Energy Resources LLC for gross proceeds of $1.262 billion. See Note 3 of the Notes to Consolidated Financial Statements.

In 2007, we continued to develop our position in the Barnett shale basin in north Texas, where our total leasehold acreage (after the January 2008 sale referred to below) is 63,541, net of impairments (58,742 acres, net of interest of others). We continue to acquire select acreage positions in active development areas in the Barnett shale to optimize our existing portfolio.

Our Unconventional Gas Production segment recorded pre-tax impairment losses of $27 million in 2007, related to the write-off of unproved properties and expiration of leases in Bosque County, which is located in the southern expansion area of the Barnett shale basin in north Texas. The properties were impaired due to the lack of economic and operating viability of the southern expansion area. See Note 4 of the Notes to Consolidated Financial Statements.

As a component of our risk management strategy for our Barnett shale reserves, we hedged a portion of anticipated production from our reserves to secure an attractive investment return. As of December 31, 2007, we have a series of cash flow hedges for approximately 5.5 Bcf of anticipated Barnett gas production through 2010 at an average price of $7.48 per Mcf.

In August 2007, we announced that we were exploring opportunities to monetize a portion of our interests in the Barnett shale. On January 15, 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $250 million, subject to post-closing adjustments. The Company will recognize a gain on the sale in the first quarter of 2008. The properties in the sale include 186 billion cubic feet of proved and probable reserves on approximately 11,000 net acres in the core area of the Barnett shale.

We plan to retain our holdings in the western portion of the Barnett shale and anticipate significant opportunities to develop our current position while accumulating additional acreage in and around our existing assets.

Current natural gas prices and successes within the Barnett shale are resulting in additional capital being invested into the area. The competition for opportunities and goods and services may result in increased operating costs. However, our experienced Barnett shale personnel provide an advantage in addressing potential cost increases.

Texas – Barnett Shale


	2007		2006		2005
Net Producing Wells
Held for sale		33		27		8
Continuing operations		120		83		47

Total		153		110		55

Production Volume (Bcfe)
Held for sale		4.7		2.8		0.4
Continuing operations		3.0		1.3		0.4

Total		7.7		4.1		0.8

Proved Reserves (Bcfe) (1)
Held for sale		75		60		11
Continuing operations		144		111		48

Total		219		171		59

Net Developed Acreage (1)
Held for sale		4,987		3,977		1,349
Continuing operations (2)		9,880		10,693		13,018

Total		14,867		14,670		14,367

Net Undeveloped Acreage (1)
Held for sale		5,809		6,164		7,801
Continuing operations (2)		38,066		27,613		13,495

Total		43,875		33,777		21,296

Capital Expenditures (in Millions) (3)
Held for sale	$	45	$	67	$	19
Continuing operations		95		61		76

Total	$	140	$	128	$	95

Future Undiscounted Net Cash Flows (in Millions) (4)
Held for sale	$	282	$	167	$	63
Continuing operations		521		305		266

Total	$	803	$	472	$	329

Average gas price (per Mcf)	$	6.29	$	5.66	$	9.01


(1)		Due to the impairment of acreage and wells in the southern expansion area of the Barnett shale during 2007, the proved reserves and acreage numbers above do not include the southern area. Total net acreage related to impaired leases in the southern expansion area was 23,659 acres, 32,083 acres and 40,332 acres for the years 2007, 2006 and 2005, respectively.

(2)		Developed acreage for continuing operations shows a decrease from prior periods, which reflects the Company’s experience that spacing of wells in the Barnett shale has been reduced over the years. This reduced spacing estimate drives a shift from developed to undeveloped acreage counts. We continue to expand our total position in the western expansion area of the Barnett shale. During 2007, total net acreage for continuing operations increased by 9,640 acres.

(3)		Excludes sold and impaired assets in southern expansion area of the Barnett shale.

(4)		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.

Power and Industrial Projects

Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers, and biomass energy projects. This segment provides utility-type services using project assets usually located on or near the customers’ premises in the steel, automotive, pulp and paper, airport and other industries. These services include pulverized coal and petroleum coke supply, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. At December 31, 2007, this segment owned and operated one gas-fired peaking electric generating plant and a biomass-fired electric generating plant. This segment also owned one additional coal-fired power plant that is currently not in service. This segment develops, owns and operates landfill gas recovery systems throughout the United States. In addition, this segment produces metallurgical coke from two coke batteries. The production of coke from these coke batteries generates production tax credits.

We expect to sell a 50 percent interest in a portfolio of select Power and Industrial Projects. In addition to the proceeds that the Company will receive from the sale of the 50 percent equity interest, the company that will own the projects will obtain debt financing and the proceeds will be distributed to DTE Energy immediately prior to the sale of the equity interest. The total gross proceeds the Company will receive are expected to approximate $650 million. The Company expects to complete the transaction in the first half of 2008. This timing, however, is highly dependent on availability of acceptable financing terms in the credit markets. As a result, the Company cannot predict the timing with certainty. The Company expects to recognize a gain upon completion of the transaction. In conjunction with the sale, the Company will enter into a management services agreement to manage the day-to-day operations of the Projects and to act as the managing member of the company that owns the projects. We plan to account for our 50 percent ownership interest in the company that will own the portfolio of projects using the equity method. See Note 3 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Energy Trading

Energy Trading focuses on physical power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio and the optimization of contracted natural gas pipelines and storage, and power transmission and generating capacity positions. Our customer base is predominantly utilities, local distribution companies, pipelines, 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 the recognition of unrealized gains and losses from changes in the fair value of the derivatives in our results of operations. 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. Energy Trading provides commodity risk management services to the other businesses within DTE Energy.

DISCONTINUED OPERATIONS

Synthetic Fuel

The Synthetic Fuel business had been shown as a non-utility segment through the third quarter of 2007. Due to the expiration of synfuel production tax credits at the end of 2007, the Synthetic Fuel business ceased operations and has been classified as a discontinued operation as of December 31, 2007. Synfuel plants chemically changed coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits were provided for the production and sale of solid synthetic fuel produced from coal and were available through December 31, 2007. To optimize income and cash flow from the synfuel operations, we had sold interests in all nine of the facilities, representing 91% of the total production capacity as of December 31, 2007. The synthetic fuel plants generated operating losses that were substantially offset by production tax credits.

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.

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 required to provide safe, reliable and affordable energy. Specifically, we began a series of focused improvement initiatives within our Electric and Gas Utilities, and our corporate support function. The process is rigorous and challenging and seeks to yield sustainable performance improvements to our customers and shareholders. We have identified the Performance Excellence Process as critical to our long-term growth strategy. In order to fully realize the benefits from the Performance Excellence Process, it is necessary to make significant up-front investments in our infrastructure and business processes. The CTA in 2006 exceeded our savings, but we began to realize sustained net cost savings in 2007.

In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison and MichCon, commencing in 2006, to defer the incremental CTA. Further, the order provides for Detroit Edison and MichCon to amortize the CTA deferrals over a ten-year period beginning with the year subsequent to the year the CTA was deferred. Detroit Edison deferred approximately $102 million of CTA in 2006 as a regulatory asset and began amortizing deferred 2006 costs in 2007 as the recovery of these costs was provided for by the MPSC in the order approving the settlement in the show cause proceeding. Amortization of prior year deferred CTA costs amounted to $10 million in 2007. During 2007, CTA costs of approximately $54 million were deferred. MichCon cannot defer CTA costs at this time because a regulatory recovery mechanism has not been established by the MPSC. MichCon expects to seek a recovery mechanism in its next rate case in 2009.

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 segment currently expects to invest approximately $5.2 billion (excluding investments in new generation capacity, if any), including increased environmental requirements and reliability enhancement projects during the period of 2008 through 2012. Our gas utility segment currently expects to invest approximately $1.0 billion 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 consistent with prior treatment.

ENTERPRISE BUSINESS SYSTEMS

In 2003, we began the development of our Enterprise Business Systems (EBS) project, an enterprise resource planning system initiative to improve existing processes and to implement new core information systems, relating to finance, human resources, supply chain and work management. As part of this initiative, we have implemented EBS software including, among others, products developed by SAP AG. The first phase of implementation occurred in 2005 in the regulated electric fossil generation unit. The second phase of implementation began in April 2007 and was completed by the end of 2007. The total capital cost of implementation was approximately $385 million. We expect the benefits of lower costs, faster business cycles, repeatable and optimized processes, enhanced internal controls, improvements in inventory management and reductions in system support costs to outweigh the expense of our investment in this initiative.

OUTLOOK

The next few years will be a period 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.

Looking forward, we will focus on several areas 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; and

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

Along with pursuing a leaner organization, we anticipate approximately $200 million of synfuel-related cash impacts in 2008 and 2009, which consists of cash from operations and proceeds from option hedges, including approximately $100 million of tax credit carryforward utilization and other tax benefits that are expected to reduce future tax payments. As part of a strategic review of our non-utility operations, we have taken and continue to pursue various actions including the sale, restructuring or recapitalization of certain non-utility businesses that generated approximately $900 million in after-tax cash proceeds in 2007 and are expected to generate an additional approximately $800 million in 2008. We have used approximately $725 million to repurchase common stock and approximately $500 million to redeem outstanding debt. In 2008, upon completion of our remaining monetization activities, we expect to repurchase an additional approximately $275 million of common stock and to use approximately $200 million to redeem outstanding debt, assuming the expected asset sales occur. Our objectives for cash redeployment are to increase shareholder value, strengthen the balance sheet and coverage ratios to improve our current credit rating and outlook, and to have any monetizations be accretive to earnings per share.

We performed an assessment during the fourth quarter of 2007 to determine the impact, if any, of the current conditions in the credit markets on our operations. We believe that our access to financing at reasonable interest rates, the fair value of assets held in trust to satisfy future obligations under our pension plans, and our counterparties’ creditworthiness will not be significantly affected by current conditions in the credit market.

RESULTS OF OPERATIONS

Net income in 2007 was $971 million, or $5.70 per diluted share, compared to net income of $433 million, or $2.43 per diluted share in 2006 and net income of $537 million, or $3.05 per diluted share in 2005. Excluding discontinued operations and the cumulative effect of accounting changes, our income from continuing operations in 2007 was $787 million, or $4.62 per diluted share, compared to income of $389 million, or $2.18 per diluted share in 2006 and income of $272 million, or $1.55 per diluted share in 2005. The following sections provide a detailed discussion of our segments’ operating performance and future outlook.

Based on the following structure, we set strategic goals, allocate resources and evaluate performance:

	•		Electric Utility, consisting of Detroit Edison;

	•		Gas Utility, primarily consisting of MichCon;

	•		Non-utility Operations

	•		Coal and Gas Midstream, primarily consisting of coal transportation and marketing, gas pipelines and storage;

	•		Unconventional Gas Production, primarily consisting of unconventional gas project development and production;

	•		Power and Industrial Projects, primarily consisting of on-site energy services, steel-related projects and power generation with services;

	•		Energy Trading, consisting of energy marketing and trading operations; and

•


(in Millions)	2007			2006			2005
Net Income by Segment:
Electric Utility	$	317		$	325		$	277
Gas Utility		70			50			37
Non-utility Operations:
Coal and Gas Midstream		53			50			45
Unconventional Gas Production (1)		(217	)		9			4
Power and Industrial Projects		30			(80	)		4
Energy Trading		32			96			(43	)

Corporate & Other (1)		502			(61	)		(52	)

Income (Loss) from Continuing Operations:
Utility		387			375			314
Non-utility		(102	)		75			10
Corporate & Other		502			(61	)		(52	)

		787			389			272

Discontinued Operations		184			43			268
Cumulative Effect of Accounting Changes		—			1			(3	)

Net Income	$	971		$	433		$	537


(1)		2007 Net Loss of the Unconventional Gas Production segment resulted principally from the recognition of losses on hedge contracts associated with the Antrim sale transaction. 2007 Net Income of the Corporate & Other segment resulted principally from the gain recognized on the Antrim sale transaction. See Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.

ELECTRIC UTILITY

Our Electric Utility segment consists of Detroit Edison.

Factors impacting income: Our net income decreased $8 million in 2007 and increased $48 million in 2006. The 2007 decrease reflects higher operation and maintenance expenses, partially offset by higher gross margins and lower depreciation and amortization expenses. The 2006 increase primarily reflects higher gross margins, partially offset by increased depreciation and amortization expenses.


(in Millions)	2007			2006			2005
Operating Revenues	$	4,900		$	4,737		$	4,462
Fuel and Purchased Power		1,686			1,566			1,590

Gross Margin		3,214			3,171			2,872
Operation and Maintenance		1,422			1,336			1,308
Depreciation and Amortization		764			809			640
Taxes Other Than Income		277			252			241
Asset (Gains) and Losses, Net		8			(6	)		(26	)

Operating Income		743			780			709
Other (Income) and Deductions		277			294			283
Income Tax Provision		149			161			149

Net Income	$	317		$	325		$	277


Operating Income as a Percent of Operating Revenues		15	%		16	%		16	%

Gross margin increased $43 million during 2007 and $299 million in 2006. The increase in 2007 was attributed to higher margins due to returning sales from electric Customer Choice, the favorable impact of a May 2007 MPSC order related to the 2005 PSCR reconciliation and weather related impacts, partially offset by lower rates resulting primarily from the August 2006 settlement in the MPSC show cause proceeding and the unfavorable impact of a September 2006 MPSC order related to the 2004 PSCR

reconciliation. The 2006 improvement was primarily due to increased rates due to the expiration of the residential rate cap on January 1, 2006 and returning sales from electric Customer Choice, partially offset by milder weather. Revenues include a component for the cost of power sold that is recoverable through the PSCR mechanism.

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


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

Increase in gross margin	$	43		$	299


	2007					2006					2005
Power Generated and Purchased (in Thousands of MWh)
Power Plant Generation
Fossil		42,359		72	%		39,686		70	%		40,756		73	%
Nuclear		8,314		14			7,477		13			8,754		16

		50,673		86			47,163		83			49,510		89

Purchased Power		8,422		14			9,861		17			6,378		11

System Output		59,095		100	%		57,024		100	%		55,888		100	%
Less Line Loss and Internal Use		(3,391	)				(3,603	)				(3,205	)

Net System Output		55,704					53,421					52,683


Average Unit Cost ($/MWh)
Generation (1)	$	15.83				$	15.61				$	15.47

Purchased Power (2)	$	62.40				$	53.71				$	89.37

Overall Average Unit Cost	$	22.47				$	22.20				$	23.90


(1)		Represents fuel costs associated with power plants.

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


(in Thousands of MWh)	2007		2006		2005
Electric Sales
Residential		16,147		15,769		16,812
Commercial		19,332		17,948		15,618
Industrial		13,338		13,235		12,317
Wholesale		2,902		2,826		2,329
Other		398		402		390

		52,117		50,180		47,466
Interconnection sales (1)		3,587		3,241		5,217

Total Electric Sales		55,704		53,421		52,683


Electric Deliveries
Retail and Wholesale		52,117		50,180		47,466
Electric Customer Choice		1,690		2,694		6,760
Electric Customer Choice–Self Generators (2)		549		909		518

Total Electric Sales and Deliveries		54,356		53,783		54,744


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

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

Operation and maintenance expense increased $86 million in 2007 and $28 million in 2006. The increase in 2007 is primarily due to EBS implementation costs of $30 million, higher storm expenses of $22 million, increased uncollectible expense of $22 million and higher corporate support expenses of $20 million. The 2006 increase was primarily due to increased distribution system maintenance of $35 million and increased plant outage costs of $33 million, partially offset by $36 million of lower storm expenses.

Depreciation and amortization expense decreased $45 million in 2007 and increased $169 million in 2006. The 2007 decrease was due primarily to a 2006 net stranded cost write-off of $112 million related to the September 2006 MPSC order regarding stranded costs and a $13 million decrease in our asset retirement obligation at our Fermi 1 nuclear facility, partially offset by $58 million of increased amortization of regulatory assets and $13 million of higher depreciation expense due to increased levels of depreciable plant assets. Amortization of prior year deferred CTA costs amounted to $10 million in 2007. The 2006 increase was due to a $112 million net stranded cost write-off related to the September 2006 MPSC order regarding stranded costs and a $19 million increase in our asset retirement obligation at our Fermi 1 nuclear facility. In 2006, we also had increased amortization of regulatory assets of $19 million related to electric Customer Choice and $8 million related to our securitized assets.

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

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

Outlook – We will move forward in our efforts to continue to improve the operating performance of Detroit Edison. We continue to resolve outstanding regulatory issues and continue to pursue additional regulatory and/or legislative solutions for structural problems within the Michigan electric market structure, primarily electric Customer Choice and the need to adjust rates for each customer class to reflect the full cost of service. We are also seeking regulatory reform to insure more timely cost recovery and resolution of rate cases. Looking forward, additional issues, such as rising prices for coal, health care and higher levels of capital spending, will result in us taking meaningful action to address our costs while continuing to provide quality customer service. We will utilize the DTE Energy Operating System and the Performance Excellence Process to seek opportunities to improve productivity, remove waste and decrease our costs while improving customer satisfaction.

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

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

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

•

amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals,

			or new legislation;

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

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

	•		economic conditions within the State of Michigan;

	•		weather, including the severity and frequency of storms;

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

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

We expect cash flows and operating performance will continue to be at risk due to the electric Customer Choice program until the issues associated with this program are adequately addressed. We will accrue as regulatory assets any future unrecovered generation-related fixed costs (stranded costs) due to electric Customer Choice that we believe are recoverable under Michigan legislation and MPSC orders. We cannot predict the outcome of these matters. See Note 5 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

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

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

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

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

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

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

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

GAS UTILITY

Our Gas Utility segment consists of MichCon and Citizens.

Factors impacting income: Gas Utility’s net income increased $20 million in 2007 and $13 million in 2006. The 2007 and 2006 increases were due primarily to higher gross margins.


(in Millions)	2007			2006			2005
Operating Revenues	$	1,875		$	1,849		$	2,138
Cost of Gas		1,164			1,157			1,490

Gross Margin		711			692			648
Operation and Maintenance		429			431			424
Depreciation and Amortization		93			94			95
Taxes Other Than Income		56			53			43
Asset (Gains) and Losses, Net		(3	)		—			4

Operating Income		136			114			82
Other (Income) and Deductions		43			53			47
Income Tax Provision (Benefit)		23			11			(2	)

Net Income	$	70		$	50		$	37


Operating Income as a Percent of Operating Revenues		7	%		6	%		4	%

Gross margin increased $19 million and $44 million in 2007 and 2006, respectively. The increase in 2007 is primarily due to $21 million from the favorable effects of weather in 2007 and $28 million related to an increase in midstream services including storage and transportation, partially offset by a $26 million unfavorable impact in lost gas recognized and $7 million in GCR disallowances. The increase in 2006 is primarily due to $15 million in higher base rates and $22 million in higher revenue associated with the uncollectible expense tracking mechanism authorized by the MPSC in the April 2005 gas rate order. Additionally, 2006 was impacted by a $17 million favorable impact in lost gas recognized and an increase of $24 million in midstream services including storage and transportation. Partially offsetting these increases were declines of $31 million due to warmer than normal weather and $26 million as a result of customer conservation and lower volumes. The comparability of 2006 to 2005 is also affected by an adjustment we recorded in the first quarter of 2005 related to an April 2005 MPSC order in our 2002 GCR reconciliation case that disallowed $26 million representing unbilled revenues at December 31, 2001. Revenues include a component for the cost of gas sold that is recoverable through the GCR mechanism.


	2007		2006		2005
Gas Markets (in Millions)
Gas sales	$	1,536	$	1,541	$	1,860
End user transportation		140		135		134

		1,676		1,676		1,994
Intermediate transportation		59		69		58
Storage and other		140		104		86

	$	1,875	$	1,849	$	2,138


Gas Markets (in Bcf)
Gas sales		148		138		168
End user transportation		132		136		157

		280		274		325
Intermediate transportation		399		373		432

		679		647		757

Operation and maintenance expense decreased $2 million in 2007 and increased $7 million in 2006. The 2007 decrease was attributed to $4 million of lower uncollectible expense and $4 million of reduced corporate support expenses, partially offset by $5 million in increased EBS implementation costs. The 2006 increase is due to $14 million of higher uncollectible expense and $24 million in implementation

costs associated with our Performance Excellence Process, partially offset by $9 million of lower injuries and damages expenses and lower labor and employee incentives. The comparability of 2006 to 2005 was affected by an adjustment we recorded in the second quarter of 2005 for the disallowance of $11 million in environmental costs due to the April 2005 gas rate order and the requirement to defer negative pension expense as a regulatory liability. Additionally, the comparability was impacted by the DTE Energy parent company no longer allocating $9 million of merger-related interest to MichCon effective in April 2005.

Asset (gains) and losses, net gain increased $3 million in 2007 and increased $4 million in 2006. The 2007 increase is attributable to the sale of base gas. The 2006 increase is attributable to the write-off of certain computer equipment and related depreciation resulting from the April 2005 gas rate order.

Outlook – Operating results are expected to vary due to regulatory proceedings, weather, changes in economic conditions, customer conservation, process improvements and base gas sales. Higher gas prices and economic conditions have resulted in continued pressure on receivables and working capital requirements that are partially mitigated by the MPSC’s uncollectible true-up mechanism and GCR mechanism.

We will continue to utilize the DTE Energy Operating System and the Performance Excellence Process to seek opportunities to improve productivity, remove waste and decrease our costs while improving customer satisfaction.

NON-UTILITY OPERATIONS

Coal and Gas Midstream

Our Coal and Gas Midstream segment consists of Coal Transportation and Marketing and the Pipelines, Processing and Storage businesses.

Factors impacting income: Net income increased $3 million and $5 million in 2007 and 2006, respectively. Net income was higher in 2007 due to higher midstream gas storage revenues, offset by increased overhead related to legal expenses.


(in Millions)	2007			2006			2005
Operating Revenues	$	837		$	707		$	707
Operation and Maintenance		747			628			653
Depreciation and Amortization		8			4			3
Taxes Other Than Income		5			5			4
Asset (Gains) and Losses, Net		(1	)		—			—

Operating Income		78			70			47
Other (Income) and Deductions		(5	)		(8	)		(20	)
Income Tax Provision		30			28			22

Net Income	$	53		$	50		$	45

Operating revenues increased $130 million in 2007 and remained the same in 2006. In 2007, revenues were impacted by increases in our Coal and Transportation business based on higher synfuel related volumes and increases in trading volumes related to both coal and emissions. Revenues were also favorably impacted by higher midstream gas storage revenues in our Pipelines, Processing and Storage business. In 2006, our Coal Transportation and Marketing business experienced lower synfuel related volumes, which were offset by an increase in storage revenues in the Pipelines, Processing and Storage business.

Operation and maintenance expense increased $119 million in 2007 and decreased $25 million in 2006. The 2007 increase was due to increased Coal Transportation and Marketing volume related to higher synfuel related volumes and higher trading volumes related to coal and emissions.

The 2006 decrease was due to decreased expenses at our Coal Transportation and Marketing business due to decreased marketing volume.

Other (income) and deductions income decreased $3 million in 2007 and $12 million in 2006. The 2007 and 2006 decreases are primarily attributable to higher interest expense as a result of our expansion of owned storage.

Outlook – In 2008, we expect to see a decrease in net income since approximately $11 million of our 2007 Coal Transportation and Marketing net income was dependent upon our Synfuel operations that ceased operations at the end of 2007. Beyond 2008, we expect to continue to grow our Coal Transportation and Marketing business in a manner consistent with, and complementary to, the growth of our other business segments.

Our Pipelines, Processing and Storage business expects to continue its steady growth plan. In April 2007, Washington 28 received MPSC approval to increase working gas storage capacity by over 6 Bcf to a total of 16 Bcf by April 2008. In June 2007, Washington 10 received MPSC approval to develop the Shelby 2 storage field which will increase the working gas storage capacity of Washington 10 over the next two years by 8 Bcf to a total of 74 Bcf. Vector Pipeline placed into service its Phase 1 expansion for approximately 200 MMcf/d in November 2007. This project is fully supported by customers with long-term agreements. In addition, Vector Pipeline requested permission from the FERC in the fourth quarter of 2007 to build one more compressor station and to expand the Vector Pipeline by approximately 100 MMcf/d, with a proposed in-service date of November 1, 2009. Adding another compressor station will bring the system from its current capacity of about 1.2 Bcf/d up to 1.3 Bcf/d in 2009. Pipelines, Processing and Storage has a 26 percent ownership interest in Millennium Pipeline which commenced construction in June 2007 and is scheduled to be in service in late 2008. We plan to expand existing assets and develop new assets which are typically supported with long-term customer commitments.

Unconventional Gas Production

Our Unconventional Gas Production business is engaged in natural gas exploration, development and production primarily within the Barnett shale in north Texas. On June 29, 2007, we sold our Antrim shale gas exploration and production business in the northern lower peninsula of Michigan for gross proceeds of $1.262 billion. The gain on sale is included in the Corporate & Other segment. See Note 3 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Factors impacting income: Net income decreased $226 million in 2007 and increased $5 million in 2006. The significant decline in results in 2007 reflects the recording of losses on financial contracts that hedged our price risk exposure related to expected Antrim gas production and sales and impairments of our southern expansion area of the Barnett shale in 2007. The 2006 results were primarily impacted by an increase in Barnett shale production and an increase in net gas prices for Antrim shale. Partially offsetting these revenue increases were higher operating and depletion expenses associated with increased production and the operation of new wells.


(in Millions)	2007			2006			2005
Operating Revenues	$	(228	)	$	99		$	74
Operation and Maintenance		36			37			30
Depreciation, Depletion and Amortization		22			27			20
Taxes Other Than Income		8			11			11
Asset (Gains) and Losses, Net		27			(3	)		—

Operating Income (Loss)		(321	)		27			13
Other (Income) and Deductions		13			13			8
Income Tax Provision (Benefit)		(117	)		5			1

Net Income (Loss)	$	(217	)	$	9		$	4

Operating revenues decreased $327 million in 2007. The decrease for 2007 was due to the recording of $323 million of losses on financial contracts that hedged our price risk exposure related to expected Antrim gas production and sales through 2013. These financial contracts were accounted for as cash flow hedges, with changes in estimated fair value of the contracts reflected in other comprehensive income. Upon the sale of Antrim, the financial contracts no longer qualified as cash flow hedges. The contracts were retained and offsetting financial contracts were put into place to effectively settle these positions. As a result of these transactions and market research performed by the Company, we gained additional insight and visibility into the value ascribed to these contracts by third party market participants for the duration of the contracts. In conjunction with the Antrim sale and effective settlement of these contract positions, Antrim reclassified amounts held in Accumulated other comprehensive income and recorded the effective settlements, reducing operating revenues in 2007 by $323 million. Operating revenues increased $25 million in 2006 due to increased Barnett shale production.

Assets (gains) and losses, net decreased $30 million in 2007 primarily due to the recording of impairment losses of $27 million in 2007 related to the write-off of unproved properties and the expiration of leases in the southern expansion area of the Barnett shale.

Outlook – On January 15, 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $250 million, subject to post-closing adjustments. We will recognize a gain on the sale in the first quarter of 2008. The properties in the sale included 186 billion cubic feet of proved and probable reserves on approximately 11,000 net acres in the core area of the Barnett shale.

Current natural gas prices and successes within the Barnett shale are resulting in additional capital being invested into the area. The competition for opportunities and goods and services may result in increased operating costs, however, our experienced Barnett shale personnel provide an advantage in addressing potential cost increases.

We invested approximately $140 million in the Barnett shale in 2007. During 2007, Barnett shale production was approximately 7.7 Bcfe of natural gas compared with approximately 4.1 Bcfe in 2006.

Power and Industrial Projects

The Power and Industrial Projects segment is comprised primarily of projects that deliver utility-type products and services to industrial, commercial and institutional customers, and biomass energy projects.

Factors impacting income: Net income was $30 million in 2007 compared to a net loss of $80 million in 2006. The 2006 period reflects impairments at various businesses and projects.


(in Millions)	2007			2006			2005
Operating Revenues	$	473		$	409		$	428
Operation and Maintenance		409			366			329
Depreciation and Amortization		39			48			48
Taxes other than Income		11			12			14
Asset (Gains) and Losses, Reserves and Impairments, Net		—			75			(1	)

Operating Income (Loss)		14			(92	)		38
Other (Income) and Deductions		(13	)		43			4
Minority Interest		2			1			37
Income Taxes
Provision (Benefit)		6			(44	)		5
Production Tax Credits		(11	)		(12	)		(12	)

		(5	)		(56	)		(7	)

Net Income (Loss)	$	30		$	(80	)	$	4

Operating revenues increased $64 million in 2007 reflecting a new long-term utility services contract with a large automotive company, higher coke prices and sales volumes in addition to higher volumes at several other projects. Additionally, revenue was earned for a one-time success fee from the sale of an asset we operated for a third party. Revenues in 2006 decreased $19 million due primarily to lower coke prices and lower pulverized coal sales. The 2006 decrease was partially offset by increased revenue from our on-site energy projects, 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.

Operation and maintenance expense increased $43 million in 2007 and $37 million in 2006. The increases resulted from higher costs related to the addition of new facilities, a new long-term utility services contract with a large automotive company and higher volumes at several other projects.

Depreciation and amortization expense decreased $9 million in 2007 due primarily to the suspension of $6 million of depreciation expense in the fourth quarter of 2007 related to the assets held for sale, the sale of a generation facility during the year and reduced depreciation expense as a result of asset impairments at several biomass landfill sites in 2006.

Asset (gains) and losses, reserves and impairments, net expense decreased $75 million in 2007 and increased $76 million in 2006. In 2006, we recorded a $42 million impairment for one of our 100% owned natural gas-fired generating plants and a $14 million impairment at our landfill gas recovery unit relating to the write-down of long-lived assets at several landfill sites. Also, during 2006, we recorded a pre-tax impairment loss of $19 million for the write down of fixed assets and patents at our waste coal recovery business.

Other (income) and deductions expense decreased $56 million in 2007 and increased $39 million in 2006 primarily due to a realized gain of $8 million on the sale of a 50 percent equity interest in a natural gas-fired generating plant, a $4 million gain recognized in 2007 on an installment sale of a coke battery facility, a reduction of $5 million in interest expense and a $32 million impairment of a 51% equity interest in a natural gas-fired generating plant in 2006.

Outlook – We expect to sell a 50 percent interest in a portfolio of select Power and Industrial Projects. In addition to the proceeds that the Company will receive from the sale of the 50 percent equity interest, the company that will own the Projects will obtain debt financing and the proceeds will be distributed to DTE Energy immediately prior to the sale of the equity interest. The total gross proceeds the Company will receive are expected to approximate $650 million. The Company expects to complete the transaction in the first half of 2008. This timing, however, is highly dependent on availability of acceptable financing terms in the credit markets. As a result, the Company cannot predict the timing with certainty. The Company expects to recognize a gain upon completion of the transaction. In conjunction with the sale, the Company will enter into a management services agreement to manage the day-to-day operations of the Projects and to act as the managing member of the company that owns the Projects. We plan to account for our 50 percent ownership interest in the company that will own the portfolio of projects using the equity method. See Note 3 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

We have entered into a purchase and sale agreement to acquire the equity interests in a coke battery, with an estimated acquisition price of $75 million. The closing of this acquisition is contingent upon the signing of a long-term coke sales agreement, which is currently in negotiation. We expect to close on this acquisition in the first half of 2008.

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.

Energy Trading

Our Energy Trading segment focuses on physical power and gas marketing, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, optimization of contracted natural gas pipelines and storage, and power transmission and generating capacity positions.

Factors impacting income: Net income decreased $64 million in 2007 and increased $139 million in 2006. The decrease in 2007 was attributable to lower gross margins and an increase in other deductions. The 2006 increase is attributed to increased mark-to-market and realized power and gas positions that resulted from significant 2005 mark-to-market losses on derivative contracts used to economically hedge our gas in storage and forward power contracts.


(in Millions)	2007		2006			2005
Operating Revenues	$	955	$	830		$	977
Fuel, Purchased Power and Gas		807		616			984

Gross Margin		148		214			(7	)
Operation and Maintenance		58		65			43
Depreciation and Amortization		5		6			4
Taxes Other Than Income		1		1			(1	)

Operating Income (Loss)		84		142			(53	)
Other (Income) and Deductions		35		(3	)		13
Income Tax Provision (Benefit)		17		49			(23	)

Net Income (Loss)	$	32	$	96		$	(43	)

Gross margin decreased $66 million in 2007 and increased $221 million in 2006. The 2007 decrease is attributed to approximately $30 million of unrealized losses for gas contracts related to revisions of valuation estimates for the long-dated portion of our energy contracts. Timing differences from 2005 that largely reversed and favorably impacted 2006 margin caused $11 million of realized unfavorability in 2007. Additionally, margins were unfavorably impacted by $13 million of lower realized gains from reduced merchant storage capacity in 2007 and $12 million of unfavorability in realized power positions. The 2006 increase is attributed to a $168 million mark-to-market increase on power and gas positions and a $57 million increase in realized power and gas positions. The 2006 results reflect the timing differences from 2005 that largely reversed and favorably impacted earnings.

Operation and maintenance expense decreased $7 million in 2007 and increased $22 million in 2006. The 2007 decrease was due primarily to lower incentive expenses of $7 million. The 2006 increase was due to higher incentive expenses of $14 million resulting from our strong economic performance and higher corporate allocation charges of $10 million.

Other (income) and deductions expense increased by $38 million in 2007 and decreased by $16 million in 2006. The 2007 increase is due to mark-to-market unfavorability on foreign currency swaps that economically hedge exposure on anticipated power sales and existing transportation positions that settle in Canadian dollars. The 2006 decrease is attributable to $6 million of lower intercompany interest expense and $8 million of higher affiliate interest income resulting from favorable operating cash flows to fund intercompany loans.

Outlook - Significant portions of the Energy Trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as capacity positions of natural gas storage, natural gas pipelines, and power transmission and full requirements contracts. The financial instruments are deemed derivatives, whereas the owned gas inventory, pipelines, transmission contracts, certain full requirements contracts 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 assets. The majority of such earnings volatility is associated with the natural gas storage cycle, which does not coincide with the calendar year, but runs annually from April of one year to March of the next year. Our strategy is to economically manage the price risk of storage with futures and over-the-counter forwards and swaps. This results in gains and losses that are recognized in different interim and annual accounting periods.

See “Fair Value of Contracts” section that follows.

CORPORATE & OTHER

Corporate & Other includes various corporate staff functions. As these functions 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 and energy-related investments.

Factors impacting income: Corporate & Other results increased by $563 million in 2007, which is primarily attributable to the gain on the sale of the Antrim shale gas exploration and production business of approximately $900 million ($580 million after-tax). Corporate & Other results declined by $9 million in 2006, primarily due to higher Michigan Single Business Taxes.

DISCONTINUED OPERATIONS

Synthetic Fuel

We discontinued the operations of our synthetic fuel production facilities throughout the United States as of December 31, 2007. Synfuel plants chemically changed coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits were provided for the production and sale of solid synthetic fuel produced from coal and were available through December 31, 2007.

Factors impacting income: Synthetic Fuel net income increased $157 million in 2007 and decreased $257 million in 2006. The increase in 2007 was due to synfuel production occurring throughout the year in comparison to 2006 when production was idled at all nine of our synfuel facilities from May to October 2006 and higher income from oil price hedges, partially offset by a higher phase-out of production tax credits due to high oil prices. The decline in 2006 was also due to higher oil prices resulting in reduced gains from selling interests in our synfuel plants, lower levels of production tax credits and asset impairments and reserves.


(in Millions)	2007			2006			2005
Operating Revenues	$	1,069		$	863		$	927
Operation and Maintenance		1,265			1,019			1,167
Depreciation and Amortization		(6	)		24			58
Taxes other than Income		5			12			20
Asset (Gains) and Losses, Reserves and Impairments, Net (1)		(280	)		40			(367	)

Operating Income (Loss)		85			(232	)		49
Other (Income) and Deductions		(9	)		(20	)		(34	)
Minority Interest		(188	)		(251	)		(318	)
Income Taxes
Provision (Benefit)		98			14			139
Production Tax Credits		(21	)		(23	)		(43	)

		77			(9	)		96

Net Income (1)	$	205		$	48		$	305


(1)		Includes intercompany pre-tax gain of $32 million ($21 million after-tax) for 2007.

Operating revenues increased $206 million in 2007 and decreased $64 million in 2006 due to synfuel production occurring throughout 2007 in comparison to 2006 when production was idled at all nine of our synfuel facilities from May to October 2006.

Operation and maintenance expense increased $246 million in 2007 and decreased $148 million in 2006 due to synfuel production occurring throughout 2007 in comparison to 2006 when production was idled at all nine of our synfuel facilities from May to October 2006.

Depreciation and amortization expense was lower by $30 million in 2007 and $34 million in 2006 as a result of reductions in asset retirement obligations in 2007 and the impairment of fixed assets at all nine synfuel projects in 2006.

Asset (gains) and losses, reserves and impairments, net gain increased $320 million in 2007 and decreased $407 million in 2006. The increase in gains in 2007 reflects the annual partner payment adjustment, recognition of certain fixed gains that were reserved during the comparable 2006 period, higher hedge gains and the impact of one-time impairment charges and fixed note reserves recorded in 2006. In 2007 and 2006, we deferred gains from the sale of the synfuel facilities, including a portion of gains related to fixed payments. Due to the increase in oil prices, we recorded accruals for contractual partners’ obligations of $130 million in 2007 and $79 million in 2006 reflecting the probable refund of amounts equal to our partners’ capital contributions or for operating losses that would normally be paid by our partners. In 2007, we reversed $3 million of other synfuel-related reserves and impairments and in 2006 recorded $78 million of other synfuel-related reserves and impairments. To economically hedge our exposure to the risk of an increase in oil prices and the resulting reduction in 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 net 2007 synfuel hedge mark-to-market gains of $196 million compared with net 2006 synfuel hedge mark-to-market gains of $60 million. See Note 15 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

The following table displays the various pre-tax components that comprise the determination of synfuel gains and losses in 2007, 2006 and 2005.


(in Millions)
Components of Asset (Gains) Losses, Reserves and
Impairments, Net	2007			2006			2005
Gains recognized associated with fixed payments	$	(172	)	$	(43	)	$	(132	)
Gains recognized associated with variable payments		(39	)		(14	)		(187	)

Reserves recorded for contractual partners’ obligations		130			79			—
Other reserves and impairments, including partners’ share (1)		(3	)		78			—
Hedge (gains) losses:
Hedges for 2005 exposure		—			—			(2	)
Hedges for 2006 exposure		—			(66	)		(40	)
Hedges for 2007 exposure		(196	)		6			(6	)

	$	(280	)	$	40		$	(367	)


(1)		Includes $70 million in 2006, representing our partners’ share of the asset impairment, included in Minority Interest.

Minority interest decreased by $63 million and $67 million in 2007 and 2006, respectively. The amounts reflect our partners’ share of operating losses associated with synfuel operations, as well as our partners’ $70 million share of the asset impairment charges in 2006. The 2007 decrease reflects the decreased operating losses due to the 2006 one-time impairment charges, partially offset by increased production in 2007. The decrease in 2006 reflects reduced operating losses due to the idling of production at all nine of our synfuel facilities from May to October 2006, partially offset by our partners’ $70 million share of the asset impairment. 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 $86 million in 2007 and decreased $105 million in 2006, reflecting changes in pre-tax income due to synfuel-related gains, loss reserves and the impairment of fixed assets in 2006.

Outlook – Synfuel production ceased on December 31, 2007. The value of a production tax credit is adjusted annually by an inflation factor and published annually by the Internal Revenue Service (IRS). The value is reduced if the Reference Price of a barrel of oil exceeds certain thresholds. The actual tax credit phase-out for 2007 will not be certain until the Reference Price is published by the IRS in April 2008, and is not expected to result in a material impact to the 2008 financial statements.

DTE Georgetown (Georgetown)

In the fourth quarter of 2006, management approved the marketing of Georgetown, an 80 MW natural gas-fired peaking electric generating plant, for sale. In December 2006, Georgetown met the SFAS No. 144 criteria of an asset “held for sale” and we reported its operating results as a discontinued operation. The plant was sold in July 2007, resulting in gross proceeds of approximately $23 million, which approximated our carrying value. Georgetown did not have significant business activity in 2007 and 2006.

DTE Energy Technologies (Dtech)

See Note 3 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES

Effective January 1, 2007, we adopted FASB Interpretation No. (FIN) 48, Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109. The cumulative effect of the adoption of FIN 48 represented a $5 million reduction to the January 1, 2007 balance of retained earnings.

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

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

CAPITAL RESOURCES AND LIQUIDITY

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. During 2007, our cash requirements were met primarily through operations and short-term borrowings. We believe that we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements.

Our strategic direction anticipates base level capital investments and expenditures for existing businesses in 2008 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 $300 million on growth-related projects within our non-utility businesses in 2008.

Capital spending is expected to increase in 2008 due to higher environmental expenditures. We incurred environmental expenditures of approximately $219 million in 2007 and we expect over $2 billion of future capital expenditures through 2018 to satisfy both existing and proposed new requirements.

We expect non-utility capital spending will approximate $200 million to $350 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 or remarketing in 2008 totals approximately $450 million.


(in Millions)	2007			2006			2005
Cash and Cash Equivalents
Cash Flow From (Used For)
Operating activities:
Net income	$	971		$	433		$	537
Depreciation, depletion and amortization		926			1,014			872
Deferred income taxes		144			28			147
Gain on sale of non-utility business		(900	)		—			—
Gain on sale of synfuel and other assets, net and synfuel impairment		(253	)		28			(405	)
Working capital and other		237			(47	)		(150	)

		1,125			1,456			1,001

Investing activities:
Plant and equipment expenditures – utility		(1,035	)		(1,126	)		(850	)
Plant and equipment expenditures – non-utility		(264	)		(277	)		(215	)
Acquisitions, net of cash acquired		—			(42	)		(50	)
Proceeds from sale of non-utility business		1,262			—			—
Proceeds from sale of synfuels and other assets		417			313			409
Restricted cash and other investments		(50	)		(62	)		(96	)

		330			(1,194	)		(802	)

Financing activities:
Issuance of long-term debt and common stock		50			629			1,041
Redemption of long-term debt		(393	)		(687	)		(1,266	)
Short-term borrowings, net		(47	)		291			437
Repurchase of common stock		(708	)		(61	)		(13	)
Dividends on common stock and other		(370	)		(375	)		(366	)

		(1,468	)		(203	)		(167	)

Net Increase (Decrease) in Cash and Cash Equivalents	$	(13	)	$	59		$	32

Cash from Operating Activities

A majority of our operating cash flow is provided by our electric and gas 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, primarily from the synthetic fuels business, which we believe, subject to considerations discussed below, will provide up to approximately $200 million of cash impacts in 2008 and 2009. We have reported the business activity of the synthetic fuel business as a discontinued operation as of December 31, 2007. Cash flow related to discontinued operations in 2007 includes a gain on sale of interests in synfuel projects of $244 million, after adjusting for impairments, partners’ share of synfuel project losses of $188 million, and contributions from synfuel partners of $229 million.

Cash from operations totaling $1.1 billion in 2007 decreased $331 million from the comparable 2006 period. The operating cash flow comparison primarily reflects a decrease in net income after adjusting for non-cash items (depreciation, depletion and amortization and deferred taxes) and gains on sales of businesses. The decrease was mostly driven by taxes attributable to our non-utility monetization program.

Cash from operations totaling $1.5 billion in 2006 was up $455 million from the comparable 2005 period. The operating cash flow comparison reflects an increase of $352 million in net income, after adjusting for non-cash items (depreciation, depletion, amortization, deferred taxes and gains), and a $103 million decrease in working capital and other requirements. Most of the improvement was driven by higher net income at Detroit Edison that was the result of improved revenues and gross margin stemming from a full

year of higher rates granted in the 2004 electric rate orders and lower customer choice penetration. The working capital improvement was driven by MichCon and resulted primarily from declining GCR factors which had the effect of lowering customer accounts receivable balances. This improvement was partially offset by working capital requirements at Detroit Edison that resulted from pension and VEBA contributions totaling $271 million in 2006.

Outlook — We expect cash flow from operations to increase over the long-term primarily due to improvements from higher earnings at our utilities. We have incurred costs associated with implementation of our Performance Excellence Process, but we began to realize sustained net cost savings in 2007. 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 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 initiatives.

We anticipate approximately $200 million of synfuel-related cash impacts in 2008, which consist of the final reconciliation of cash from synthetic fuel operations (related to activity prior to December 31, 2007), proceeds from option hedges, approximately $100 million of tax credit carryforward utilization and other tax benefits that are expected to reduce future tax payments. The synthetic fuel business is reported as a discontinued operation as of December 31, 2007.

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 or matured fully valued 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 initially invest 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 from investing activities increased $1.5 billion in 2007, due primarily to the sale of our Antrim shale gas exploration and production business and lower capital expenditures.

Net cash outflows relating to investing activities increased $392 million in 2006 compared to 2005. The 2006 change was primarily due to increased capital expenditures. The increase in capital expenditures was driven by environmental expenditures, Enterprise Business Systems development and distribution projects at Detroit Edison, pipeline reliability and inventory management projects at MichCon, and growth-oriented projects across our non-utility segments.

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 our 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 of fixed and variable interest rates and maturity. We continually evaluate our leverage target, which is currently 50% to 52%, 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.

The current credit situation impacts our short-term financing activities, long-term financing activities, and the funding obligations of our defined benefit pension plans. In response, we have undertaken contingency planning efforts to mitigate any adverse impacts to our businesses resulting from the liquidity issues in the credit markets. We have performed an assessment of our ability to obtain financing and do not anticipate any issues with financing in the public or private markets in 2008. With respect to short-term financing, we have the ability to draw on bank lines if there is a further disruption in the commercial paper market. Additionally, a decrease in the fair value of our pension plan assets, which fluctuates based on current market conditions, could result in increased funding requirements to our pension plans. We will continue to monitor developments in the credit markets and the potential impacts on our business.

Net cash used for financing activities increased $1.3 billion in 2007 primarily related to the repurchase of common stock, a decrease in short-term borrowings and the issuance of long-term debt, partially offset by lower debt redemptions.

Net cash used for financing activities increased $36 million during 2006 compared to 2005, due mostly to a decrease in short-term borrowings and the issuance of common stock and long-term debt, partially offset by lower debt redemptions.

See Notes 11, 12, and 13 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

We anticipate approximately $200 million of synfuel-related cash impacts in 2008 and 2009, which consists of cash from operations and proceeds from option hedges, including approximately $100 million of tax credit carryforward utilization and other tax benefits that are expected to reduce future tax payments. As part of a strategic review of our non-utility operations, we have taken and continue to pursue various actions including the sale, restructuring or recapitalization of certain non-utility businesses that generated approximately $900 million in after-tax cash proceeds in 2007 and are expected to generate an additional approximately $800 million in 2008. We have used approximately $725 million to repurchase common stock and approximately $500 million to redeem outstanding debt. In 2008, upon completion of our remaining monetization activities, we expect to repurchase an additional approximately $275 million of common stock and to use approximately $200 million to redeem outstanding debt, assuming the expected asset sales occur. Our objectives for cash redeployment are to increase shareholder value, strengthen the balance sheet and coverage ratios to improve our current credit rating and outlook, and to have any monetizations be accretive to earnings per share.

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

Contractual Obligations

The following table details our contractual obligations for debt redemptions, leases, purchase obligations and other long-term obligations as of December 31, 2007:


			Less
(in Millions)			Than						After
Contractual Obligations	Total		1 Year		1-3 Years		4-5 Years		5 Years
Long-term debt:
Mortgage bonds, notes and other (1)	$	5,933	$	327	$	750	$	1,053	$	3,803
Securitization bonds		1,185		120		272		314		479
Trust preferred-linked securities		289		—		—		—		289
Capital lease obligations (1)		106		15		29		21		41
Interest (1)		6,080		453		847		668		4,112
Operating leases (1)		233		44		64		43		82
Electric, gas, fuel, transportation and storage purchase obligations (2)		5,706		2,898		2,002		166		640
Other long-term obligations (1) (3)		154		43		45		27		39


Total obligations	$	19,686	$	3,900	$	4,009	$	2,292	$	9,485


(1)		Includes obligations associated with assets held for sale of $22 million of other long-term debt, $33 million of capital lease obligations, $9 million of interest, $22 million of operating leases and other long-term obligations of $94 million.

(2)		Excludes amounts associated with full requirements contracts where no stated minimum purchase volume is required.

(3)		Includes liabilities for unrecognized tax benefits of $19 million.

Credit Ratings

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. Management believes that our current credit ratings provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to us may affect our ability to access these funding sources or cause an increase in the return required by investors.

We have issued guarantees for the benefit of various non-utility subsidiaries. In the event that our credit rating is downgraded to below investment grade, certain of these guarantees would require us to post cash or letters of credit valued at approximately $488 million at December 31, 2007. Additionally, upon a downgrade, our trading business could be required to restrict operations and our access to the short-term commercial paper market could be restricted or eliminated. While we currently do not anticipate such a downgrade, we cannot predict the outcome of current or future credit rating agency reviews. The following table shows our credit rating as determined by three nationally respected credit rating agencies. All ratings are considered investment grade and affect the value of the related securities.


		Credit Rating Agency
		Standard &	Moody’s	Fitch
Entity	Description	Poor’s	Investors Service	Ratings
DTE Energy	Senior Unsecured Debt	BBB-	Baa2	BBB
	Commercial Paper	A-2	P-2	F2

Detroit Edison	Senior Secured Debt	A-	A3	A-
	Commercial Paper	A-2	P-2	F2

MichCon	Senior Secured Debt	BBB+	A3	A-
	Commercial Paper	A-2	P-2	F2

CRITICAL ACCOUNTING ESTIMATES

There are estimates used in preparing the consolidated financial statements that require considerable judgment. Such estimates relate to regulation, risk management and trading activities, allowance for doubtful accounts, goodwill, pension and postretirement costs, legal reserves, insured and uninsured risks, accounting for tax obligations and production tax credits.

Regulation

A significant portion of our business is subject to regulation. Detroit Edison and MichCon currently meet the criteria of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Application of this standard results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses. SFAS No. 71 requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Future regulatory changes or changes in the competitive environment could result in discontinuing the application of SFAS No. 71 for some or all of our businesses. Management believes that currently available facts support the continued application of SFAS No. 71 and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment. See Note 5 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Risk Management and Trading Activities

Risk management and trading activities are accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. As amended, SFAS No. 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. All derivatives are recorded at fair value and shown as “Assets or liabilities from risk management and trading activities” in the Consolidated Statements of Financial Position. Derivatives are measured at fair value, and changes in the fair value of the derivative instruments are recognized in earnings in the period of change, unless the derivative meets certain defined conditions and qualifies as an effective hedge. SFAS No. 133 also provides a scope exception for contracts that meet the normal purchase and sales criteria specified in the standard. The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchases and normal sales are not recorded at fair value. A majority of the contracts entered into by Detroit Edison and MichCon meet the criteria specified for this exception. The fair values of derivative contracts are determined from a combination of active quotes, published indexes and mathematical valuation models. Valuation models require various inputs and assumptions, including forward prices, volatility, interest rates, and exercise periods. The fair values we calculate for our derivatives may change significantly as inputs and assumptions are updated for new information. The cash returns we actually realize on our derivatives may be different from the results we estimate using models.

Allowance for Doubtful Accounts

We establish an allowance for doubtful accounts based upon factors surrounding the credit risk of specific customers, historical trends, economic conditions, age of receivables and other information. Higher customer bills due to increased electricity and gas prices, the lack of adequate levels of assistance for low-income customers and economic conditions have also contributed to the increase in past due receivables. As a result of these factors, our allowance for doubtful accounts increased in 2007 and 2006. We believe the allowance for doubtful accounts is based on reasonable estimates. As part of the 2005 gas rate order for MichCon, the MPSC provided for the establishment of an uncollectible accounts tracking mechanism that partially mitigates the impact associated with MichCon uncollectible expenses. However, failure to make continued progress in collecting our past due receivables in light of rising energy prices would unfavorably affect operating results and cash flow.

Goodwill

Certain of our business units have goodwill resulting from purchase business combinations. In accordance with SFAS No. 142, Goodwill and Other Intangible Assets, each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In order to perform these impairment tests, we must determine the reporting unit’s fair value using valuation techniques, which use estimates of discounted future cash flows to be generated by the reporting unit. These cash flow valuations involve a number of estimates that require broad assumptions and significant judgment by management regarding future performance. To the extent estimated cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill, which would adversely impact our earnings.

As of December 31, 2007, our goodwill totaled $2 billion. The majority of our goodwill is allocated to our utility reporting units. The value of the utility reporting units may be significantly impacted by rate orders and the regulatory environment.

Based on our 2007 goodwill impairment test, we determined that the fair value of our remaining operating reporting units exceeded their carrying value and no impairment existed. We will continue to monitor our estimates and assumptions regarding future cash flows. While we believe our assumptions are reasonable, actual results may differ from our projections.

Pension and Postretirement Costs

Our costs of providing pension and postretirement benefits are dependent upon a number of factors, including rates of return on plan assets, the discount rate, the rate of increase in health care costs and the amount and timing of plan sponsor contributions.

We had pension costs for qualified pension plans of $67 million in 2007 (including Special Termination Benefits of $8 million), $125 million in 2006 (including Special Termination Benefits of $49 million), and $90 million in 2005. Postretirement benefits costs for all plans were $188 million in 2007 (including Special Termination Benefits of $2 million), $197 million in 2006 (including Special Termination Benefits of $8 million), and $155 million in 2005. Pension and postretirement benefits costs for 2007 are calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on our plan assets of 8.75%. In developing our expected long-term rate of return assumption, we evaluated asset class risk and return expectations, as well as inflation assumptions. Projected returns are based on broad equity and bond markets. Our 2008 expected long-term rate of return on plan assets is based on an asset allocation assumption utilizing active investment management of 55% in equity markets, 20% in fixed income markets, and 25% invested in other assets. Because of market volatility, we periodically review our asset allocation and rebalance our portfolio when considered appropriate. Given market conditions, we believe that 8.75% is a reasonable long-term rate of return on our plan assets for 2008. We will continue to evaluate our actuarial assumptions, including our expected rate of return, at least annually.

We base our determination of the expected return on qualified plan assets on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes changes in fair value in a systematic manner over a three-year period. Accordingly, the future value of assets will be impacted as previously deferred gains or losses are recorded. We have unrecognized net gains due to the performance of the financial markets. As of December 31, 2007, we had $63 million of cumulative gains that remain to be recognized in the calculation of the market-related value of assets.

The discount rate that we utilize for determining future pension and postretirement benefit obligations is based on a yield curve approach and a review of bonds that receive one of the two highest ratings given by a recognized rating agency. The yield curve approach matches projected plan pension and postretirement benefit payment streams with bond portfolios reflecting actual liability duration unique to our plans. The discount rate determined on this basis increased from 5.7% at December 31, 2006 to 6.5%

at December 31, 2007. Due to recent company contributions, financial market performance and higher discount rates, we estimate that our 2008 total pension costs will approximate $29 million compared to $67 million in 2007 and our 2008 postretirement benefit costs will approximate $146 million compared to $188 million in 2007. In the last several years, we have made modifications to the pension and postretirement benefit plans to mitigate the earnings impact of higher costs. Future actual pension and postretirement benefit costs will depend on future investment performance, changes in future discount rates and various other factors related to plan design. Additionally, future pension costs for Detroit Edison will be affected by a pension tracking mechanism, which was authorized by the MPSC in its November 2004 electric rate order. The tracking mechanism provides for the recovery or refunding of pension costs above or below the amount reflected in Detroit Edison’s base rates. In April 2005, the MPSC approved the deferral of the non-capitalized portion of MichCon’s negative pension expense. MichCon will record a regulatory liability for any negative pension costs, as determined under generally accepted accounting principles.

Lowering the expected long-term rate of return on our plan assets by one-percentage-point would have increased our 2007 qualified pension costs by approximately $26 million. Lowering the discount rate and the salary increase assumptions by one-percentage-point would have increased our 2007 pension costs by approximately $10 million. Lowering the health care cost trend assumptions by one-percentage-point would have decreased our postretirement benefit service and interest costs for 2007 by approximately $24 million.

The market value of our pension and postretirement benefit plan assets has been affected in a positive manner by the financial markets. The value of our plan assets was $3.5 billion at November 30, 2006 and $3.8 billion at November 30, 2007. At December 31, 2006, we adopted SFAS No. 158 that required us to recognize the underfunded status of our pension and other postretirement plans. The impact of the adoption of SFAS No. 158 was an increase in pension and postretirement benefit liabilities of approximately $1.3 billion in 2006. We requested and received agreement from the MPSC to record the additional liability amounts for the Detroit Edison and MichCon benefit plans on the Statement of Financial Position as a Regulatory asset. As a result, Regulatory assets were increased by approximately $1.2 billion. The remainder of the increase in pension and postretirement benefit liabilities is included in Accumulated other comprehensive loss, net of tax. At December 31, 2007 our qualified pension plans were overfunded by $152 million, our non-qualified pension plans were underfunded by $71 million, and our other postretirement benefit plans were underfunded by $1.1 billion, reflected in noncurrent assets, current liabilities, and noncurrent liabilities, respectively. The improvement relative to 2006 results from Company contributions, investment performance returns, and increased discount rates.

Pension and postretirement costs and pension cash funding requirements may increase in future years without substantial returns in the financial markets. We made a $180 million pension contribution in 2006 and made a $150 million pension contribution in 2007. At the discretion of management and depending upon financial market conditions, we anticipate making up to a $150 million contribution to our qualified pension plans in 2008 and up to $400 million over the next five years. Also, we anticipate making up to a $5 million contribution to our nonqualified benefit plans in 2008 and up to $25 million over the next five years. We made a $116 million contribution to our postretirement benefit plans in 2006 and made a $76 million contribution to our postretirement benefit plans in 2007. At the discretion of management, and depending upon financial market conditions, we anticipate making up to a $116 million contribution to our postretirement plans in 2008 and up to $600 million over the next five years.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act was signed into law. This Act provides for a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the benefit established by law. The effects of the subsidy on the measurement of net periodic postretirement benefit costs reduced costs by $16 million in 2007, $17 million in 2006, and $20 million in 2005.

See Note 17 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Legal Reserves

We are involved in various legal proceedings, claims and litigation arising in the ordinary course of business. We regularly assess our liabilities and contingencies in connection with asserted or potential matters, and establish reserves when appropriate. Legal reserves are based upon management’s assessment of pending and threatened legal proceedings and claims against us.

Insured and Uninsured Risks

Our comprehensive insurance program provides coverage for various types of risks. Our insurance policies cover risk of loss including property damage, general liability, workers’ compensation, auto liability, and directors’ and officers’ liability. Under our risk management policy, we self-insure portions of certain risks up to specified limits, depending on the type of exposure. The maximum self-insured retention for various risks is as follows: property damage — $10 million, general liability — $7 million, workers’ compensation — $8.5 million, and auto liability — $7 million. We have an actuarially determined estimate of our incurred but not reported (IBNR) liability prepared annually and we adjust our reserves for self-insured risks as appropriate. As of December 31, 2007, this IBNR liability was approximately $40 million.

Accounting for Tax Obligations

We are required to make judgments regarding the potential tax effects of various financial transactions and results of operations in order to estimate our obligations to taxing authorities. Beginning January 1, 2007, we began accounting for uncertain income tax positions using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement in accordance with FIN 48, Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109. If the benefit does not meet the more likely than not criteria for being sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. Prior to January 1, 2007, we estimated uncertain income tax obligations in accordance with SFAS No. 109, Accounting for Income Taxes, SFAS No. 5, Accounting for Contingencies and Statement of Financial Accounting Concepts No. 6 (CON 6), Elements of Financial Statements. We also have non-income tax obligations related to real estate, sales and use and employment-related taxes and ongoing appeals related to these tax matters that are outside the scope of FIN 48 and accounted for under SFAS No. 5 and CON 6.

Accounting for tax obligations requires judgments, including assessing whether tax benefits are more likely than not to be sustained, and estimating reserves for potential adverse outcomes regarding tax positions that have been taken. We also assess our ability to utilize tax attributes, including those in the form of carryforwards, for which the benefits have already been reflected in the financial statements. We do not record valuation allowances for deferred tax assets related to capital losses that we believe will be realized in future periods. While we believe the resulting tax reserve balances as of December 31, 2007 and December 31, 2006 are appropriately accounted for in accordance with FIN 48, SFAS No. 5, SFAS No. 109 and CON 6 as applicable, the ultimate outcome of such matters could result in favorable or unfavorable adjustments to our consolidated financial statements and such adjustments could be material.

Production Tax Credits

We generated production tax credits from our synfuel operations through December 31, 2007. Our coke battery and landfill gas recovery operations also generate production tax credits with varying expiration dates. We recognize earnings as tax credits are generated at our facilities in one of two ways. First, to the extent we have sold an interest in our synfuel facilities to third parties, we recognize gains as synfuel is produced and sold, and when there is persuasive evidence that the sales proceeds have become fixed or determinable, when probability of refund is considered remote and collectibility is reasonably assured. Second, to the extent we generate credits to our own account, we recognize earnings through reduced tax expense.

All production tax credits are subject to audit by the IRS. However, all of our synfuel facilities have received favorable private letter rulings from the IRS with respect to their operations. Audits of five of our synfuel facilities were successfully completed in the past two years. If production tax credits were disallowed in whole or in part as a result of an IRS audit, there could be a significant write-off of previously recorded earnings from such tax credits.

Tax credits generated by our facilities were $217 million in 2007 as compared to $295 million in 2006, and $617 million in 2005. The portion of tax credits generated for our own account was $31 million in 2007, as compared to $35 million in 2006, and $55 million in 2005, with the remaining credits generated allocated to third party partners.

Tax credits related to synfuels are classified as income from discontinued operations in our consolidated statement of operations.

ENVIRONMENTAL MATTERS

Protecting the environment, as well as correcting past environmental damage, continues to be a focus of state and federal regulators. Legislation and/or rulemaking could further impact the electric utility industry including Detroit Edison. The EPA and the MDEQ have aggressive programs to clean up contaminated property.

Electric Utility

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, the EPA issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, Detroit Edison has spent approximately $1.1 billion through 2007. We estimate Detroit Edison will incur future capital expenditures of up to $282 million in 2008 and up to $2.4 billion of additional capital expenditures through 2018 to satisfy both the existing and proposed new control requirements.

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

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

Water – In response to an EPA regulation, currently under judicial review, Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of the studies to be conducted over the next several years, Detroit Edison may be required to install additional control technologies to reduce the impacts of the intakes. Initially, we estimated that we will incur up to approximately $55 million over the next four to six years in additional capital expenditures to comply with these requirements. However, a recent court decision remanded back to the EPA several provisions of the federal regulation that has resulted in a delay in compliance requirements. The court decision also raised the possibility that we may have to

install cooling towers at some facilities, substantially increasing capital expenditures. We cannot predict the effect on Detroit Edison of this court decision or any resulting regulations.

Contaminated Sites – Detroit Edison conducted remedial investigations at contaminated sites, including three former MGP sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. We have a reserve balance of $15 million as of December 31, 2007 for the remediation of these sites over the next several years. In addition, Detroit Edison expects to make approximately $6 million of capital improvements to the ash landfill in 2008.

Gas Utility

Contaminated 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. Gas Utility owns, or previously owned, 15 former MGP sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, Gas Utility is also in the process of cleaning up other contaminated sites. Cleanup activities associated with these sites will be conducted over the next several years. As a result of these determinations, we have recorded liabilities of $40 million and $2 million for the MGP and other contaminated sites, respectively. It is estimated that Gas Utility may spend $6 million in expenses related to cleanup costs in 2008.

A cost deferral and rate recovery mechanism was approved by the MPSC for investigation and remediation costs incurred at former MGP sites. After a study was completed in 1995, Gas Utility accrued an additional liability and a corresponding regulatory asset of $35 million. During 2007, we spent approximately $2 million investigating and remediating these former MGP sites. We accrued an additional $1 million in remediation liabilities associated with former MGP holders to increase the reserve balance to $40 million as of December 31, 2007.

Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and thereby affect our financial position and cash flows. However, we anticipate the cost deferral and rate recovery mechanism approved by the MPSC will prevent environmental costs from having a material adverse impact on our consolidated results of operations.

Other

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 project to be substantially completed during 2009 at a cost of approximately $15 million. Our non-utility affiliates are substantially in compliance with all environmental requirements.

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

NEW ACCOUNTING PRONOUNCEMENTS

See Note 2 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

FAIR VALUE OF CONTRACTS

The accounting standards for determining whether a contract meets the criteria for derivative accounting are numerous and complex. Moreover, significant judgment is required to determine whether a contract requires derivative accounting, and similar contracts can sometimes be accounted for differently. If a contract is accounted for as a derivative instrument, it is recorded in the financial statements as “Assets or Liabilities from risk management and trading activities,” at the fair value of the contract. The recorded fair value of the contract is then adjusted at each reporting date, in the Consolidated Statements of Operations, to reflect any change in the fair value of the contract, a practice known as mark-to-market (MTM) accounting. Changes in the fair value of a designated derivative that is highly effective as a cash flow hedge are recorded as a component of Accumulated other comprehensive income, net of taxes, until the hedged item affects income. These amounts are subsequently reclassified into earnings as a component of the value of the forecasted transaction, in the same period as the forecasted transaction affects earnings. The ineffective portion of the fair value changes is recognized in the Consolidated Statements of Operations immediately.

Fair value represents the amount at which willing parties would transact an arms-length transaction. To determine the fair value of contracts accounted for as derivative instruments, we use a combination of quoted market prices, broker quotes and mathematical valuation models. Valuation models require various inputs, including forward prices, volatility, interest rates, and exercise periods.

Contracts we typically classify as derivative instruments include power, gas, certain coal, and oil forwards, futures, options and swaps, as well as foreign currency contracts. Items we do not generally account for as derivatives (and which are therefore excluded from the following tables) include gas inventory, gas storage and transportation arrangements, and gas and oil reserves.

The subsequent tables contain the following four categories represented by their operating characteristics and key risks.

	•		“Proprietary Trading” represents derivative activity transacted with the intent of taking a view, capturing market price changes, or putting capital at risk. This activity is speculative in nature as opposed to hedging an existing exposure.

	•		“Structured Contracts” represents derivative activity transacted by originating substantially hedged positions with wholesale energy marketers, producers, end users, utilities, retail aggregators and alternative energy suppliers. Although transactions are generally executed with a buyer and seller simultaneously, some positions remain open until a suitable offsetting transaction can be executed.

	•		“Economic Hedges” represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas production and trades associated with owned transportation and storage capacity. Changes in the value of derivatives in this category economically offset changes in the value of underlying non-derivative positions, which do not qualify for fair value accounting. The difference in accounting treatment of derivatives in this category and the underlying non-derivative positions can result in significant earnings volatility.

	•		“Other” primarily represents derivative activity associated with our gas reserves and discontinued synfuel operations. A portion of the price risk associated with anticipated production from the Barnett gas reserves has been mitigated through 2010. Changes in the value of the hedges are recorded as “Assets or Liabilities from risk management and trading activities,” with an offset in Other comprehensive income to the extent that the hedges are deemed effective. Oil-related derivative contracts were executed to economically hedge cash flow risks related to underlying, non-derivative synfuel related positions through 2007. The amounts shown in the following tables exclude the value of the underlying gas reserves and synfuel proceeds including changes therein.

Roll-Forward of MTM Energy Contract Net Assets

The following tables provide details on changes in our MTM net asset (or liability) position during 2007:


	Proprietary			Structured			Economic
(in Millions)	Trading			Contracts			Hedges			Other			Total
MTM at December 31, 2006	$	(9	)	$	(2	)	$	(36	)	$	(24	)	$	(71	)

Reclassed to realized upon settlement		22			1			17			16			56
Changes in fair value recorded to income		4			(57	)		23			(220	)(1)		(250	)
Amortization of option premiums		(10	)		(2	)		—			(101	)(2)		(113	)

Amounts recorded to unrealized income		16			(58	)		40			(305	)		(307	)
Amounts recorded in Other comprehensive Income		—			—			—			(1	)		(1	)
Transfer of contracts		—			(323	)		—			323			—
Option premiums paid and other		1			37			—			9			47

MTM at December 31, 2007	$	8		$	(346	)	$	4		$	2		$	(332	)


(1)		Change in fair value of contracts in Unconventional Gas Production prior to the transfer to Energy Trading as a result of the Antrim sale.

(2)		Realized synfuel option premiums by Power and Industrial Projects.

A substantial portion of the Company’s price risk related to its Antrim shale gas exploration and production business had been mitigated by financial contracts that hedged our price risk exposure through 2013. These financial contracts were accounted for as cash flow hedges, with changes in estimated fair value of the contracts reflected in Other comprehensive income. Upon the sale of Antrim, the financial contracts no longer qualified as cash flow hedges. The contracts were retained and offsetting financial contracts were put into place to effectively settle these positions.

The following table provides a current and noncurrent analysis of “Assets and Liabilities from risk management and trading activities,” as reflected on the Consolidated Statements of Financial Position as of December 31, 2007. Amounts that relate to contracts that become due within twelve months are classified as current and all remaining amounts are classified as noncurrent.


	Proprietary			Structured			Economic									Assets
(in Millions)	Trading			Contracts			Hedges			Eliminations			Other			(Liabilities)
Current assets	$	35		$	135		$	29		$	(9	)	$	5		$	195
Noncurrent assets		9			194			8			(4	)		—			207

Total MTM assets		44			329			37			(13	)		5			402


Current liabilities		(34	)		(234	)		(23	)		9			—			(282	)
Noncurrent liabilities		(2	)		(441	)		(10	)		4			(3	)		(452	)

Total MTM liabilities		(36	)		(675	)		(33	)		13			(3	)		(734	)


Total MTM net assets (liabilities)	$	8		$	(346	)	$	4		$	—		$	2		$	(332	)

Maturity of Fair Value of MTM Energy Contract Net Assets

We manage our MTM risk on a portfolio basis based upon the delivery period of our contracts and the individual components of the risks within each contract. Accordingly, we record and manage the energy purchase and sale obligations under our contracts in separate components based on the commodity (e.g. electricity or gas), the product (e.g. electricity for delivery during peak or off-peak hours), the delivery location (e.g. by region), the risk profile (e.g. forward or option), and the delivery period (e.g. by month and year).

We determine the MTM adjustment for our derivative contracts from a combination of active quotes, published indexes and mathematical valuation models. We generally derive the pricing for our contracts from active quotes or external resources. Actively quoted indexes include exchange-traded positions such as the New York Mercantile Exchange and the Intercontinental Exchange, and over-the-counter positions for which broker quotes are available. For periods in which external market data is not readily observable, we estimate value using mathematical valuation models. We periodically update our policy and valuation methodologies for changes in market liquidity and other assumptions which may impact the estimated fair value of our derivative contracts. During 2007, we performed an analysis of the energy markets and its participants, including an evaluation of liquidity. As a result, we revised our policy and valuation estimates for the portions of our contracts that extend beyond the actively traded reporting period. Accordingly, our power and natural gas contracts are marked through 2011 and 2013, respectively. The majority of our long-dated power contracts relate to retail or structured transactions, which require the use of internal models to estimate fair value.

As a result of adherence to generally accepted accounting principles, the tables above do not include the expected earnings impacts of certain non-derivative gas storage and power contracts. Consequently, gains and losses from these positions may not match with the related physical and financial hedging instruments in some reporting periods, resulting in volatility in DTE Energy’s reported period-by-period earnings; however, the financial impact of this timing difference will reverse at the time of physical delivery and/or settlement.

The table below shows the maturity of our MTM positions:


										2011
(in Millions)										and			Total Fair
Source of Fair Value	2008			2009			2010			Beyond			Value
Proprietary Trading	$	1		$	7		$	—		$	—		$	8
Structured Contracts		(99	)		(78	)		(52	)		(117	)		(346	)
Economic Hedges		6			—			(2	)		—			4
Other		5			(2	)		(1	)		—			2

Total	$	(87	)	$	(73	)	$	(55	)	$	(117	)	$	(332	)

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Price Risk

DTE Energy has commodity price risk in both utility and non-utility businesses arising from market price fluctuations.

The Electric and Gas utility businesses have risks in conjunction with the anticipated purchases of coal, natural gas, uranium, electricity, and base metals to meet their service obligations. Further, changes in the price of electricity can impact the level of exposure of Customer Choice programs and uncollectible expenses at the Electric Utility. In addition, changes in the price of natural gas can impact the valuation of lost gas, storage sales revenue and uncollectible expenses at the Gas Utility.

To limit our exposure to commodity price fluctuations, the utility businesses have applied various approaches including forward energy, capacity, storage and futures contracts, as well as regulatory rate-recovery mechanisms. Regulatory rate-recovery occurs in the form of PSCR and GCR mechanisms (see Note 1 of the Notes to Consolidated Financial Statements in Item 8 of this Report) and a tracking mechanism to mitigate some losses from customer migration due to electric Customer Choice programs.

Our Power and Industrial Projects segment is subject to crude oil, electricity, natural gas and coal based product price risk. As previously discussed, production tax credits generated by DTE Energy’s coke battery and landfill gas recovery operations are subject to phase-out if domestic crude oil prices reach certain levels. The benefits associated with tax credits may be subject to changes in federal tax law. See Note 15 of the Notes to Consolidated Financial Statements in Item 8 of this Report. To manage this exposure, we use forward energy, capacity and futures contracts.

Our Unconventional Gas Production business segment has exposure to natural gas and, to a lesser extent, crude oil price fluctuations. These commodity price fluctuations can impact both current year earnings and reserve valuations. To manage this exposure we use forward energy and futures contracts.

Our Energy Trading business segment has exposure to electricity, natural gas, crude oil, heating oil, and foreign currency price fluctuations. These risks are managed through its energy marketing and trading operations through the use of forward energy, capacity, storage, options and futures contracts, within pre-determined risk parameters.

Our Coal and Gas Midstream business segment has exposure to natural gas and coal price fluctuations. These coal price risks are managed primarily through its coal transportation and marketing operations through the use of forward coal and futures contracts. The Gas Midstream business unit manages its exposure through the sale of long-term storage and transportation contracts.

Credit Risk

Bankruptcies

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

Other

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

Energy Trading

We are exposed to credit risk through trading activities. Credit risk is the potential loss that may result if our trading counterparties fail to meet their contractual obligations. We utilize both external and internally generated credit assessments when determining the credit quality of our trading counterparties. The following table displays the credit quality of our trading counterparties as of December 31, 2007:


	Credit Exposure
	before Cash		Cash			Net Credit
(in Millions)	Collateral		Collateral			Exposure
Investment Grade (1)
A- and Greater	$	612	$	(100	)	$	512
BBB+ and BBB		104		—			104
BBB-		46		—			46

Total Investment Grade		762		(100	)		662
Non-investment grade (2)		38		(5	)		33
Internally Rated – investment grade (3)		98		(1	)		97
Internally Rated – non-investment grade (4)		10		(8	)		2

Total	$	908	$	(114	)	$	794


(1)		This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s Investor Service (Moody’s) and BBB- assigned by Standard & Poor’s Rating Group, a division of the McGraw-Hill Companies, Inc. (Standard & Poor’s). The five largest counterparty exposures combined for this category represented approximately 34 percent of the total gross credit exposure.

(2)		This category includes counterparties with credit ratings that are below investment grade. The five largest counterparty exposures combined for this category represented approximately three percent of the total gross credit exposure.

(3)		This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, but are considered investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately seven percent of the total gross credit exposure.

(4)		This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, and are considered non-investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately one percent of the total gross credit exposure.

Interest Rate Risk

DTE Energy is subject to interest rate risk in connection with the issuance of debt and preferred securities. In order to manage interest costs, we may use treasury locks and interest rate swap agreements. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). As of December 31, 2007, we had a floating rate debt-to-total debt ratio of approximately 18% (excluding securitized debt).

Foreign Currency Risk

DTE Energy has foreign currency exchange risk arising from market price fluctuations associated with fixed priced contracts. These contracts are denominated in Canadian dollars and are primarily for the purchase and sale of power as well as for long-term transportation capacity. To limit our exposure to foreign currency fluctuations, we have entered into a series of currency forward contracts through January

2012. Additionally, we may enter into fair value currency hedges to mitigate changes in the value of contracts or loans.

Summary of Sensitivity Analysis

We performed a sensitivity analysis on the fair values of our commodity contracts, long-term debt instruments and foreign currency forward contracts. The sensitivity analysis involved increasing and decreasing forward rates at December 31, 2007 by a hypothetical 10% and calculating the resulting change in the fair values.

The results of the sensitivity analysis calculations follow:


(in Millions)	Assuming a 10%			Assuming a 10%
Activity	increase in rates			decrease in rates			Change in the fair value of
Coal Contracts	$	(2	)	$	2		Commodity contracts
Gas Contracts	$	(13	)	$	13		Commodity contracts
Power Contracts	$	(13	)	$	13		Commodity contracts
Interest Rate Risk	$	(290	)	$	315		Long-term debt
Foreign Currency Risk	$	1		$	(1	)	Forward contracts

Item 8. Financial Statements and Supplementary Data

The following consolidated financial statements and schedules are included herein.


		Page
Controls and Procedures			70
Reports of Independent Registered Public Accounting Firm			72
Consolidated Statements of Operations			74
Consolidated Statements of Financial Position			75
Consolidated Statements of Cash Flows			77
Consolidated Statements of Changes in Shareholders’ Equity and Comprehensive Income			78
Notes to Consolidated Financial Statements
Note 1	Significant Accounting Policies		79
Note 2	New Accounting Pronouncements		86
Note 3	Disposals and Discontinued Operations		88
Note 4	Other Impairments and Restructuring		92
Note 5	Regulatory Matters		93
Note 6	Nuclear Operations		102
Note 7	Jointly Owned Utility Plant		105
Note 8	Income Taxes		106
Note 9	Common Stock		109
Note 10	Earnings Per Share		109
Note 11	Long-Term Debt		110
Note 12	Preferred Securities		112
Note 13	Short-Term Credit Arrangements and Borrowings		112
Note 14	Capital and Operating Leases		114
Note 15	Financial and Other Derivative Instruments		114
Note 16	Commitments and Contingencies		117
Note 17	Retirement Benefits and Trusteed Assets		120
Note 18	Stock-based Compensation		129
Note 19	Segment and Related Information		133
Note 20	Supplementary Quarterly Financial Information (Unaudited)		137
	Schedule II — Valuation and Qualifying Accounts		144

Controls and Procedures

(a) Evaluation of disclosure controls and procedures

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

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

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

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

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

The Company’s independent registered public accounting firm that audited the financial statements included in this annual report has issued an attestation report on the Company’s internal control over financial reporting.

(c) Changes in internal control over financial reporting

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

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

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

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of DTE Energy Company:

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

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

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

As discussed in Note 8 to the consolidated financial statements, in connection with the required adoption of a new accounting standard, the Company changed its method of accounting for uncertainty in income taxes on January 1, 2007. As discussed in Notes 17 and 18 to the consolidated financial statements, in connection with the required adoption of new accounting standards, in 2006 the Company changed its method of accounting for defined benefit pension and other postretirement plans and share based payments, respectively. As discussed in Note 1 to the consolidated financial statements, in connection with the required adoption of new accounting standards, in 2005 the Company changed its method of accounting for asset retirement obligations.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 7, 2008 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/S/ DELOITTE & TOUCHE LLP

Detroit, Michigan
March 7, 2008

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of DTE Energy Company:

We have audited the internal control over financial reporting of DTE Energy Company and subsidiaries (the “Company”) as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2007 of the Company and our report dated March 7, 2008 expressed an unqualified opinion on those consolidated financial statements and financial statement schedules and included an explanatory paragraph regarding the Company’s adoption of new accounting standards.

/S/ DELOITTE & TOUCHE LLP

Detroit, Michigan
March 7, 2008

DTE Energy Company

Consolidated Statements of Operations


	Year Ended December 31
(in Millions, Except per Share Amounts)	2007			2006			2005
Operating Revenues	$	8,506		$	8,159		$	8,094


Operating Expenses
Fuel, purchased power and gas		3,553			3,056			3,530
Operation and maintenance		2,892			2,677			2,625
Depreciation, depletion and amortization		932			990			810
Taxes other than income		357			309			254
Gain on sale of non-utility business (Note 3)		(900	)		—			—
Other asset (gains) and losses, reserves and impairments, net		37			67			(23	)

		6,871			7,099			7,196


Operating Income		1,635			1,060			898


Other (Income) and Deductions
Interest expense		533			525			518
Interest income		(25	)		(26	)		(22	)
Other income		(93	)		(61	)		(68	)
Other expenses		65			86			55

		480			524			483


Income Before Income Taxes and Minority Interest		1,155			536			415

Income Tax Provision		364			146			106

Minority Interest		4			1			37


Income from Continuing Operations		787			389			272

Discontinued Operations
Loss from discontinued operations, net of tax		4			208			50
Minority interest in discontinued operations		(188	)		(251	)		(318	)

		184			43			268

Cumulative Effect of Accounting Changes, net of tax		—			1			(3	)


Net Income	$	971		$	433		$	537


Basic Earnings per Common Share
Income from continuing operations	$	4.64		$	2.19		$	1.56
Discontinued operations		1.09			.24			1.53
Cumulative effect of accounting changes		—			.01			(.02	)

Total	$	5.73		$	2.44		$	3.07


Diluted Earnings per Common Share
Income from continuing operations	$	4.62		$	2.18		$	1.55
Discontinued operations		1.08			.24			1.52
Cumulative effect of accounting changes		—			.01			(.02	)

Total	$	5.70		$	2.43		$	3.05


Weighted Average Common Shares Outstanding
Basic		169			177			175
Diluted		170			178			176
Dividends Declared per Common Share	$	2.12		$	2.075		$	2.06

See Notes to Consolidated Financial Statements

DTE Energy Company

Consolidated Statements of Financial Position


	December 31
(in Millions)	2007			2006
ASSETS
Current Assets
Cash and cash equivalents	$	123		$	147
Restricted cash		140			146
Accounts receivable (less allowance for doubtful accounts of $182 and $170, respectively)
Customer		1,658			1,427
Collateral held by others		56			68
Other		448			442
Accrued power and gas supply cost recovery revenue		76			117
Inventories
Fuel and gas		429			562
Materials and supplies		204			153
Deferred income taxes		387			245
Assets from risk management and trading activities		195			461
Other		196			193
Current assets held for sale		83			—

		3,995			3,961


Investments
Nuclear decommissioning trust funds		824			740
Other		446			505

		1,270			1,245


Property
Property, plant and equipment		18,809			19,224
Less accumulated depreciation and depletion		(7,401	)		(7,773	)

		11,408			11,451


Other Assets
Goodwill		2,037			2,057
Regulatory assets		2,786			3,226
Securitized regulatory assets		1,124			1,235
Intangible assets		25			72
Notes receivable		87			164
Assets from risk management and trading activities		207			164
Prepaid pension assets		152			71
Other		116			139
Noncurrent assets held for sale		547			—

		7,081			7,128


Total Assets	$	23,754		$	23,785

See Notes to Consolidated Financial Statements

DTE Energy Company
Consolidated Statements of Financial Position


	December 31
(in Millions, Except Shares)	2007			2006
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	1,198		$	1,145
Accrued interest		112			115
Dividends payable		87			94
Short-term borrowings		1,084			1,131
Current portion long-term debt, including capital leases		454			354
Liabilities from risk management and trading activities		282			437
Deferred gains and reserves		400			208
Other		566			680
Current liabilities associated with assets held for sale		48			—

		4,231			4,164


Long-Term Debt (net of current portion)
Mortgage bonds, notes and other		5,576			5,918
Securitization bonds		1,065			1,185
Trust preferred-linked securities		289			289
Capital lease obligations		41			82

		6,971			7,474


Other Liabilities
Deferred income taxes		1,824			1,465
Regulatory liabilities		1,168			765
Asset retirement obligations		1,277			1,221
Unamortized investment tax credit		108			120
Liabilities from risk management and trading activities		452			259
Liabilities from transportation and storage contracts		126			157
Accrued pension liability		68			388
Accrued postretirement liability		1,094			1,414
Deferred gains		15			36
Nuclear decommissioning		134			119
Other		303			312
Noncurrent liabilities associated with assets held for sale		82			—

		6,651			6,256


Commitments and Contingencies (Notes 5, 6, and 16)

Minority Interest		48			42


Shareholders’ Equity
Common stock, without par value, 400,000,000 shares authorized, 163,232,095 and 177,138,060 shares issued and outstanding, respectively		3,176			3,467
Retained earnings		2,790			2,593
Accumulated other comprehensive loss		(113	)		(211	)

		5,853			5,849


Total Liabilities and Shareholders’ Equity	$	23,754		$	23,785

See Notes to Consolidated Financial Statements

DTE Energy Company

Consolidated Statements of Cash Flows


	Year Ended December 31
(in Millions)	2007			2006			2005
Operating Activities
Net income	$	971		$	433		$	537
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		926			1,014			872
Deferred income taxes		144			28			147
Gain on sale of non-utility business		(900	)		—			—
Other asset (gains), losses and reserves, net		(9	)		(11	)		(38	)
Gain on sale of interests in synfuel projects		(248	)		(38	)		(367	)
Impairment of synfuel projects		4			77			—
Partners’ share of synfuel project losses		(188	)		(251	)		(318	)
Contributions from synfuel partners		229			197			243
Cumulative effect of accounting changes		—			(1	)		3
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		196			8			(78	)

Net cash from operating activities		1,125			1,456			1,001


Investing Activities
Plant and equipment expenditures — utility		(1,035	)		(1,126	)		(850	)
Plant and equipment expenditures — non-utility		(264	)		(277	)		(215	)
Acquisitions, net of cash acquired		—			(42	)		(50	)
Proceeds from sale of interests in synfuel projects		447			246			349
Refunds to synfuel partners		(115	)		—			—
Proceeds from sale of non-utility business		1,262			—			—
Proceeds from sale of other assets, net		85			67			60
Restricted cash for debt redemptions		6			(21	)		4
Proceeds from sale of nuclear decommissioning trust fund assets		286			253			201
Investment in nuclear decommissioning trust funds		(323	)		(284	)		(235	)
Other investments		(19	)		(10	)		(66	)

Net cash from (used) for investing activities		330			(1,194	)		(802	)


Financing Activities
Issuance of long-term debt		50			612			869
Redemption of long-term debt		(393	)		(687	)		(1,266	)
Short-term borrowings, net		(47	)		291			437
Issuance of common stock		—			17			172
Repurchase of common stock		(708	)		(61	)		(13	)
Dividends on common stock		(364	)		(365	)		(360	)
Other		(6	)		(10	)		(6	)

Net cash used for financing activities		(1,468	)		(203	)		(167	)


Net Increase (Decrease) in Cash and Cash Equivalents		(13	)		59			32
Cash and Cash Equivalents Reclassified to Assets Held for Sale		(11	)		—			—
Cash and Cash Equivalents at Beginning of Period		147			88			56

Cash and Cash Equivalents at End of Period	$	123		$	147		$	88

See Notes to Consolidated Financial Statements

DTE Energy Company

Consolidated Statements of Changes in Shareholders’ Equity and Comprehensive Income


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

Balance, December 31, 2004		174,209		$	3,323		$	2,383		$	(158	)	$	5,548

Net income		—			—			537			—			537
Issuance of new shares		3,686			172			—			—			172
Dividends declared on common stock		—			—			(363	)		—			(363	)
Repurchase and retirement of common stock		(288	)		(13	)		—			—			(13	)
Benefit obligations, net of tax		—			—			—			4			4
Net change in unrealized losses on derivatives, net of tax		—			—			—			(106	)		(106	)
Net change in unrealized losses on investments, net of tax		—			—			—			(11	)		(11	)
Stock-based compensation and other		207			1			—			—			1

Balance, December 31, 2005		177,814			3,483			2,557			(271	)		5,769

Net income		—			—			433			—			433
Issuance of new shares		411			17			—			—			17
Dividends declared on common stock		—			—			(368	)		—			(368	)
Repurchase and retirement of common stock		(1,283	)		(32	)		(29	)		—			(61	)
Adjustment to initially apply SFAS No. 158, net of tax		—			—			—			(38	)		(38	)
Benefit obligations, net of tax		—			—			—			3			3
Net change in unrealized losses on derivatives, net of tax		—			—			—			102			102
Net change in unrealized losses on investments, net of tax		—			—			—			(7	)		(7	)
Stock-based compensation and other		196			(1	)		—			—			(1	)

Balance, December 31, 2006		177,138			3,467			2,593			(211	)		5,849

Net income		—			—			971			—			971
Implementation of FIN 48		—			—			(5	)		—			(5	)
Benefit obligations, net of tax		—			—			—			6			6
Dividends declared on common stock		—			—			(358	)		—			(358	)
Repurchase and retirement of common stock		(14,440	)		(297	)		(411	)		—			(708	)
Net change in unrealized losses on derivatives, net of tax		—			—			—			91			91
Net change in unrealized losses on investments, net of tax		—			—			—			1			1
Stock-based compensation and other		534			6			—			—			6

Balance, December 31, 2007		163,232		$	3,176		$	2,790		$	(113	)	$	5,853

The following table displays comprehensive income:


(in Millions)	2007			2006			2005
Net income	$	971		$	433		$	537

Other comprehensive income (loss), net of tax:
Benefit obligations, net of taxes of $3, $2 and $2		6			3			4

Net unrealized gains (losses) on derivatives:
Gains (losses) arising during the period, net of taxes of $(76), $3 and $(78)		(141	)		6			(145	)
Amounts reclassified to income, net of taxes of $125, $52 and $21		232			96			39

		91			102			(106	)


Net unrealized gains (losses) on investments:
Gains (losses) arising during the period, net of taxes of $2, $(4) and $(3)		4			(7	)		(6	)
Amounts reclassified to income, net of taxes of $(2), $- and $(2)		(3	)		—			(5	)

		1			(7	)		(11	)

Comprehensive income	$	1,069		$	531		$	424

See Notes to Consolidated Financial Statements

DTE Energy Company

Notes to Consolidated Financial Statements

NOTE 1 — SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure

DTE Energy owns the following businesses:

	•		Detroit Edison, an electric utility engaged in the generation, purchase, distribution and sale of electric energy to approximately 2.2 million customers in southeast Michigan;

	•		MichCon, a natural gas utility engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.3 million customers throughout Michigan; and

	•		Our four non-utility segments are involved in 1) coal transportation and marketing, gas pipelines processing and storage; 2) unconventional gas project development and production; 3) power and industrial projects; and 4) energy marketing and trading operations.

Detroit Edison and MichCon are regulated by the MPSC. The FERC regulates certain activities of Detroit Edison’s business as well as various other aspects of businesses under DTE Energy. In addition, the Company is regulated by other federal and state regulatory agencies including the NRC, the EPA and MDEQ.

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

Principles of Consolidation

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

For entities that are considered variable interest entities, the Company applies the provisions of FIN 46-R, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51.

Basis of Presentation

The accompanying Consolidated Financial Statements are prepared using accounting principles generally accepted in the United States of America. These accounting principles require management to use estimates and assumptions that impact reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from the Company’s estimates.

Revenues

Revenues from the sale and delivery of electricity, and the sale, delivery and storage of natural gas are recognized as services are provided. Detroit Edison and MichCon record revenues for electric and gas provided but unbilled at the end of each month. Detroit Edison’s accrued revenues include a component for the cost of power sold that is recoverable through the PSCR mechanism. MichCon’s accrued revenues include a component for the cost of gas sold

that is recoverable through the GCR mechanism. Annual PSCR and GCR proceedings before the MPSC permit Detroit Edison and MichCon to recover prudent and reasonable supply costs. Any overcollection or undercollection of costs, including interest, will be reflected in future rates. See Note 5.

Non-utility businesses recognize revenues as services are provided and products are delivered. The Energy Trading segment records in revenues net unrealized derivative gains and losses on energy trading contracts, including those to be physically settled. Net gains or losses on foreign currency derivatives are reported in Other income or Other expenses, respectively.

Comprehensive Income

Comprehensive income is the change in common shareholders’ equity during a period from transactions and events from non-owner sources, including net income. As shown in the following table, amounts recorded to other comprehensive income at December 31, 2007 include unrealized gains and losses from derivatives accounted for as cash flow hedges, unrealized gains and losses on available for sale securities, and changes in benefit obligations, consisting of deferred actuarial losses, prior service costs and transition amounts related to pension and other postretirement benefit plans, pursuant to SFAS No. 158.


	Net			Net					Accumulated
	Unrealized			Unrealized					Other
	Losses on			Gains on		Benefit			Comprehensive
(in Millions)	Derivatives			Investments		Obligations			Loss
Beginning balances	$	(104	)	$	15	$	(122	)	$	(211	)
Current period change		91			1		6			98

Ending balance	$	(13	)	$	16	$	(116	)	$	(113	)

Cash Equivalents and Restricted Cash

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

Inventories

The Company values fuel inventory and materials and supplies at average cost.

Gas inventory at MichCon is determined using the last-in, first-out (LIFO) method. At December 31, 2007, the replacement cost of gas remaining in storage exceeded the $32 million LIFO cost by $288 million. During 2007, MichCon liquidated 9.5 billion cubic feet of prior years’ LIFO layers. The liquidation reduced 2007 cost of gas by approximately $30 million, but had no impact on earnings as a result of the GCR mechanism. At December 31, 2006, the replacement cost of gas remaining in storage exceeded the $77 million LIFO cost by $236 million. During 2006, MichCon liquidated 5.1 billion cubic feet of prior years’ LIFO layers. The liquidation reduced 2006 cost of gas by approximately $1 million, but had no impact on earnings as a result of the GCR mechanism.

The Energy Trading segment uses the average cost method for its gas in inventory.

Property, Retirement and Maintenance, and Depreciation and Depletion

Summary of property by classification as of December 31:


(in Millions)	2007			2006
Property, Plant and Equipment
Electric Utility
Generation	$	8,100		$	7,667
Distribution		6,272			6,249

Total Electric Utility		14,372			13,916


Gas Utility
Distribution		2,392			2,175
Storage		241			245
Other		985			985

Total Gas Utility		3,618			3,405


Non-utility and other		1,423			1,903
Assets held for sale		(604	)		—

Total Property, Plant and Equipment		18,809			19,224


Less Accumulated Depreciation and Depletion
Electric Utility
Generation		(3,539	)		(3,410	)
Distribution		(2,101	)		(2,170	)

Total Electric Utility		(5,640	)		(5,580	)


Gas Utility
Distribution		(970	)		(926	)
Storage		(100	)		(108	)
Other		(538	)		(513	)

Total Gas Utility		(1,608	)		(1,547	)


Non-utility and other		(350	)		(646	)
Assets held for sale		197			—

Total Accumulated Depreciation and Depletion		(7,401	)		(7,773	)

Net Property, Plant and Equipment	$	11,408		$	11,451

Property is stated at cost and includes construction-related labor, materials, overheads and an allowance for funds used during construction (AFUDC). AFUDC capitalized during 2007 and 2006 was approximately $32 million and $22 million, respectively. The cost of properties retired, less salvage value, at Detroit Edison and MichCon is charged to accumulated depreciation.

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

The Company bases depreciation provisions for utility property at Detroit Edison and MichCon on straight-line and units-of-production rates approved by the MPSC. The composite depreciation rate for Detroit Edison was 3.3% in 2007, 3.3% in 2006 and 3.4% in 2005. The composite depreciation rate for MichCon was 3.1% in 2007, 2.8% in 2006 and 3.2% in 2005.

The average estimated useful life for each major class of utility property, plant and equipment as of December 31, 2007 follows:

Estimated Useful Lives in Years

Utility

Generation

Distribution

Transmission

Electric

N/A

Gas

N/A

Non-utility property is depreciated over its estimated useful life using straight-line, declining-balance or units-of-production methods. The estimated useful lives for major classes of non-utility assets and facilities ranges from 20 to 40 years.

The Company credits depreciation, depletion and amortization expense when it establishes regulatory assets for stranded costs related to the electric Customer Choice program and deferred environmental expenditures. The Company charges depreciation, depletion and amortization expense when it amortizes the regulatory assets. The Company credits interest expense to reflect the accretion income on certain regulatory assets.

Intangible assets relating to capitalized software are classified as Property, plant and equipment and the related amortization is included in Accumulated depreciation and depletion on the Consolidated Statements of Financial Position. The Company capitalizes the costs associated with computer software it develops or obtains for use in its business. The Company amortizes intangible assets on a straight-line basis over the expected period of benefit, ranging from 3 to 15 years. Intangible assets amortization expense was $42 million in 2007, $37 million in 2006 and $41 million in 2005. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2007 were $493 million and $141 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2006 were $503 million and $108 million, respectively. Amortization expense of intangible assets is estimated to be $45 million annually for 2008 through 2012.

Asset Retirement Obligations

The Company records asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and FIN 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. The Company has a legal retirement obligation for the decommissioning costs for its Fermi 1 and Fermi 2 nuclear plants. To a lesser extent, the Company has legal retirement obligations for the synthetic fuel operations, gas production facilities, gas gathering facilities and various other operations. The Company has conditional retirement obligations for gas pipeline retirement costs and disposal of asbestos at certain of its power plants. To a lesser extent, the Company has conditional retirement obligations at certain service centers, compressor and gate stations, and disposal costs for PCB contained within transformers and circuit breakers. The Company recognizes such obligations as liabilities at fair market value at the time the associated assets are placed in service. Fair value is measured using expected future cash outflows discounted at our credit-adjusted risk-free rate.

For the Company’s regulated operations, timing differences arise in the expense recognition of legal asset retirement costs that the Company is currently recovering in rates. The Company defers such differences under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

As a result of adopting FIN 47 on December 31, 2005, we recorded a plant asset of $26 million with offsetting accumulated depreciation of $14 million, and an asset retirement obligation liability of $124 million. We also recorded a cumulative effect amount related to utility operations as a reduction to a regulatory liability of $108 million and a cumulative effect charge against earnings of $3 million, after-tax in 2005.

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

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

A reconciliation of the asset retirement obligations for 2007 follows:


(in Millions)
Asset retirement obligations at January 1, 2007	$	1,221
Accretion		78
Liabilities incurred		4
Liabilities settled		(21	)
Assets held for sale		(16	)
Revision in estimated cash flows		27

Asset retirement obligations at December 31, 2007		1,293
Less amount included in current liabilities		(16	)

	$	1,277

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

Gas Production

The Company follows the successful efforts method of accounting for investments in gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well are expensed. The costs of development wells are capitalized, whether productive or nonproductive. Geological and geophysical costs on exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. An impairment loss is recorded to the extent that capitalized costs of unproved properties, on a property-by-property basis, are considered not to be realizable. An impairment loss is recorded if the net capitalized costs of proved gas properties exceed the aggregate related undiscounted future net revenues. Depreciation, depletion and amortization of proved gas properties are determined using the units-of-production method.

Long-Lived Assets

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

Goodwill

The Company has goodwill resulting from purchase business combinations. The change in the carrying amount of goodwill for the fiscal years ended December 31, 2007 and December 31, 2006 is as follows:


(in Millions)	Total
Balance at December 31, 2005	$2,057

Balance at December 31, 2006	2,057
Synthetic fuels impairment	(4	)
Sale of non-utility businesses and other	(16	)

Balance at December 31, 2007	$2,037

Intangible Assets

The Company has certain intangible assets relating to non-utility contracts and emission allowances. The Company amortizes intangible assets on a straight-line basis over the expected period of benefit, ranging from 4 to 30 years. Intangible assets amortization expense was $2 million in 2007, $5 million in 2006 and $2 million in 2005. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2007 were $31 million and $6 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2006 were $80 million and $8 million, respectively. Net intangible assets reclassified to Assets held for sale totaled $38 million at December 31, 2007. Amortization expense of intangible assets is estimated to be $3 million annually for 2008 through 2012.

Excise and Sales Taxes

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

Deferred Debt Costs

The costs related to the issuance of long-term debt are deferred and amortized over the life of each debt issue. In accordance with MPSC regulations applicable to the Company’s electric and gas utilities, the unamortized discount, premium and expense related to debt redeemed with a refinancing are amortized over the life of the replacement issue. Discount, premium and expense on early redemptions of debt associated with non-utility operations are charged to earnings.

Insured and Uninsured Risks

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

Investments in Debt and Equity Securities

The Company generally classifies investments in debt and equity securities as either trading or available-for-sale and has recorded such investments at market value with unrealized gains or losses included in earnings or in other comprehensive income or loss, respectively. Changes in the fair value of Fermi 2 nuclear decommissioning investments are recorded as adjustments to regulatory assets or liabilities, due to a recovery mechanism from customers. The Company’s investments are reviewed for impairment each reporting period. If the assessment indicates that the impairment is other than temporary, a loss is recognized resulting in the investment being written down to its estimated fair value. See Note 6.

Consolidated Statement of Cash Flows

A detailed analysis of the changes in assets and liabilities that are reported in the Consolidated Statement of Cash Flows follows:


(in Millions)	2007			2006			2005
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	(102	)	$	441		$	(633	)
Accrued GCR revenue		(10	)		120			(16	)
Inventories		80			(49	)		(6	)
Recoverable pension and postretirement costs		738			(1,184	)		61
Accrued/prepaid pensions		(401	)		218			17
Accounts payable		6			(68	)		290
Accrued PSCR refund		41			(101	)		(127	)
Income taxes payable		(19	)		46			(38	)
Risk management and trading activities		160			(518	)		353
Postretirement obligation		(320	)		1,008			132
Other assets		(430	)		(134	)		(9	)
Other liabilities		453			229			(102	)

	$	196		$	8		$	(78	)

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


(in Millions)	2007		2006		2005
Cash paid for:
Interest (net of interest capitalized)	$	537	$	526	$	516
Income taxes	$	326	$	89	$	80
Noncash investing and financing activities
Notes received from sale of synfuel projects	$	—	$	—	$	20
Sale of assets
Note receivable	$	—	$	—	$	47
Other assets	$	—	$	—	$	45

In conjunction with maintaining certain traded risk management positions, the Company may be required to post cash collateral with its clearing agent; therefore, the Company entered into a demand financing agreement for up to $150 million with its clearing agent in lieu of posting additional cash collateral (a non-cash transaction). The amounts outstanding under this facility were $13 million and $23 million at December 31, 2007 and 2006, respectively.

Other asset (gains) and losses, reserves and impairments, net

The following items are included in the Other asset (gains) and losses, reserves and impairments, net line in the Consolidated Statements of Operations:


(in Millions)	2007		2006			2005
Electric utility	$	8	$	(6	)	$	(26	)


Non-utility:
Barnett shale		27		(4	)		—
Waste coal recovery		—		19			—
Landfill gas recovery		—		14			—
Power generation		—		42			—

		27		71			—
Other		2		2			3

	$	37	$	67		$	(23	)

See the following notes for other accounting policies impacting the Company’s financial statements:


Note		Title

	2	New Accounting Pronouncements
	5	Regulatory Matters
	8	Income Taxes
	15	Financial and Other Derivative Instruments
	17	Retirement Benefits and Trusteed Assets
	18	Stock-based Compensation

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

Fair Value Accounting

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. It emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Fair value measurement should be determined based on the assumptions that market participants would use in pricing an asset or liability. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company adopted SFAS No. 157 effective January 1, 2008. The FASB deferred the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009. The adoption of SFAS No. 157 will not have a material impact to the January 1, 2008 balance of retained earnings.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115. This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. The fair value option established by SFAS No. 159 permits all entities to choose to measure eligible items at fair value at specified election dates. An entity will report in earnings unrealized gains and losses on items, for which the fair value option has been elected, at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to

entire instruments and not to portions of instruments. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. The adoption of SFAS No. 159 is not expected to have a material impact to the Company’s financial statements. At January 1, 2008, the Company has not elected to use the fair value option for financial assets and liabilities held at that date.

Offsetting Amounts Related to Certain Contracts

In April 2007, the FASB issued FSP FIN 39-1, Amendment of FASB Interpretation No. 39. This standard will permit the Company to offset the fair value of derivative instruments with cash collateral received or paid for those derivative instruments executed with the same counterparty under a master netting arrangement. As a result, the Company will be permitted to record one net asset or liability that represents the total net exposure of all derivative positions under a master netting arrangement. The decision to offset derivative positions under master netting arrangements remains an accounting policy choice. The Company presently records the net fair value of derivative assets and liabilities for those contracts held by Energy Trading that are subject to master netting arrangements, and separately records amounts for cash collateral received or paid for these instruments. Under this standard, if the Company chooses to offset the collateral amounts against the fair value of derivative assets and liabilities, both the Company’s total assets and total liabilities could be reduced. The guidance in this FSP is effective for fiscal years beginning after November 15, 2007, with early application permitted. The FSP is to be applied retrospectively by adjusting the financial statements for all periods presented. The company adopted the FSP as of January 1, 2008.

Business Combinations

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

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

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

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

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

Noncontrolling Interests in Consolidated Financial Statements

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

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

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

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

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

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

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

NOTE 3 — DISPOSALS AND DISCONTINUED OPERATIONS

Sale of Antrim Shale Gas Exploration and Production Business

In 2007, the Company sold its Antrim shale gas exploration and production business (Antrim) for gross proceeds of $1.262 billion. The pre-tax gain recognized on this sale amounted to $900 million ($580 million after-tax) and is reported on the Consolidated Statements of Operations under the line item, “Gain on sale of non-utility business,” and included in the Corporate & Other segment. Prior to the sale, the operating results of Antrim were reflected in the Unconventional Gas Production segment.

The Antrim business is not presented as a discontinued operation due to continuation of cash flows related to the sale of a portion of Antrim’s natural gas production to Energy Trading under the terms of natural gas sales contracts that expire in 2010 and 2012. These continuing cash flows, while not significant to DTE Energy, are significant to Antrim and therefore meet the definition of continuing cash flows as described in EITF 03-13, Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations.

Prior to the sale, a substantial portion of the Company’s price risk related to expected gas production from its Antrim shale business had been hedged through 2013. These financial contracts were accounted for as cash flow hedges, with changes in estimated fair value of the contracts reflected in other comprehensive income. Upon the sale of Antrim, the financial contracts no longer qualified as cash flow hedges. The contracts were retained and assigned to Energy Trading, and offsetting financial contracts were put into place to effectively settle these positions. As a result of these transactions and market research performed by the Company, we gained additional insight and visibility into the value ascribed to these contracts by third party market participants, including contract periods that extend beyond the actively traded period. In conjunction with the Antrim sale and effective settlement of these contract positions, the Company reclassified amounts held in accumulated other comprehensive income and recorded the effective settlements, reducing operating revenues in 2007 by $323 million.

Plan to Sell Interest in Certain Power and Industrial Projects

The Company expects to sell a 50 percent interest in a portfolio of select Power and Industrial Projects (Projects). In addition to the proceeds that the Company will receive from the sale of the 50 percent equity interest, the company that will own the Projects will obtain debt financing and the proceeds will be distributed to DTE Energy immediately prior to the sale of the equity interest. The Company expects to complete the transaction in the first half of 2008. This timing, however, is highly dependent on availability of acceptable financing terms in the credit markets. As a result, the Company cannot predict the timing with certainty. The Company expects to recognize a gain upon completion of the transaction. In conjunction with the sale, the Company will enter into a management services agreement to manage the day-to-day operations of the Projects and to act as the managing member of the company that owns the Projects. We

plan to account for our 50 percent ownership interest in the company that will own the portfolio of projects using the equity method. The Projects are contained in the Power and Industrial Projects segment and were classified as held for sale in September 2007.

The earnings pertaining to the Projects are fully consolidated in the Company’s Consolidated Statements of Operations. The following table presents the major classes of assets and liabilities of the Projects classified as held for sale at December 31, 2007:


(in Millions)
Cash and cash equivalents	$	11
Accounts receivable (less allowance for doubtful accounts of $4)		65
Inventories		4
Other current assets		3

Total current assets held for sale		83


Investments		55
Property, plant and equipment, net of accumulated depreciation of $183		285
Intangible assets		38
Long-term notes receivable		46
Other noncurrent assets		1

Total noncurrent assets held for sale		425


Total assets held for sale	$	508


Accounts payable	$	38
Other current liabilities		10

Total current liabilities associated with assets held for sale		48


Long-term debt (including capital lease obligations of $31)		53
Asset retirement obligations		16
Other liabilities		13

Total noncurrent liabilities associated with assets held for sale		82


Total liabilities related to assets held for sale	$	130

The table above represents 100 percent of the applicable assets and liabilities that are held for sale as of December 31, 2007. At September 30, 2007, the assets were classified as held for sale and we ceased recording depreciation and amortization expense related to these assets. Subsequent to the expected sale of the 50 percent interest, the remaining 50 percent interest in the Projects will be reflected in the Company’s financial statements under the equity method of accounting. The Consolidated Statements of Financial Position includes $28 million of minority interests in projects classified as held for sale. The results of the Projects will not be presented as discontinued operations, as the Company expects to retain a 50 percent ownership interest which represents significant continuing involvement as described in SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.

Sale of Interest in Barnett Shale Properties

On January 15, 2008, the Company sold a portion of its Barnett shale properties for gross proceeds of approximately $250 million, subject to post-closing adjustments. The properties in the sale include 186 billion cubic feet of proved and probable reserves on 11,000 net acres in the core area of the Barnett shale. As of December 31, 2007, property, plant and equipment of approximately $122 million, net of approximately $14 million of accumulated depreciation and depletion, was classified as held for sale. The Company expects to recognize a gain upon completion of the transaction.

Synthetic Fuel Business

The Company discontinued the operations of our synthetic fuel production facilities throughout the United States as of December 31, 2007. Synfuel plants chemically changed coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits were provided for the production and sale of solid synthetic fuel produced from coal and were available through December 31, 2007. Through December 31, 2007, the Company has generated and recorded approximately $601 million in production tax credits.

The Company had sold interests in all of the synthetic fuel production plants, representing approximately 91% of its total production capacity. Proceeds from the sales are contingent upon production levels, the production qualifying for production tax credits, and the value of such credits. Production tax credits are subject to phase-out if domestic crude oil prices reach certain levels. The Company recognizes gains from the sale of interests in the synfuel facilities as synfuel is produced and sold, and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectibility is reasonably assured.

The Company has provided certain guarantees and indemnities in conjunction with the sales of interests in its synfuel facilities. The guarantees cover potential commercial, environmental, oil price and tax-related obligations and will survive until 90 days after expiration of all applicable statutes of limitations. The Company estimates that its maximum potential liability under these guarantees at December 31, 2007 is $3.1 billion. At December 31, 2007, the Company has reserved $436 million of its maximum potential liability, primarily representing the estimated refund of certain payments made by its synfuel partners.

As shown in the following table, the Company has reported the business activity of the Synthetic Fuel business as a discontinued operation. The amounts exclude general corporate overhead costs:


(in Millions)	2007			2006			2005
Operating Revenues	$	1,069		$	863		$	927
Operation and Maintenance		1,265			1,019			1,167
Depreciation and Amortization		(6	)		24			58
Taxes other than Income		5			12			20
Asset (Gains) and Losses, Reserves and Impairments, Net (1)		(280	)		40			(367	)

Operating Income (Loss)		85			(232	)		49
Other (Income) and Deductions		(9	)		(20	)		(34	)
Minority Interest		(188	)		(251	)		(318	)
Income Taxes
Provision		98			14			139
Production Tax Credits		(21	)		(23	)		(43	)

		77			(9	)		96

Net Income (1)	$	205		$	48		$	305


(1)		Includes intercompany pre-tax gain of $32 million ($21 million after-tax) for 2007.

Crete

In July 2007, the Company entered into an agreement to sell its 50 percent equity interest in Crete, a 320 MW natural gas-fired peaking electric generating plant. The sale closed in October 2007 resulting in gross proceeds of approximately $37 million, which resulted in a gain of $8 million, ($5 million after- tax). See Note 4 for information regarding a 2006 impairment related to Crete.

DTE Georgetown (Georgetown)

Georgetown is an 80 MW natural gas-fired peaking electric generating plant. In December 2006, Georgetown met the SFAS No. 144 criteria of an asset “held for sale” and the Company reported its operating results as a discontinued operation. In February 2007, the Company entered into an agreement to sell this plant. The sale closed in July 2007 resulting in gross proceeds of approximately $23 million, which approximated its carrying value.

As shown in the following table, the Company has reported the business activity of Georgetown as a discontinued operation. The amounts exclude general corporate overhead costs:


	Year Ended December 31
(in Millions)	2007		2006			2005
Revenues (1)	$	—	$	1		$	1
Expenses		—		3			2

Loss before income taxes		—		(2	)		(1	)
Income tax benefit		—		—			—

Loss from discontinued operations	$	—	$	(2	)	$	(1	)


(1)		Includes intercompany revenues of $1 million for 2006 and 2005.

DTE Energy Technologies (Dtech)

Dtech assembled, marketed, distributed and serviced distributed generation products, provided application engineering, and monitored and managed on-site generation system operations. In the third quarter of 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 generation sales and service. The systems monitoring business is planned to be retained by the Company. The Dtech restructuring plan met the SFAS No. 144 criteria of an asset “held for sale” and the Company reported its operating results as a discontinued operation. The Company expects continued legal and warranty expenses in 2008 related to Dtech’s operations prior to the third quarter of 2005. As of December 31, 2007, Dtech had liabilities of approximately $1 million.

As shown in the following table, the Company has reported the business activity of Dtech as a discontinued operation. The amounts exclude general corporate overhead costs and operations that are to be retained.


	Year Ended December 31
(in Millions)	2007		2006			2005
Revenues (1)	$	—	$	1		$	18
Expenses		—		6			67

Loss before income taxes		—		(5	)		(49	)
Income tax benefit		—		(2	)		(14	)

Loss from discontinued operations	$	—	$	(3	)	$	(35	)


(1)		Includes intercompany revenues of $6 million for 2005.

NOTE 4 — OTHER IMPAIRMENTS AND RESTRUCTURING

Other Impairments

Barnett shale

In 2007, our Unconventional Gas Production segment recorded a pre-tax impairment loss of $27 million related to the write-off of the costs of unproved properties and expired leases in Bosque County, which is located in the southern expansion area of the Barnett shale in north Texas. The properties were impaired due to the lack of economic and operating viability of the project. The impairment loss was recorded within the Other asset (gains) and losses, reserves, and impairments, net line in the Consolidated Statements of Operations.

Landfill Gas Recovery

In 2006, the Company’s Power and Industrial Projects segment recorded a pre-tax impairment loss of $14 million at its landfill gas recovery unit relating to the write down of assets at several landfill sites. The fixed assets were impaired due to continued operating losses and the oil price-related phase-out of production tax credits. The impairment was recorded within the Other asset (gains) and losses, reserves and impairments, net line in the Consolidated Statements of Operations. The Company calculated the expected undiscounted cash flows from the use and eventual disposition of the assets, which indicated that the carrying amount of certain assets was not recoverable. The Company determined the fair value of the assets utilizing a discounted cash flow technique.

Non-Utility Power Generation

In 2006, the Power and Industrial Projects segment recorded a pre-tax impairment loss totaling $74 million for its investments in two natural gas-fired electric generating plants.

A loss of $42 million related to a 100% owned plant is recorded within the Other asset (gains) and losses, reserves and impairments, net line in the Consolidated Statements of Operations. The generating plant was impaired due to continued operating losses and the September 2006 delisting by MISO, resulting in the plant no longer providing capacity for the power grid. The Company calculated the expected undiscounted cash flows from the use and eventual disposition of the plant, which indicated that the carrying amount of the plant was not recoverable. The Company determined the fair value of the plant utilizing a discounted cash flow technique.

A loss of $32 million related to a 50% equity interest in Crete is recorded within the Other (income) and deductions, Other expenses line in the Consolidated Statements of Operations for 2006. The investment was impaired due to continued operating losses and the expected sale of the investment. The Company determined the fair value of the plant utilizing a discounted cash flow technique, which indicated that the carrying amount of the investment exceeded its fair value.

Waste Coal Recovery

In 2006, our Power and Industrial Projects segment recorded a pre-tax impairment loss of $19 million related to its investment in proprietary technology used to refine waste coal. The fixed assets at our development operation were impaired due to continued operating losses and negative cash flow. In addition, the Company impaired all of its patents related to waste coal technology. The Company calculated the expected undiscounted cash flows from the use and eventual disposition of the assets, which indicated that the carrying amount of the assets was not recoverable. The Company determined the fair value of the assets utilizing a discounted cash flow technique. The impairment loss was recorded within the Other asset (gains) and losses, reserves and impairments, net line in the Consolidated Statements of Operations.

Restructuring — Performance Excellence Process

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

The Company incurred CTA for employee severance and other costs. Other costs include project management and consultant support. Pursuant to MPSC authorization, beginning in the third quarter of 2006, Detroit Edison deferred approximately $102 million of CTA in 2006. Detroit Edison began amortizing deferred 2006 costs in 2007 as the recovery of these costs was provided for by the MPSC. Amortization expense amounted to $10 million in 2007. Detroit Edison deferred $54 million of CTA during 2007. MichCon cannot defer CTA costs at this time because a recovery mechanism has not been established. MichCon expects to seek a recovery mechanism in its next rate case in 2009. See
Note 5.

Amounts expensed are recorded in the Operation and maintenance line on the Consolidated Statements of Operations. Deferred amounts are recorded in the Regulatory asset line on the Consolidated Statements of Financial Position. Costs incurred in 2007 and 2006 are as follows:


	Employee Severance Costs				Other Costs				Total Cost
(in Millions)	2007		2006		2007		2006		2007		2006
Costs incurred:
Electric Utility	$	15	$	51	$	50	$	56	$	65	$	107
Gas Utility		3		17		6		7		9		24
Other		1		2		1		1		2		3

Total costs		19		70		57		64		76		134
Less amounts deferred or capitalized:
Electric Utility		15		51		50		56		65		107

Amount expensed	$	4	$	19	$	7	$	8	$	11	$	27

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

NOTE 5 — REGULATORY MATTERS

Regulation

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

Regulatory Assets and Liabilities

Detroit Edison and MichCon apply the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, to their regulated operations. SFAS No. 71 requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as revenue and expense in non-regulated businesses. Continued applicability of SFAS No. 71 requires that rates be designed to recover specific costs of providing regulated services and be charged to and collected from customers. Future regulatory changes or changes in the competitive environment could result in the Company discontinuing the application of SFAS No. 71 for some or all of its utility businesses and may require the write-off of

the portion of any regulatory asset or liability that was no longer probable of recovery through regulated rates. Management believes that currently available facts support the continued application of SFAS No. 71 to Detroit Edison and MichCon.

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


(in Millions)	2007			2006
Assets
Securitized regulatory assets	$	1,124		$	1,235


Recoverable income taxes related to securitized regulatory assets	$	616		$	677
Recoverable pension and postretirement costs		991			1,728
Asset retirement obligation		266			236
Other recoverable income taxes		94			100
Recoverable costs under PA 141
Excess capital expenditures		11			22
Deferred Clean Air Act expenditures		28			67
Midwest Independent System Operator charges		23			48
Electric Customer Choice implementation costs		58			78
Enhanced security costs		10			13
Unamortized loss on reacquired debt		67			69
Deferred environmental costs		41			40
Accrued PSCR/GCR revenue		76			117
Recoverable uncollectibles expense		42			45
Cost to achieve Performance Excellence Process		146			102
Enterprise Business Systems costs		26			9
Deferred income taxes — Michigan Business Tax		364			—
Other		3			3

		2,862			3,354
Less amount included in current assets		(76	)		(128	)

	$	2,786		$	3,226


Liabilities
Asset removal costs	$	581		$	576
Accrued pension		115			72
Safety and training cost refund		—			3
Accrued PSCR/GCR refund		70			81
Refundable income taxes		104			114
Fermi 2 refueling outage		4			16
Deferred income taxes — Michigan Business Tax		364			—
Other		5			2

		1,243			864
Less amount included in current liabilities		(75	)		(99	)

	$	1,168		$	765

ASSETS

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

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

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

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

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

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

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

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

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

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

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

•		Deferred environmental costs — The MPSC approved the deferral and recovery of investigation and remediation costs associated with Gas Utility’s former MGP sites.

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

•		Accrued GCR revenue — Receivable for the temporary under-recovery of and a return on gas costs incurred by MichCon which are recoverable through the GCR mechanism.

•		Recoverable uncollectibles expense — MichCon receivable for the MPSC approved uncollectible expense true-up mechanism that tracks the difference in the fluctuation in uncollectible accounts and amounts recognized pursuant to the MPSC authorization.

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

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

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

LIABILITIES

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

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

•		Safety and training cost refund — The MPSC ordered the refund of unspent costs which were included in the Company’s rates.

•		Accrued PSCR refund — Payable for the temporary over-recovery of and a return on power supply costs and transmission costs incurred by Detroit Edison which are recoverable through the PSCR mechanism.

•		Accrued GCR Refund - Liability for the temporary over-recovery of and a return on gas costs incurred by MichCon which are recoverable through the GCR mechanism.

•		Refundable income taxes — Income taxes refundable to MichCon’s customers representing the difference in property-related deferred income taxes payable and amounts recognized pursuant to MPSC authorization.

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

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

MPSC Show Cause Order

In March 2006, the MPSC issued an order directing Detroit Edison to show cause by June 1, 2006 why its rates should not be reduced in 2007. Detroit Edison filed its response explaining why its rates should not be reduced in 2007. The MPSC issued an order approving a settlement agreement in this proceeding on August 31, 2006. The order provided for an annualized rate reduction of $53 million for 2006, effective September 5, 2006. Beginning January 1, 2007, and continuing until April 13, 2008, one year from the filing of the general rate case on April 13, 2007, rates were reduced by an additional $26 million, for a total reduction of $79 million annually. The revenue reduction is net of the recovery of the amortization of the costs associated with the implementation of the Performance Excellence Process. The settlement agreement provided for some level of realignment of the existing rate structure by allocating a larger percentage share of the rate reduction to the commercial and industrial customer classes than to the residential customer classes.

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

2007 Electric Rate Case Filing

Pursuant to the February 2006 MPSC order in Detroit Edison’s rate restructuring case and the August 2006 MPSC order in the settlement of the show cause case, Detroit Edison filed a general rate case on April 13, 2007 based on a 2006 historical test year. The filing with the MPSC requested a $123 million, or 2.9 percent, average increase in Detroit Edison’s annual revenue requirement for 2008.

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

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

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

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

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

	•		Terminate the Pension Equalization Mechanism.

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

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

Also, in the filing, in conjunction with Michigan’s 21st Century Energy Plan, Detroit Edison has reinstated a long-term integrated resource planning (IRP) process with the purpose of developing the least overall cost plan to serve customers’ generation needs over the next 20 years. Based on the IRP, new base load capacity may be required for Detroit Edison. To protect tax credits available under Federal law, Detroit Edison determined it would be prudent to initiate the application process for a new nuclear unit. Detroit Edison has not made a final decision to build a new nuclear unit. Detroit Edison is preserving its option to build at some point in the future by beginning the complex nuclear licensing process in 2007. Also, beginning the licensing process at the present time positions Detroit Edison, potentially, to take advantage of tax incentives of up to $320 million derived from provisions in the 2005 Federal Energy Policy Act that will benefit customers. To qualify for these substantial tax credits, a combined operating license application for construction and operation of an advanced nuclear generating plant must be docketed by the Nuclear Regulatory Commission no later than December 31, 2008. Preparation and approval of a combined operating license can take up to 4 years and is estimated to cost at least $60 million. At December 31, 2007, costs related to preparing the combined licensing application totaling $10 million have been deferred and included in Other assets.

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

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

Regulatory Accounting Treatment for Performance Excellence Process

In May 2006, Detroit Edison and MichCon filed applications with the MPSC to allow deferral of costs associated with the implementation of the Performance Excellence Process, a company-wide cost-savings and performance improvement program. Detroit Edison and MichCon sought MPSC authorization to defer and amortize Performance Excellence Process implementation costs for accounting purposes to match the expected savings from the Performance Excellence Process program with the related CTA.

Detroit Edison and MichCon anticipate the Performance Excellence Process to continue into 2008. In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison and MichCon, commencing in 2006, to defer the incremental CTA, subject to the MPSC establishing a recovery mechanism in a future rate proceeding. Further, the order provides for Detroit Edison and MichCon to amortize the CTA deferrals over a ten-year period beginning with the year subsequent to the year the CTA was deferred. At year-end 2006, Detroit Edison recorded deferred CTA costs of $102 million as a regulatory asset and began amortizing deferred 2006 costs in 2007, as the recovery of these costs was provided for by the MPSC in its order approving the settlement of the show cause proceeding. During 2007, Detroit Edison deferred CTA costs of $54 million. Amortization of prior year deferred CTA costs amounted to $10 million during 2007. MichCon cannot defer CTA costs at this time because a recovery mechanism has not been established. MichCon expects to seek a recovery mechanism in its next rate case.

Accounting for Costs Related to Enterprise Business Systems (EBS)

In July 2004, Detroit Edison filed an accounting application with the MPSC requesting authority to capitalize and amortize costs related to EBS, consisting of computer equipment, software and development costs, as well as related training, maintenance and overhead costs. In April 2005, the MPSC approved a settlement agreement providing for the deferral of up to $60 million of certain EBS costs, which would otherwise be expensed, as a regulatory asset for future rate recovery starting January 1, 2006. At December 31, 2007, approximately $26 million of EBS costs have been deferred as a regulatory asset. In addition, EBS costs recorded as plant assets will be amortized over a 15-year period, pursuant to MPSC authorization.

Fermi 2 Enhanced Security Costs Settlement

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

Reconciliation of Regulatory Asset Recovery Surcharge

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

Power Supply Costs Recovery Proceedings

2005 Plan Year — In March 2006, Detroit Edison filed its 2005 PSCR reconciliation that sought approval for recovery of an under-recovery of approximately $144 million at December 31, 2005 from its commercial and industrial customers. The filing included a motion for entry of an order to implement immediately a reconciliation surcharge of 4.96 mills per kWh on the bills of its commercial and industrial customers. The under-collected PSCR expense allocated to residential customers could not be recovered due to the PA 141 rate cap for residential customers, which expired January 1, 2006. In addition to the 2005 PSCR plan year reconciliation, the filing included a reconciliation for the Pension Equalization Mechanism (PEM) for the periods from November 24, 2004 through December 31, 2004 and from January 1, 2005 through December 31, 2005. The PEM reconciliation seeks to allocate and refund approximately $12 million to customers based upon their contributions to pension expense during the subject periods. In September 2006, the MPSC ordered the Company to roll the entire 2004 PSCR over-collection amount to the Company’s 2005 PSCR Reconciliation. An order was issued on May 22, 2007 approving a 2005 PSCR undercollection amount of $94 million and the recovery of this amount through a surcharge for 12 months beginning in June 2007. In addition, the order approved Detroit Edison’s proposed PEM reconciliation that was refunded to customers on a bills-rendered basis during June 2007.

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

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

filing is being collected in the 2007 PSCR plan. Included in the 2006 PSCR reconciliation filing was the Company’s 2006 PEM reconciliation that reflects a $21 million ovecollection which is subject to refund to customers. An MPSC order in this case is expected in 2008.

2007 Plan Year — In September 2006, Detroit Edison filed its 2007 PSCR plan case seeking approval of a levelized PSCR factor of 6.98 mills per kWh above the amount included in base rates for all PSCR customers. The Company’s PSCR plan filing included $130 million for the recovery of its projected 2006 PSCR under-collection, bringing the total requested PSCR factor to 9.73 mills/kWh. The Company’s application included a request for an early hearing and temporary order granting such ratemaking authority. The Company’s 2007 PSCR plan includes fuel and power supply costs, including NOx and SO₂ emission allowance costs, transmission costs and MISO costs. The Company filed supplemental testimony and briefs in December 2006 supporting its updated request to include approximately $81 million for the recovery of its projected 2006 PSCR under-collection. The MPSC issued a temporary order in December 2006 approving the Company’s request. In addition, Detroit Edison was granted the authority to include all PSCR over/(under) collections in future PSCR plans, thereby reducing the time between refund or recovery of PSCR reconciliation amounts. The Company began to collect its 2007 power supply costs, including the 2006 rollover amount, through a PSCR factor of 8.69 mills/kWh on January 1, 2007. The Company reduced the PSCR factor to 6.69 mills/kWh on July 1, 2007 based on the updated 2007 PSCR plan year projections. In August 2007, the MPSC approved Detroit Edison’s 2007 PSCR case and authorized the Company to charge a maximum power supply cost recovery factor of 8.69 mills/kWh in 2007.

2008 Plan Year — In September 2007, Detroit Edison filed its 2008 PSCR plan case seeking approval of a levelized PSCR factor of 9.23 mills/kWh above the amount included in base rates for all PSCR customers. The Company is supporting a total 2008 power supply expense forecast of $1.3 billion that includes $1 million for the recovery of its projected 2007 PSCR under-collection. The Company’s PSCR Plan will allow the Company to recover its reasonably and prudently incurred power supply expense including; fuel costs, purchased and net interchange power costs, NOx and SO₂ emission allowance costs, transmission costs and MISO costs. Also included in the filing is a request for approval of the Company’s emission compliance strategy which includes pre-purchases of emission allowances as well as a request for pre-approval of a contract for capacity and energy associated with a renewable wind energy project. On January 31, 2008, Detroit Edison filed a revised PSCR plan case seeking approval of a levelized PSCR factor of 11.22 mills/kWh above the amount included in base rates for all PSCR customers. The revised filing supports a 2008 power supply expense forecast of $1.4 billion and includes $43 million for the recovery of a projected 2007 PSCR under-collection.

Uncollectible Expense True-Up Mechanism (UETM) and Report of Safety and Training-Related Expenditures

2005 UETM — In March 2006, MichCon filed an application with the MPSC for approval of its UETM for 2005. This is the first filing MichCon has made under the UETM, which was approved by the MPSC in April 2005 as part of MichCon’s last general rate case. MichCon’s 2005 base rates included $37 million for anticipated uncollectible expenses. Actual 2005 uncollectible expenses totaled $60 million. The true-up mechanism allows MichCon to recover ninety percent of uncollectibles that exceeded the $37 million base. Under the formula prescribed by the MPSC, MichCon recorded an under-recovery of approximately $11 million for uncollectible expenses from May 2005 (when the mechanism took effect) through the end of 2005. In December 2006, the MPSC issued an order authorizing MichCon to implement the UETM monthly surcharge for service rendered on and after January 1, 2007.

As part of the March 2006 application with the MPSC, MichCon filed a review of its 2005 annual safety and training-related expenditures. MichCon reported that actual safety and training-related expenditures for the initial period exceeded the pro-rata amounts included in base rates and based on the under-recovered position, recommended no refund at this time. In the December 2006 order, the MPSC also approved MichCon’s 2005 safety and training report.

100

2006 UETM — In March 2007, MichCon filed an application with the MPSC for approval of its UETM for 2006 requesting $33 million of under-recovery plus applicable carrying costs of $3 million. The March 2007 application included a report of MichCon’s 2006 annual safety and training-related expenditures, which shows a $2 million over-recovery. In August 2007, MichCon filed revised exhibits reflecting an agreement with the MPSC Staff to net the $2 million over-recovery and associated interest related to the 2006 safety and training-related expenditures against the 2006 UETM under-recovery. An MPSC order was issued in December 2007 approving the collection of $33 million requested in the August 2007 revised filing. MichCon is authorized to implement the new UETM monthly surcharge for service rendered on and after January 1, 2008.

Gas Cost Recovery Proceedings

2005-2006 Plan Year —In June 2006, MichCon filed its GCR reconciliation for the 2005-2006 GCR year. The filing supported a total over-recovery, including interest through March 2006, of $13 million. MPSC Staff and other interveners filed testimony regarding the reconciliation in which they recommended disallowances related to MichCon’s implementation of its dollar cost averaging fixed price program. In January 2007, MichCon filed testimony rebutting these recommendations. On December 18, 2007, the MPSC issued an order adopting the adjustments proposed by the MPSC Staff resulting in an $8 million disallowance. Expense related to the disallowance was reflected in the Consolidated Statements of Operations for the year ended December 31, 2007. The MPSC authorized MichCon to roll a net over-recovery, inclusive of interest, of $20 million into its 2006-2007 GCR reconciliation. On December 27, 2007, MichCon filed an appeal of the case with the Michigan Court of Appeals. MichCon is unable to predict the outcome of the appeal.

2006-2007 Plan Year — In June 2007, MichCon filed its GCR reconciliation for the 2006-2007 GCR year. The filing supported a total under-recovery, including interest through March 2007, of $18 million. An MPSC order in this case is expected in 2008.

2007-2008 Plan Year / Base Gas Sale Consolidated — In August 2006, MichCon filed an application with the MPSC requesting permission to sell base gas that would become accessible with storage facilities upgrades. In December 2006, MichCon filed its 2007-2008 GCR plan case proposing a maximum GCR factor of $8.49 per Mcf. In August 2007, a settlement agreement in this proceeding was reached by all intervening parties that provides for a sharing with customers of the proceeds from the sale of base gas. In addition, the agreement provides for a rate case filing moratorium until January 1, 2009, unless certain unanticipated changes occur that impact income by more than $5 million. The settlement agreement was approved by the MPSC on August 21, 2007. MichCon’s gas storage enhancement projects, the main subject of the aforementioned settlement, will enable 17 billion cubic feet (Bcf) of gas to become available for cycling. Under the settlement terms, MichCon delivered 13.4 Bcf of this gas to its customers through 2007 at a savings to market-priced supplies of approximately $54 million. This settlement provides for MichCon to retain the proceeds from the sale of 3.6 Bcf of gas, which MichCon expects to sell in 2007 through 2009. In the fourth quarter of 2007, MichCon sold .75 Bcf of base gas and recognized a pre-tax gain of $5 million. By enabling MichCon to retain the profit from the sale of this gas, the settlement provides MichCon with the opportunity to earn an 11% return on equity with no customer rate increase for a period of five years from 2005 to 2010.

2008-2009 Plan Year — In December 2007, MichCon filed its GCR plan case for the 2008-2009 GCR Plan year. MichCon filed for a maximum GCR factor of $8.36 per Mcf. An order in this case is expected during 2008.

Other

On July 3, 2007, the Court of Appeals of the State of Michigan published its decision with respect to an

101

appeal by Detroit Edison and others of certain provisions of a November 23, 2004 MPSC order, including reversing the MPSC’s denial of recovery of merger control premium costs. In its published decision, the Court of Appeals held that Detroit Edison is entitled to recover its allocated share of the merger control premium and remanded this matter to the MPSC for further proceedings to establish the precise amount and timing of this recovery. Detroit Edison has filed a supplement to its April 2007 rate case to address the recovery of the merger control premium costs. Other parties have filed requests for leave to appeal to the Michigan Supreme Court from the Court of Appeals decision. On September 6, 2007, the Court of Appeals remanded to the MPSC, for reconsideration, the MichCon recovery of merger control premium costs. DTE Energy and Detroit Edison are unable to predict the financial or other outcome of any legal or regulatory proceeding at this time.

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

NOTE 6 — NUCLEAR OPERATIONS

General

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

Property Insurance

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

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

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

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

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

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

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Public Liability Insurance

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

Decommissioning

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

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

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

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

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

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

Total	$	824	$	740

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

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

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


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

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


			Total
	Fair		Unrealized
(in Millions)	Value		Gains
As of December 31, 2007
Equity Securities	$	443	$	170
Debt Securities		373		9
Cash and Cash Equivalents		8		—

	$	824	$	179


As of December 31, 2006
Equity Securities	$	399	$	140
Debt Securities		316		4
Cash and Cash Equivalents		25		—

	$	740	$	144

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

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

Nuclear Fuel Disposal Costs

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

NOTE 7 — JOINTLY OWNED UTILITY PLANT

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


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


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

Belle River

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

Ludington Hydroelectric Pumped Storage

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

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NOTE 8 — INCOME TAXES

Income Tax Summary

The Company files a consolidated federal income tax return. Total income tax expense varied from the statutory federal income tax rate for the following reasons:


(in Millions)	2007			2006			2005
Income before income taxes and minority interest	$	1,155		$	536		$	415
Less minority interest		4			1			37

Income from continuing operations before tax	$	1,151		$	535		$	378


Income tax expense at 35% statutory rate	$	403		$	187		$	132
Production tax credits		(11	)		(12	)		(10	)
Investment tax credits		(8	)		(8	)		(8	)
Depreciation		(4	)		(4	)		(4	)
Employee Stock Ownership Plan dividends		(5	)		(5	)		(5	)
Medicare part D subsidy		(6	)		(6	)		(7	)
Other, net		(5	)		(6	)		8

Income tax expense from continuing operations	$	364		$	146		$	106

Effective federal income tax rate		31.6	%		27.3	%		28.0	%

The minority interest allocation reflects the adjustment to earnings to allocate partnership losses to third party owners. The tax impact of partnership earnings and losses are attributable to the partners instead of the partnerships. The minority interest allocation is therefore removed in computing income taxes associated with continuing operations.

Components of income tax expense were as follows:


(in Millions)	2007		2006			2005
Continuing operations
Current federal and other income tax expense	$	277	$	88		$	78
Deferred federal income tax expense		87		58			28

		364		146			106
Discontinued operations		66		(11	)		83
Cumulative effect of accounting changes		—		1			(2	)

Total	$	430	$	136		$	187

Production tax credits are provided for qualified fuels produced and sold by a taxpayer to an unrelated party during the taxable year. Production tax credits earned but not utilized totaled $186 million and are carried forward indefinitely as alternative minimum tax credits. The majority of the production tax credits earned, including all of those from our synfuel projects, were generated from projects that have received a private letter ruling (PLR) from the Internal Revenue Service (IRS). These PLRs provide assurance as to the appropriateness of using these credits to offset taxable income, however, these tax credits are subject to IRS audit and adjustment.

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

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liabilities are classified according to the expected reversal date of the temporary differences. Deferred tax assets (liabilities) were comprised of the following at December 31:


(in Millions)	2007			2006
Property, plant and equipment	$	(1,384	)	$	(1,358	)
Securitized regulatory assets		(621	)		(670	)
Alternative minimum tax credit carryforward		186			438
Merger basis differences		57			60
Pension and benefits		28			16
Other comprehensive income		62			113
Risk management assets and liabilities		142			62
Net operating loss carryforward		28			51
Other		93			88

		(1,409	)		(1,200	)
Less valuation allowance		(28	)		(20	)

	$	(1,437	)	$	(1,220	)


Current deferred income tax assets	$	387		$	245
Long-term deferred income tax liabilities		(1,824	)		(1,465	)

	$	(1,437	)	$	(1,220	)


Deferred income tax assets	$	1,771		$	1,834
Deferred income tax liabilities		(3,208	)		(3,054	)

	$	(1,437	)	$	(1,220	)

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

The Company has state deferred tax assets related to net operating loss carry-forwards of $28 million and $20 million at December 31, 2007 and 2006, respectively. The state net operating loss carry-forwards expire in 2008 through 2026. The Company has recorded valuation allowances at December 31, 2007 and 2006 of approximately $28 million and $20 million, respectively, a change of $8 million, with respect to deferred tax assets associated with state income taxes. In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Based upon the level of historical taxable income and projections for future taxable income over the periods which the deferred tax assets are deductible, the Company believes it is more likely than not that it will realize the benefits of those deductible differences, net of the existing valuation allowance as of December 31, 2007.

Uncertain Tax Positions

The Company adopted the provisions of FIN 48, Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109 (FIN 48) on January 1, 2007. This interpretation prescribes a more-likely-than-not recognition threshold and a measurement attribute for the financial statement reporting of tax positions taken or expected to be taken on a tax return. As a result of the implementation of FIN 48, the Company recognized a $5 million increase in liabilities that was accounted for as a reduction to the January 1, 2007 balance of retained earnings.

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A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:


(in Millions)
Balance at January 1, 2007	$	45
Additions for tax positions of prior years		4
Reductions for tax positions of prior years		(8	)
Settlements		(15	)
Lapse of statute of limitations		(4	)

Balance at December 31, 2007	$	22

The Company has $14 million of unrecognized tax benefits at December 31, 2007 that, if recognized, would favorably impact our effective tax rate. During the next twelve months, statutes of limitations will expire for our tax returns in various states. It is reasonably possible that there will be a decrease in unrecognized tax benefits of $8 million within the next twelve months.

The Company recognizes interest and penalties pertaining to income taxes in Interest expense and Other expenses, respectively, on its Consolidated Statements of Operations. Accrued interest pertaining to income taxes totaled $7 million at December 31, 2007. The Company had no accrued penalties pertaining to income taxes. The Company recognized interest expense related to income taxes of $1 million during 2007.

The Company’s U.S. federal income tax returns for years 2004 and subsequent years remain subject to examination by the IRS. The Company also files tax returns in numerous state jurisdictions with varying statutes of limitation.

Michigan Business Tax

On July 12, 2007, the Michigan Business Tax (MBT) was enacted by the State of Michigan to replace the Michigan Single Business Tax (MSBT) effective January 1, 2008. The MBT is comprised of an apportioned modified gross receipts tax of 0.8 percent; and an apportioned business income tax of 4.95 percent. The MBT provides credits for Michigan business investment, compensation, and research and development. The MBT will be accounted for as an income tax.

In 2007 a state deferred tax liability of $224 million was recognized by the Company for cumulative differences between book and tax assets and liabilities for the consolidated group. Effective September 30, 2007, legislation was adopted by the State of Michigan creating a deduction for businesses that realize an increase in their deferred tax liability due to the enactment of the MBT. Therefore, a deferred tax asset of $224 million was established related to the future deduction. The deduction will be claimed during the period of 2015 through 2029. The recognition of the enactment of the MBT did not have an impact on our income tax provision for 2007.

Of the $224 million of deferred tax liabilities and assets recognized for the consolidated group, $364 million related to our regulated entities with the remainder related to our non-regulated entities. The $364 million of deferred tax liabilities and assets recognized by our regulated utilities were offset by corresponding regulatory assets and liabilities in accordance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, as the impacts of the deferred tax liabilities and assets recognized upon enactment and amendment of the MBT will be reflected in our rates.

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NOTE 9 — COMMON STOCK

Common Stock

The DTE Energy Board of Directors has authorized the repurchase of up to $1.550 billion of common stock through 2009. Through December 31, 2007, repurchases of approximately $725 million of common stock were made.

Under the DTE Energy Company Long-Term Incentive Plan, the Company grants non-vested stock awards to key employees, primarily management. As a result of a stock award, a settlement of an award of performance shares, or by exercise of a participant’s stock option, the Company may deliver common stock from the Company’s authorized but unissued common stock and/or from outstanding common stock acquired by or on behalf of the Company in the name of the participant. The number of non-vested restricted stock awards is included in the number of common shares outstanding; however, for purposes of computing basic earnings per share, non-vested restricted stock awards are excluded.

Dividends

Certain of the Company’s credit facilities contain a provision requiring the Company to maintain a ratio of consolidated debt to capitalization equal to or less than 0.65:1, which has the effect of limiting the amount of dividends the Company can pay in order to maintain compliance with this provision. The effect of this provision as of December 31, 2007 was to restrict approximately $197 million as payments for dividends of total retained earnings of approximately $2.8 billion. There are no other effective limitations with respect to the Company’s ability to pay dividends.

NOTE 10 — EARNINGS PER SHARE

The Company reports both basic and diluted earnings per share. Basic earnings per share is computed by dividing income from continuing operations by the weighted average number of common shares outstanding during the period. The calculation of diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period and the repurchase of common shares that would have occurred with proceeds from the assumed issuance. Diluted earnings per share assume the exercise of stock options. Non-vested restricted stock awards are included in the number of common shares outstanding; however, for purposes of computing basic earnings per share, non-vested restricted stock awards are excluded. A reconciliation of both calculations is presented in the following table:


(in Millions, except per share amounts)	2007		2006		2005
Basic Earnings per Share
Income from continuing operations	$	787	$	389	$	272

Average number of common shares outstanding		169		177		175

Income per share of common stock based on weighted average number of shares outstanding	$	4.64	$	2.19	$	1.56


Diluted Earnings per Share
Income from continuing operations	$	787	$	389	$	272

Average number of common shares outstanding		169		177		175
Incremental shares from stock-based awards		1		1		1

Average number of dilutive shares outstanding		170		178		176

Income per share of common stock assuming issuance of incremental shares	$	4.62	$	2.18	$	1.55

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Options to purchase approximately 2,100 shares of common stock in 2007, 100,000 shares of common stock in 2006, and two million shares in 2005 were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares, thus making these options anti-dilutive.

NOTE 11 — LONG-TERM DEBT

Long-Term Debt

The Company’s long-term debt outstanding and weighted average interest rates⁽¹⁾ of debt outstanding at December 31 were:


(in Millions)	2007			2006
Mortgage bonds, notes, and other
DTE Energy Debt, Unsecured
6.7% due 2009 to 2033	$	1,496		$	1,669
Detroit Edison Taxable Debt, Principally Secured
5.9% due 2010 to 2038		2,305			2,267
Detroit Edison Tax Exempt Revenue Bonds (2)
5.3% due 2008 to 2036		1,213			1,213
MichCon Taxable Debt, Principally Secured
6.1% due 2008 to 2033		715			745
Other Long-Term Debt, Including Non-Recourse Debt		196			259

	$	5,925		$	6,153
Less debt associated with assets held for sale		(22	)		—
Less amount due within one year		(327	)		(235	)

	$	5,576		$	5,918


Securitization bonds
6.4% due 2008 to 2015	$	1,185		$	1,295
Less amount due within one year		(120	)		(110	)

	$	1,065		$	1,185


Trust preferred — linked securities
7.8% due 2032	$	186		$	186
7.5% due 2044		103			103

	$	289		$	289


(1)		Weighted average interest rates as of December 31, 2007 are shown below the description of each category of debt.

(2)		Detroit Edison Tax Exempt Revenue Bonds are issued by a public body that loans the proceeds to Detroit Edison on terms substantially mirroring the Revenue Bonds.

Debt Issuances

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

(in Millions)

Month

Company

Issued

Type

Interest Rate

Maturity

Amount

Detroit Edison

December

Senior Notes (1)

6.47

March 2038


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

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Debt Retirements and Redemptions

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

(in Millions)

Month

Company

Retired

Type

Interest Rate

Maturity

Amount

MichCon

May

First mortgage bonds

7.21

May 2007

DTE Energy

August

Senior notes

5.63

August 2007

173

Detroit Edison

December

Other long term debt

7.61

June 2011

Total Retirements

250

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


											2013 and
(in Millions)	2008		2009		2010		2011		2012		thereafter		Total

Amount to mature	$	447	$	352	$	670	$	914	$	453	$	4,571	$	7,407

Trust Preferred-Linked Securities

DTE Energy has interests in various unconsolidated trusts that were formed for the sole purpose of issuing preferred securities and lending the gross proceeds to the Company. The sole assets of the trusts are debt securities of DTE Energy with terms similar to those of the related preferred securities. Payments the Company makes are used by the trusts to make cash distributions on the preferred securities it has issued.

The Company has the right to extend interest payment periods on the debt securities. Should the Company exercise this right, it cannot declare or pay dividends on, or redeem, purchase or acquire, any of its capital stock during the deferral period.

DTE Energy has issued certain guarantees with respect to payments on the preferred securities. These guarantees, when taken together with the Company’s obligations under the debt securities and related indenture, provide full and unconditional guarantees of the trusts’ obligations under the preferred securities.

Financing costs for these issuances were paid for and deferred by DTE Energy. These costs are being amortized using the straight-line method over the estimated lives of the related securities.

Remarketable Securities

At December 31, 2007, $75 million of MichCon notes were subject to periodic remarketings. The notes are subject to mandatory or optional tender on June 30, 2008. The Company directs the remarketing agents to remarket these securities at the lowest interest rate necessary to produce a par bid. In the event that a remarketing fails, the Company would be required to purchase the securities. The notes are classified as long-term debt due to the expected successful remarketing in 2008.

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Cross Default Provisions

Substantially all of the net utility properties of Detroit Edison and MichCon are subject to the lien of mortgages. Should Detroit Edison or MichCon fail to timely pay their indebtedness under these mortgages, such failure may create cross defaults in the indebtedness of DTE Energy.

Other

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

NOTE 12 — PREFERRED SECURITIES

Preferred and Preference Securities — Authorized and Unissued

As of December 31, 2007, the amount of authorized and unissued stock is as follows:


Company	Type of Stock	Par Value		Shares Authorized

DTE Energy	Preferred	None			5,000,000

Detroit Edison	Preferred	$	100		6,747,484
Detroit Edison	Preference	$	1		30,000,000

MichCon	Preferred	$	1		7,000,000
MichCon	Preference	$	1		4,000,000

NOTE 13 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

DTE Energy and its wholly-owned subsidiaries, Detroit Edison and MichCon, have entered into revolving credit facilities with similar terms. The five-year credit facilities are with a syndicate of banks and may be used for general corporate borrowings, but are intended to provide liquidity support for each of the companies’ commercial paper programs. The aggregate availability under these combined facilities is $1.9 billion as shown in the following table:


(in Millions)	DTE Energy		Detroit Edison		MichCon		Total
Five-year unsecured revolving facility, dated October 2005	$	675	$	69	$	181	$	925
Five-year unsecured revolving facility, dated October 2004		525		206		244		975

Aggregate availability	$	1,200	$	275	$	425	$	1,900

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Borrowings under the facilities are available at prevailing short-term interest rates. The agreements require the Company to maintain a debt to total capitalization ratio of no more than 0.65 to l. Should the Company have delinquent debt obligations of at least $50 million to any creditor, such delinquency will be considered a default under our credit agreements. DTE Energy, Detroit Edison and MichCon are currently in compliance with these financial covenants. At December 31, 2007 and December 31, 2006, respectively, the Company had approximately $82 million and $123 million of letters of credit outstanding against these facilities.

At December 31, 2007, the Company had outstanding commercial paper of $761 million and other short-term borrowings of $323 million, including Detroit Edison and MichCon bank loans described below. At December 31, 2006, the Company had outstanding commercial paper of $1.031 billion and other short-term borrowings of $100 million.

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

DTE Energy has a $40 million letter of credit and reimbursement agreement. Provisions for an automatic one-year extension and conversion to a two-year term loan are available as long as certain conditions are met.

In conjunction with maintaining certain exchange traded risk management positions, the Company may be required to post cash collateral with its clearing agent. The Company has a demand financing agreement for up to $150 million with its clearing agent. The amount outstanding under this agreement was $13 million and $23 million at December 31, 2007 and 2006, respectively.

Detroit Edison has a $200 million short-term financing agreement secured by customer accounts receivable. This agreement contains certain covenants related to the delinquency of accounts receivable. Detroit Edison is currently in compliance with these covenants. The Company had an outstanding balance of $125 million and $100 million at December 31, 2007 and 2006, respectively.

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

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NOTE 14 — CAPITAL AND OPERATING LEASES

Lessee — The Company leases various assets under capital and operating leases, including coal cars, office buildings, a warehouse, computers, vehicles and other equipment. The lease arrangements expire at various dates through 2031. Future minimum lease payments under non-cancelable leases at December 31, 2007 were:


	Capital			Operating
(in Millions)	Leases			Leases
2008	$	15		$	44
2009		15			36
2010		14			28
2011		12			22
2012		9			21
Thereafter		41			82

Total minimum lease payments (1)		106		$	233

Less imputed interest		(24	)

Present value of net minimum lease payments		82
Less Assets held for sale		(33	)

Less current portion		(8	)

Non-current portion	$	41


(1)		Future minimum operating lease payments include $22 million associated with assets held for sale.

Rental expense for operating leases was $60 million in 2007, $72 million in 2006, and $68 million in 2005.

Lessor — MichCon leases a portion of its pipeline system to the Vector Pipeline Partnership through a capital lease contract that expires in 2020, with renewal options extending for five years. The components of the net investment in the capital lease at December 31, 2007, were as follows:


(in Millions)
2008	$	9
2009		9
2010		9
2011		9
2012		9
Thereafter		71

Total minimum future lease receipts		116
Residual value of leased pipeline		40
Less unearned income		(78	)

Net investment in capital lease		78
Less current portion		(2	)

	$	76

NOTE 15 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

The Company complies with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. Under SFAS No. 133, all derivatives are recognized on the Consolidated Statement of Financial Position at their fair value unless they qualify for certain scope exceptions, including normal purchases and normal sales exception. Further, derivatives that qualify and are designated for hedge accounting are classified as either hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge), or as hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge). For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the value of

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the underlying exposure is deferred in Accumulated other comprehensive income and later reclassified into earnings when the underlying transaction occurs. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For derivatives that do not qualify or are not designated for hedge accounting, changes in the fair value are recognized in earnings each period.

The Company’s primary market risk exposure is associated with commodity prices, credit, interest rates and foreign currency. The Company has risk management policies to monitor and decrease market risks. The Company uses derivative instruments to manage some of the exposure. The Company uses derivative instruments for trading purposes in its Energy Trading segment and the coal marketing activities of its Coal and Gas Midstream segment. The fair value of all derivatives is included in “Assets or liabilities from risk management and trading activities” on the Consolidated Statements of Financial Position.

Commodity Price Risk and Foreign Currency Risk

Utility Operations

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

MichCon — MichCon purchases, stores, transmits and distributes natural gas and sells storage and transportation capacity. MichCon has fixed-priced contracts for portions of its expected gas supply requirements through 2011. MichCon may also sell forward storage and transportation capacity contracts. These gas-supply, firm transportation, and storage contracts are designated and qualify for the normal purchases and sales exemption and are therefore accounted for under the accrual method.

Non-Utility Operations

Power and Industrial Projects — These business segments manage and operate on-site energy and steel related projects, landfill gas recovery and power generation assets. These businesses utilize fixed-priced contracts in the marketing and management of their assets. These contracts are not derivatives and are therefore accounted for under the accrual method.

Unconventional Gas Production — The Unconventional Gas business is engaged in unconventional gas project development and production. The Company uses derivative contracts to manage changes in the price of natural gas. These derivatives are designated as cash flow hedges. Amounts recorded in other comprehensive loss will be reclassified to earnings, specifically as a component of operating revenues, as the related production affects earnings through 2010. In 2007 and 2006, $222 million and $86 million, respectively, of after-tax losses were reclassified to earnings, principally related to the Antrim business. See Note 3 for further discussion of the discontinuance of a portion of cash flow hedge accounting upon sale of the Antrim business. In 2008, management estimates reclassifying an after-tax gain of approximately $1 million to earnings related to the Barnett cash flows.

Energy Trading — Commodity Price Risk — Energy Trading markets and trades wholesale electricity and natural gas physical products, energy financial instruments, and provides risk management services utilizing energy commodity derivative instruments. Forwards, futures, options and swap agreements are used to manage exposure to the risk of market price and volume fluctuations in its operations. These derivatives are accounted for by recording changes in fair value to earnings, specifically as a component of Operating revenues, unless certain hedge accounting criteria are met. This fair value accounting better aligns financial reporting with the way the business is managed and its performance is measured. Energy Trading experiences earnings

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volatility as a result of its gas inventory and other non-derivative assets that do not qualify for fair value accounting under accounting principles generally accepted in the U.S. Although the risks associated with these asset positions are substantially offset, requirements to fair value the related derivatives result in unrealized gains and losses being recorded to earnings that eventually reverse upon settlement.

Energy Trading — Foreign Currency Risk — Energy Trading has foreign currency forward contracts to hedge fixed Canadian dollar commitments existing under power purchase and sale contracts and gas transportation contracts. The Company entered into these contracts to mitigate any price volatility with respect to fluctuations of the Canadian dollar relative to the U.S. dollar. Certain of these contracts were designated as cash flow hedges with changes in fair value recorded to Other comprehensive income. Amounts recorded to Other comprehensive income are classified to Operating revenues or Fuel, purchased power and gas expense when the related hedged item impacts earnings.

For derivatives designated as cash flow hedges, amounts recorded in Other comprehensive income will be reclassified to earnings, specifically as a component of Operating revenues, as the related forecasted transaction affects earnings through 2008. In 2007 and 2006, $7 million and $8 million, respectively, of after-tax losses were reclassified to earnings. In 2008, management estimates reclassifying an after-tax gain of approximately $1 million to earnings.

Coal and Gas Midstream — These business units are primarily engaged in services related to transportation of coal as well as the transportation, processing and storage of natural gas. These businesses utilize fixed-priced contracts in their marketing and management of their businesses. Generally these contracts are not derivatives and are therefore accounted for under the accrual method. The business unit also engages in coal marketing which includes the marketing and trading of physical coal products and coal financial instruments. Certain of these physical and financial coal contracts are derivatives and are accounted for by recording changes in fair value to earnings, specifically as a component of Operating revenues, unless certain hedge accounting criteria are met.

Credit Risk

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

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

Interest Rate Risk

The Company uses interest rate swaps, treasury locks and other derivatives to hedge the risk associated with interest rate market volatility. In 2004 and 2000, the Company entered into a series of interest rate derivatives to limit its sensitivity to market interest rate risk associated with the issuance of long-term debt. Such instruments were designated as cash flow hedges. The Company subsequently issued long-term debt and terminated these hedges at a cost that is included in other comprehensive loss. Amounts recorded in other comprehensive loss will be reclassified to Interest expense as the related interest affects earnings through 2030. In 2008, the Company estimates reclassifying $4 million of losses to earnings.

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Fair Value of Other Financial Instruments

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

2007

2006

Fair Value

Carrying Value

Fair Value

Carrying Value

Long-Term Debt

$7.6 billion

$7.4 billion

$8.0 billion

$7.7 billion

NOTE 16 — COMMITMENTS AND CONTINGENCIES

Environmental

Electric Utility

Air — Detroit Edison is subject to EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. In March 2005, EPA issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, Detroit Edison has spent approximately $1.1 billion through 2007. The Company estimates Detroit Edison future capital expenditures at up to $282 million in 2008 and up to $2.4 billion of additional capital expenditures through 2018 to satisfy both the existing and proposed new control requirements.

Water — In response to an EPA regulation, Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of the studies to be conducted over the next several years, Detroit Edison may be required to install additional control technologies to reduce the impacts of the water intakes. Initially, it was estimated that Detroit Edison could incur up to approximately $55 million over the four to six years subsequent to 2007 in additional capital expenditures to comply with these requirements. However, a recent court decision remanded back to the EPA several provisions of the federal regulation that may result in a delay in compliance dates. The decision also raised the possibility that Detroit Edison may have to install cooling towers at some facilities at a cost substantially greater than was initially estimated for other mitigative technologies.

Contaminated Sites — Detroit Edison conducted remedial investigations at contaminated sites, including three former manufactured gas plant (MGP) sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is approximately $15 million that was accrued in 2007 and is expected to be incurred over the next several years. In addition, Detroit Edison expects to make approximately $6 million of capital improvements to the ash landfill in 2008.

Gas Utility

Contaminated 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. Gas Utility owns, or previously owned, 15 such former MGP sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites. Cleanup activities associated with these sites will be conducted over the next several years.

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The MPSC has established a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites. Accordingly, Gas Utility recognizes a liability and corresponding regulatory asset for estimated investigation and remediation costs at former MGP sites. During 2007, the Company spent approximately $2 million investigating and remediating these former MGP sites. The Company accrued an additional $1 million in remediation liabilities to increase the reserve balance to $40 million as of December 31, 2007, with a corresponding increase in the regulatory asset.

Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows. However, the Company anticipates the cost deferral and rate recovery mechanism approved by the MPSC will prevent environmental costs from having a material adverse impact on our results of operations.

Non-Utility

The Company’s non-utility affiliates are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants. The Company is in the process of installing new environmental equipment at our coke battery facilities in Michigan. The Company expects the projects to be completed within two years. The coke battery facilities received and responded to information requests from the EPA resulting in the issuance of a notice of violation regarding potential maximum achievable control technologies and new source review violations. The EPA is in the process of reviewing the Company’s position of demonstrated compliance and has not initiated escalated enforcement. At this time, the Company cannot predict the impact of this issue. The Company’s non-utility affiliates are substantially in compliance with all environmental requirements, other than as noted above.

Guarantees

In certain limited circumstances, the Company enters into contractual guarantees. The Company may guarantee another entity’s obligation in the event it fails to perform. The Company may provide guarantees in certain indemnification agreements. Finally, the Company may provide indirect guarantees for the indebtedness of others. Below are the details of specific material guarantees the Company currently provides.

Millennium Pipeline Project Guarantee

The Company owns a 26.25% equity interest in the Millennium Pipeline Project (Millennium). Millennium is accounted for under the equity method. Millennium is expected to begin commercial operations in November 2008.

On August 29, 2007, Millennium entered into a borrowing facility to finance the construction costs of the project. The total facility amounts to $800 million and is guaranteed by the project partners, based upon their respective ownership percentages. The facility expires on August 29, 2010. The amount outstanding under this facility was $153 million at December 31, 2007. Proceeds of the facility are being used to fund project costs and expenses relating to the development, construction and commercial start up and testing of the pipeline project and for general corporate purposes. In addition, the facility has been utilized to reimburse the project partners for costs and expenses incurred in connection with the project for the period subsequent to June 1, 2004 through immediately prior to the closing of the facility. The Company received approximately $23.5 million in September 2007 as reimbursement for costs and expenses incurred by it during the above-mentioned period. The Company accounted for this reimbursement as a return of capital.

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The Company has agreed to guarantee 26.25% of the borrowing facility in the event of default by Millennium. The guarantee includes DTE Energy’s revolving credit facility’s covenant and default provisions by reference. The Company has also provided performance guarantees in regards to completion of Millennium to the major shippers in an amount of approximately $16 million. The maximum potential amount of future payments under these guarantees is approximately $226 million. There are no recourse provisions or collateral that would enable us to recover any amounts paid under the guarantees other than our share of project assets.

Parent Company Guarantee of Subsidiary Obligations

The Company has issued guarantees for the benefit of various non-utility subsidiary transactions. In the event that DTE Energy’s credit rating is downgraded below investment grade, certain of these guarantees would require the Company to post cash or letters of credit valued at approximately $488 million at December 31, 2007. This estimated amount fluctuates based upon commodity prices (primarily power and gas) and the provisions and maturities of the underlying agreements.

Other Guarantees

The Company’s other guarantees are not individually material with maximum potential payments totaling $10 million at December 31, 2007.

Labor Contracts

There are several bargaining units for the Company’s represented employees. In October 2007, a new three-year agreement was ratified by approximately 950 employees in our gas operations. In December 2007, a new three-year agreement was ratified by approximately 3,100 employees in our electric operations and corporate services. The contracts of the remaining represented employees expire at various dates in 2008 and 2009.

Purchase Commitments

Detroit Edison has an Energy Purchase Agreement to purchase steam and electricity from the Greater Detroit Resource Recovery Authority (GDRRA). Under the Agreement, Detroit Edison will purchase steam through 2008 and electricity through June 2024. In 1996, a charge to income was recorded that included a reserve for steam purchase commitments in excess of replacement costs from 1997 through 2008. The reserve for steam purchase commitments totaling $20 million at December 31, 2007 is being amortized to fuel, purchased power and gas expense with non-cash accretion expense being recorded through 2008. The Company estimates steam and electric purchase commitments from 2008 through 2024 will not exceed $343 million. In January 2003, the Company sold the steam heating business of Detroit Edison to Thermal Ventures II, LP. Under the terms of the sale, Detroit Edison remains contractually obligated to buy steam of $33 million from GDRRA until 2008. Also, the Company guaranteed bank loans of $13 million that Thermal Ventures II, LP may use for capital improvements to the steam heating system. During 2007, the Company recorded reserves of $13 million related to the bank loan guarantee.

As of December 31, 2007, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments and energy trading contracts. The Company estimates that these commitments will be approximately $5.9 billion from 2008 through 2051. The Company also estimates that 2008 capital expenditures will be approximately $1.5 billion. The Company has made certain commitments in connection with expected capital expenditures.

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Bankruptcies

The Company purchases and sells electricity, gas, coal, coke and other energy products from and to numerous companies operating in the steel, automotive, energy, retail and other industries. Certain of the Company’s customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. The Company regularly reviews contingent matters relating to these customers and its purchase and sale contracts and it records provisions for amounts considered at risk of probable loss. Management believes the Company’s previously accrued amounts are adequate for probable losses. The final resolution of these matters is not expected to have a material effect on the Company’s consolidated financial statements.

Other Contingencies

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

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

See Note 5 for a discussion of contingencies related to Regulatory Matters.

NOTE 17 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

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

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

The requirement to recognize the funded status of a postretirement benefit plan and the related disclosure requirements is effective for fiscal years ending after December 15, 2006. The Company adopted this requirement as of December 31, 2006. The requirement to measure plan assets and benefit obligations as

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of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. The Company plans to adopt this requirement as of December 31, 2008. Retrospective application of the changes required by SFAS No. 158 is prohibited; therefore certain disclosures below are not comparable.

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

Measurement Date

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

Qualified and Nonqualified Pension Plan Benefits

The Company has qualified defined benefit retirement plans for eligible represented and non-represented employees. The plans are noncontributory and cover substantially all employees. The plans provide traditional retirement benefits based on the employees’ years of benefit service, average final compensation and age at retirement. In addition, certain represented and non-represented employees are covered under cash balance provisions that determine benefits on annual employer contributions and interest credits. The Company also maintains supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees. These plans provide for benefits that supplement those provided by DTE Energy’s other retirement plans.

The Company’s policy is to fund qualified pension costs by contributing amounts consistent with the Pension Protection Act of 2006 provisions and additional amounts when it deems appropriate. In December 2007, the Company contributed $150 million to the qualified pension plans. The Company anticipates making up to a $150 million contribution to its qualified pension plans in 2008 and a $5 million contribution to its nonqualified pension plans in 2008.

Net pension cost includes the following components:


	Qualified Pension Plans									Nonqualified Pension Plans
(in Millions)	2007			2006			2005			2007		2006		2005
Service cost	$	60		$	62		$	64		$	2	$	2	$	2
Interest cost		174			172			169			4		4		3
Expected return on plan assets		(237	)		(222	)		(218	)		—		—		—
Amortization of:
Net actuarial loss		57			57			67			2		2		1
Prior service cost		5			7			8			1		1		—
Special termination benefits		8			49			—			—		—		—

Net pension cost	$	67		$	125		$	90		$	9	$	9	$	6

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

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


	Qualified Pension Plans					Nonqualified Pension Plans
(in Millions)	2007			2006		2007			2006
Other changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets
Net actuarial (gain)	$	(255	)	$	N/A	$	—		$	N/A
Amortization of net actuarial (gain)		(57	)		N/A		(2	)		N/A
Prior service cost		1			N/A		—			N/A
Amortization of prior service (credit)		(5	)		N/A		(1	)		N/A

Total recognized in other comprehensive income and regulatory assets	$	(316	)	$	N/A	$	(3	)	$	N/A


Total recognized in net periodic pension cost and other comprehensive income and regulatory assets	$	(249	)	$	N/A	$	6		$	N/A


Estimated amounts to be amortized from accumulated other comprehensive income and regulatory assets into net periodic benefit cost during next fiscal year
Net actuarial loss	$	32		$	56	$	2		$	2
Prior service cost		5			5		1			1

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

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The following table reconciles the obligations, assets and funded status of the plans as well as the amounts recognized as prepaid pension cost or pension liability in the Consolidated Statement of Financial Position at December 31:


	Qualified Pension Plans						Nonqualified Pension Plans
(in Millions)	2007			2006			2007			2006
Accumulated benefit obligation, end of year	$	2,767		$	2,934		$	69		$	73


Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	3,171		$	3,013		$	75		$	67
Service cost		60			62			2			2
Interest cost		174			172			4			4
Actuarial (gain) loss		(212	)		78			—			7
Benefits paid		(224	)		(197	)		(9	)		(5	)
Special termination benefits		8			49			—			—
Plan amendments		1			(6	)		—			—

Projected benefit obligation, end of year	$	2,978		$	3,171		$	72		$	75


Change in plan assets
Plan assets at fair value, beginning of year	$	2,744		$	2,617		$	—		$	—
Actual return on plan assets		280			324			—			—
Company contributions		180			—			9			5
Benefits paid		(224	)		(197	)		(9	)		(5	)

Plan assets at fair value, end of year	$	2,980		$	2,744		$	—		$	—


Funded status of the plans	$	2		$	(427	)	$	(72	)	$	(75	)
December contribution		150			180			1			—

Funded status, end of year	$	152		$	(247	)	$	(71	)	$	(75	)


Amount recorded as:
Noncurrent assets	$	152		$	71		$	—		$	—
Current liabilities		—			—			(4	)		(5	)
Noncurrent liabilities		—			(318	)		(67	)		(70	)

	$	152		$	(247	)	$	(71	)	$	(75	)


Amounts recognized in accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	175		$	186		$	5		$	7
Prior service (credit)		(8	)		(10	)		—			—
Amounts recognized in regulatory assets
Net actuarial loss	$	456		$	756		$	21		$	21
Prior service cost		17			24			1			1

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


	2007			2006			2005
Projected benefit obligation
Discount rate		6.5	%		5.7	%		5.9	%
Rate of compensation increase		4.0	%		4.0	%		4.0	%

Net pension costs
Discount rate		5.7	%		5.9	%		6.0	%
Rate of compensation increase		4.0	%		4.0	%		4.0	%
Expected long-term rate of return on plan assets		8.75	%		8.75	%		9.0	%

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


(in Millions)
2008	$	189
2009		194
2010		200
2011		204
2012		212
2013 - 2017		1,179

Total	$	2,178

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

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

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


	2007			2006
Equity securities		66	%		68	%
Debt securities		19			23
Other		15			9

		100	%		100	%

124

The Company’s plans’ weighted-average asset target allocations by asset category at December 31, 2007 were as follows:


Equity securities	55	%
Debt securities	20
Other	25

	100	%

The Company also sponsors defined contribution retirement savings plans. Participation in one of these plans is available to substantially all represented and non-represented employees. The Company matches employee contributions up to certain predefined limits based upon eligible compensation, the employee’s contribution rate and, in some cases, years of credited service. The cost of these plans was $29 million in each of the years 2007, 2006, and 2005.

Other Postretirement Benefits

The Company provides certain postretirement health care and life insurance benefits for employees who are eligible for these benefits. The Company’s policy is to fund certain trusts to meet its postretirement benefit obligations. Separate qualified Voluntary Employees Beneficiary Association (VEBA) trusts exist for represented and non-represented employees. In December 2007, the Company made cash contributions of $76 million to its postretirement benefit plans. In January 2008, the Company made cash contributions of $40 million to its postretirement benefit plans. At the discretion of management, the Company may make up to a $116 million contribution to its VEBA trusts in 2008.

Net postretirement cost includes the following components:


(in Millions)	2007			2006			2005
Service cost	$	62		$	59		$	55
Interest cost		118			115			105
Expected return on plan assets		(67	)		(61	)		(70	)
Amortization of
Net loss		69			72			60
Prior service (credit)		(3	)		(3	)		(2	)
Net transition obligation		7			7			7
Special termination benefits		2			8			—

Net postretirement cost	$	188		$	197		$	155

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

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

125


(in Millions)	2007			2006
Other changes in plan assets and APBO recognized in other comprehensive income and regulatory assets
Net actuarial (gain)	$	(299	)	$	N/A
Amortization of net actuarial (gain)		(69	)		N/A
Prior service (credit)		(55	)		N/A
Amortization of prior service cost		2			N/A
Amortization of transition (asset)		(6	)		N/A

Total recognized in other comprehensive income and regulatory assets	$	(427	)	$	N/A


Total recognized in net periodic pension cost, other comprehensive income and regulatory assets	$	(239	)	$	N/A


Estimated amounts to be amortized from accumulated other comprehensive income and regulatory assets into net periodic benefit cost during next fiscal year
Net actuarial loss	$	38		$	66
Prior service (credit)	$	(6	)	$	(2	)
Net transition obligation	$	2		$	7

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

126

The following table reconciles the obligations, assets and funded status of the plans including amounts recorded as accrued postretirement cost in the Consolidated Statement of Financial Position at December 31:


(in Millions)	2007			2006
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation, beginning of year	$	2,184		$	1,991
Service cost		62			59
Interest cost		118			115
Actuarial (gain) loss		(297	)		101
Plan amendments		(55	)		2
Medicare Part D subsidy		7			1
Special termination benefits		2			8
Benefits paid		(99	)		(93	)

Accumulated postretirement benefit obligation, end of year	$	1,922		$	2,184


Change in plan assets
Plan assets at fair value, beginning of year	$	794		$	713
Actual return on plan assets		69			86
Company contributions		56			60
Benefits paid		(84	)		(65	)

Plan assets at fair value, end of year	$	835		$	794


Funded status of the plans, as of November 30	$	(1,087	)	$	(1,390	)
December adjustment		(7	)		(24	)

Funded status, as of December 31	$	(1,094	)	$	(1,414	)


Noncurrent liabilities	$	(1,094	)	$	(1,414	)

Amounts recognized in accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	75		$	85
Prior service (credit)	$	(48	)	$	(44	)
Net transition (asset)	$	(18	)	$	(35	)
Amounts recognized in regulatory assets
Net actuarial loss	$	458		$	816
Prior service cost	$	9		$	36
Net transition obligation	$	29		$	74

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


	2007			2006			2005
Projected benefit obligation
Discount rate		6.50	%		5.70	%		5.90	%

Net benefit costs
Discount rate		5.70	%		5.90	%		6.00	%
Expected long-term rate of return on plan assets		8.75	%		8.75	%		9.00	%
Health care trend rate pre-65		8.00	%		9.00	%		9.00	%
Health care trend rate post-65		7.00	%		8.00	%		8.00	%
Ultimate health care trend rate		5.00	%		5.00	%		5.00	%
Year in which ultimate reached		2011			2011			2011

127

A one-percentage-point increase in health care cost trend rates would have increased the total service cost and interest cost components of benefit costs by $27 million and increased the accumulated benefit obligation by $227 million at December 31, 2007. A one-percentage-point decrease in the health care cost trend rates would have decreased the total service and interest cost components of benefit costs by $24 million and would have decreased the accumulated benefit obligation by $217 million at December 31, 2007.

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


(in Millions)
2008	$	121
2009		130
2010		135
2011		141
2012		145
2013 - 2017		780

Total	$	1,452

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

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


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

		100	%		100	%

The Company’s plans’ weighted-average asset target allocations by asset category at December 31, 2007 were as follows:


Equity securities	55	%
Debt securities	20
Other	25

	100	%

In December 2003, the Medicare Act was signed into law which provides for a non-taxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least “actuarially equivalent” to the benefit established by law. The effects of the subsidy reduced net periodic postretirement benefit costs by $16 million in 2007, $17 million in 2006, and $20 million in 2005.

128

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


(in Millions)
2008	$	5
2009		5
2010		5
2011		6
2012		6
2013 - 2017		34

Total	$	61

Grantor Trust

MichCon maintains a Grantor Trust that invests in life insurance contracts and income securities. Employees and retirees have no right, title or interest in the assets of the Grantor Trust, and MichCon can revoke the trust subject to providing the MPSC with prior notification. The Company accounts for its investment at fair value with unrealized gains and losses recorded to earnings.

NOTE 18 — STOCK-BASED COMPENSATION

The DTE Energy Stock Incentive Plan permits the grant of incentive stock options, non-qualifying stock options, stock awards, performance shares and performance units. Participants in the plan include the Company’s employees and members of its Board of Directors. In 2006, the Company adopted a new Long-Term Incentive Program (LTIP).

The following are the key points of the LTIP:

	•		Authorized limit is 9,000,000 shares of common stock;

	•		Prohibits the grant of a stock option with an exercise price that is less than the fair market value of the Company’s stock on the date of the grant; and

	•		Imposes the following award limits to a single participant in a single calendar year, (1) options for more than 500,000 shares of common stock; (2) stock awards for more than 150,000 shares of common stock; (3) performance share awards for more than 300,000 shares of common stock (based on the maximum payout under the award); or (4) more than 1,000,000 performance units, which have a face amount of $1.00 each.

Effective January 1, 2006, the Company adopted SFAS No. 123(R), Share-Based Payment, using the modified prospective transition method. Under this method, the Company records compensation expense at fair value over the vesting period for all awards it grants after the date it adopted the standard. In addition, the Company is required to record compensation expense at fair value (as previous awards continue to vest) for the unvested portion of previously granted stock option awards that were outstanding as of the date of adoption. Pre-adoption grants of stock awards and performance shares will continue to be expensed. DTE Energy did not make the one-time election to adopt the alternative transition method described in FSP SFAS No. 123(R)-3, Transition Election Related to Accounting for the Tax Effect of Share-Based Payment Awards, but has chosen instead to follow the original guidance provided by SFAS No. 123(R) in accounting for the tax effects of stock based compensation awards.

Stock-based compensation for the reporting periods is as follows:


(in Millions)	2007		2006		2005
Stock-based compensation expense	$	28	$	24	$	13
Tax benefit of compensation expense	$	10	$	8	$	5

129

The cumulative effect of the adoption of SFAS No. 123(R) in 2006 was an increase in net income of $1 million as a result of estimating forfeitures for previously granted stock awards and performance shares. The Company has not restated any prior periods as a result of the adoption of SFAS No. 123(R). The Company generally purchases shares on the open market for options that are exercised or it may settle in cash other stock-based compensation.

Options

Options are exercisable according to the terms of the individual stock option award agreements and expire 10 years after the date of the grant. The option exercise price equals the fair value of the stock on the date that the option was granted. Stock options granted vest ratably over a three-year period.

Stock option activity was as follows:


						(in Millions)
				Weighted		Aggregate
	Number of			Average		Intrinsic
	Options			Exercise Price		Value
Options outstanding at January 1, 2007		5,667,197		$	41.60
Granted		419,400		$	47.57
Exercised		(1,654,148	)	$	41.07
Forfeited or expired		(37,640	)	$	43.45

Options outstanding at December 31, 2007		4,394,809		$	42.37	$	26


Options exercisable at December 31, 2007		3,306,313		$	41.36	$	23

As of December 31, 2007, the weighted average remaining contractual life for the exercisable shares is 4.91 years. As of December 31, 2007, 1,088,496 options were non-vested. During 2007, 874,984 options vested.

The weighted average grant date fair value of options granted during 2007, 2006, and 2005 was $6.46, $6.12, and $5.89, respectively. The intrinsic value of options exercised for the years ended December 31, 2007, 2006 and 2005 was $16 million, $6 million, and $8 million, respectively. Total option expense recognized during 2007 and 2006 was $4 million and $6 million, respectively.

The number, weighted average exercise price and weighted average remaining contractual life of options outstanding were as follows:


						Weighted
				Weighted		Average
Range of		Number of		Average		Remaining
Exercise Prices		Options		Exercise Price		Contractual Life (years)
$	27.00 - $38.00		188,531	$	30.89		1.88
$	38.01 - $42.00		1,997,431	$	40.64		4.83
$	42.01 - $45.00		1,446,534	$	43.91		7.00
$	45.01 - $50.00		762,313	$	46.77		6.72

			4,394,809	$	42.37		5.74

130

The Company determined the fair value for these options at the date of grant using a Black-Scholes based option pricing model and the following assumptions:


	December 31			December 31			December 31
	2007			2006			2005
Risk-free interest rate		4.71	%		4.58	%		3.93	%
Dividend yield		4.38	%		4.75	%		4.60	%
Expected volatility		17.99	%		19.79	%		19.56	%

Expected life	6 years			6 years			6 years

In connection with the adoption of SFAS No. 123(R), the Company reviewed and updated its forfeiture, expected term and volatility assumptions. The Company modified option volatility to include both historical and implied share-price volatility. Implied volatility is derived from exchange traded options on DTE Energy common stock. The Company’s expected life estimate is based on industry standards.

Pro forma information for the period ended December 31, 2005 is provided to show what the Company’s net income and earnings per share would have been if compensation costs had been determined as prescribed by SFAS No. 123(R):


	December 31
(in Millions, except per share amounts)	2005
Net income as reported	$	537
Less: total stock-based expense		(4	)

Pro forma net income	$	533


Earnings per share
Basic — as reported	$	3.07

Basic — pro forma	$	3.05


Diluted — as reported	$	3.05

Diluted — pro forma	$	3.03

Stock Awards

Stock awards granted under the plan are restricted for varying periods, which are generally for three years. Participants have all rights of a shareholder with respect to a stock award, including the right to receive dividends and vote the shares. Prior to vesting in stock awards, the participant: (i) may not sell, transfer, pledge, exchange or otherwise dispose of shares; (ii) shall not retain custody of the share certificates; and (iii) will deliver to the Company a stock power with respect to each stock award.

The stock awards are recorded at cost that approximates fair value on the date of grant. The cost is amortized to compensation expense over the vesting period.

131

Stock award activity for the periods ended December 31 was:


	2007		2006		2005
Fair value of awards vested (in Millions)	$	10	$	5	$	4
Restricted common shares awarded		620,125		282,555		288,360
Weighted average market price of shares awarded	$	49.48	$	43.64	$	44.95
Compensation cost charged against income (in Millions)	$	16	$	10	$	8

The following table summarizes the Company’s stock awards activity for the period ended December 31, 2007:


	Restricted			Weighted Average Grant Date
	Stock			Fair Value
Balance at January 1, 2007		666,136		$	43.20
Grants		620,125		$	49.48
Forfeitures		(62,139	)	$	46.55
Vested		(239,812	)	$	41.53

Balance at December 31, 2007		984,310		$	47.36

Performance Share Awards

Performance shares awarded under the plan are for a specified number of shares of common stock that entitle the holder to receive a cash payment, shares of common stock or a combination thereof. The final value of the award is determined by the achievement of certain performance objectives and market conditions. The awards vest at the end of a specified period, usually three years. The Company accounts for performance share awards by accruing compensation expense over the vesting period based on: (i) the number of shares expected to be paid which is based on the probable achievement of performance objectives; and (ii) the grant date fair value of the shares.

The Company recorded compensation expense as follows:


(in Millions)	2007		2006		2005
Compensation expense	$	7	$	8	$	5
Cash settlements (1)	$	5	$	4	$	5

(1) Approximates the intrinsic value of the liability.

During the vesting period, the recipient of a performance share award has no shareholder rights. However, recipients will be paid an amount equal to the dividend equivalent on such shares. Performance share awards are nontransferable and are subject to risk of forfeiture.

132

The following table summarizes the Company’s performance share activity for the period ended December 31, 2007:


	Performance Shares
Balance at January 1, 2007		1,035,696
Grants		489,765
Forfeitures		(84,043	)
Payouts		(267,265	)


Balance at December 31, 2007		1,174,153

Unrecognized Compensation Costs

As of December 31, 2007, there was $37 million of total unrecognized compensation cost related to non-vested stock incentive plan arrangements. That cost is expected to be recognized over a weighted-average period of 1.28 years.


	(In Millions)
	Unrecognized
	Compensation		(in years)
	Cost		Weighted Average to be Recognized
Stock awards	$	22		1.16
Performance shares		13		1.48
Options		2		1.26

	$	37		1.28

The tax benefit realized for tax deductions related to the Company’s stock incentive plan totaled $10 million for the period ended December 31, 2007. Approximately $1.4 million, $1.6 million, and $1 million of compensation cost was capitalized as part of fixed assets during 2007, 2006, and 2005, respectively.

NOTE 19 — SEGMENT AND RELATED INFORMATION

Based on the following structure, the Company sets strategic goals, allocates resources and evaluates 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 and industrial 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, a gas utility that distributes natural gas to approximately 17,000 customers in Adrian, Michigan.

133

Non-Utility Operations

	•		Coal and Gas Midstream, primarily consisting of coal transportation and marketing, and gas pipelines, processing and storage;

	•		Unconventional Gas Production, primarily consisting of unconventional gas project development and production;

	•		Power and Industrial Projects, consisting of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers, and biomass energy projects; and

	•		Energy Trading, primarily consisting of energy marketing and trading operations.

The income tax provisions or benefits of DTE Energy’s subsidiaries are determined on an individual company basis and recognize the tax benefit of production tax credits and net operating losses. The subsidiaries record income tax payable to or receivable from DTE Energy resulting from the inclusion of its taxable income or loss in DTE Energy’s consolidated federal tax return.

Inter-segment billing for goods and services exchanged between segments is based upon tariffed or market-based prices of the provider and primarily consists of power sales, gas sales and coal transportation services in the following segments:


(in Millions)	2007			2006		2005
Electric Utility	$	36		$	59	$	207
Gas Utility		5			16		13
Coal and Gas Midstream		191			180		152
Unconventional Gas Production		64			134		154
Power and Industrial Projects		23			6		6
Energy Trading		7			75		116
Corporate & Other		(35	)		7		54

	$	291		$	477	$	702

134

Financial data of the business segments follows:


				Depreciation,
	Operating			Depletion &			Interest			Interest			Income			Net			Total				Capital
(in Millions)	Revenue			Amortization			Income			Expense			Taxes			Income			Assets		Goodwill		Expenditures

2007
Electric Utility	$	4,900		$	764	$		(7	)	$	294		$	149		$	317		$	14,854	$	1,206	$	809
Gas Utility		1,875			93			(10	)		61			23			70			3,266		772		226
Non-utility Operations:
Coal and Gas Midstream		837			8			(2	)		14			30			53			540		13		53
Unconventional Gas Production (1)		(228	)		22			—			13			(117	)		(217	)		355		2		161
Power and Industrial Projects		473			39			(9	)		25			(5	)		30			471		27		48
Energy Trading		955			5			(5	)		11			17			32			1,125		17		2

		2,037			74			(16	)		63			(75	)		(102	)		2,491		59		264

Corporate & Other (1)		(15	)		1			(51	)		174			267			502			2,369		—		—
Reconciliation and Eliminations		(291	)		—			59			(59	)		—			—			—		—		—

Total from Continuing Operations	$	8,506		$	932	$		(25	)	$	533		$	364			787			22,980		2,037		1,299


Discontinued Operations (Note 3)																	205			774		—		—
Reconciliation and Eliminations																	(21	)		—		—		—

Total from Discontinued Operations																	184			774		—		—

Total																$	971		$	23,754	$	2,037	$	1,299


(1)		Operating Revenues and Net Loss of the Unconventional Gas Production segment in 2007 reflect the recognition of losses on hedge contracts associated with the Antrim sale transaction. Net Income of the Corporate & Other segment in 2007 results principally from the gain recognized on the Antrim sale transaction. See Note 3.


				Depreciation,
	Operating			Depletion &		Interest			Interest			Income			Net			Total				Capital
(in Millions)	Revenue			Amortization		Income			Expense			Taxes			Income			Assets		Goodwill		Expenditures

2006
Electric Utility	$	4,737		$	809	$	(4	)	$	278		$	161		$	325		$	14,540	$	1,206	$	972
Gas Utility		1,849			94		(9	)		67			11			50			3,123		773		155
Non-utility Operations:
Coal and Gas Midstream		707			4		(3	)		10			28			50			435		13		53
Unconventional Gas Production		99			27		—			13			5			9			611		8		186
Power and Industrial Projects		409			48		(8	)		29			(56	)		(80	)		864		36		35
Energy Trading		830			6		(12	)		15			49			96			1,220		17		2

		2,045			85		(23	)		67			26			75			3,130		74		276

Corporate & Other		5			2		(52	)		174			(52	)		(61	)		2,307		—		—
Reconciliation and Eliminations		(477	)		—		62			(61	)		—			—			—		—		—

Total from Continuing Operations	$	8,159		$	990	$	(26	)	$	525		$	146			389			23,100		2,053		1,403


Discontinued Operations (Note 3)																43			685		4		—
Cumulative Effect of Accounting Change																1			—		—		—

Total															$	433		$	23,785	$	2,057	$	1,403

135


				Depreciation,
	Operating			Depletion &		Interest			Interest			Income			Net			Total				Capital
(in Millions)	Revenue			Amortization		Income			Expense			Taxes			Income			Assets		Goodwill		Expenditures

2005
Electric Utility	$	4,462		$	640	$	(3	)	$	267		$	149		$	277		$	13,112	$	1,207	$	722
Gas Utility		2,138			95		(10	)		58			(2	)		37			3,101		772		128
Non-utility Operations:
Coal and Gas Midstream		707			3		(3	)		4			22			45			373		12		28
Unconventional Gas Production		74			20		—			8			1			4			434		8		144
Power and Industrial Projects		428			48		(5	)		20			(7	)		4			1,043		37		29
Energy Trading		977			4		(3	)		17			(23	)		(43	)		1,834		17		8

		2,186			75		(11	)		49			(7	)		10			3,684		74		209

Corporate & Other		10			—		(40	)		187			(34	)		(52	)		2,358		—		4
Reconciliation and Eliminations		(702	)		—		42			(43	)		—			—			—		—		—

Total from Continuing Operations	$	8,094		$	810	$	(22	)	$	518		$	106			272			22,255		2,053		1,063


Discontinued Operations (Note 3)																268			1,080		4		2
Cumulative Effect of Accounting Change																(3	)		—		—		—

Total															$	537		$	23,335	$	2,057	$	1,065

136

NOTE 20 — SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly earnings per share may not total for the years, since quarterly computations are based on weighted average common shares outstanding during each quarter. Synthetic Fuels was reported as a discontinued operation beginning in the fourth quarter of 2007, resulting in the adjustment of prior quarterly results. See Note 3.


	First		Second			Third		Fourth
(in Millions, except per share amounts)	Quarter		Quarter(1)			Quarter		Quarter(2)		Year
2007
Operating Revenues	$	2,463	$	1,692		$	2,140	$	2,211	$	8,506
Operating Income	$	270	$	736		$	298	$	331	$	1,635
Net Income
From continuing operations	$	96	$	348		$	152	$	191	$	787
Discontinued operations		38		37			45		64		184

Total	$	134	$	385		$	197	$	255	$	971


Basic Earnings per Share
From continuing operations	$	.54	$	2.00		$	.93	$	1.17	$	4.64
Discontinued operations		.22		.21			.27		.40		1.09

Total	$	.76	$	2.21		$	1.20	$	1.57	$	5.73


Diluted Earnings per Share
From continuing operations	$	.54	$	1.99		$	.92	$	1.17	$	4.62
Discontinued operations		.22		.21			.27		.39		1.08

Total	$	.76	$	2.20		$	1.19	$	1.56	$	5.70


2006
Operating Revenues	$	2,361	$	1,706		$	2,054	$	2,038	$	8,159
Operating Income	$	295	$	138		$	335	$	292	$	1,060
Net Income (Loss)
From continuing operations	$	115	$	2		$	146	$	126	$	389
Discontinued operations		20		(35	)		42		16		43
Cumulative effect of accounting change		1		—			—		—		1

Total	$	136	$	(33	)	$	188	$	142	$	433

Basic Earnings (Loss) per Share
From continuing operations	$	.64	$	.01		$	.83	$	.71	$	2.19
Discontinued operations		.12		(.20	)		.23		.09		.24
Cumulative effect of accounting change		.01		—			—		—		.01

Total	$	.77	$	(.19	)	$	1.06	$	.80	$	2.44

Diluted Earnings (Loss) per Share
From continuing operations	$	.64	$	.01		$	.83	$	.71	$	2.18
Discontinued operations		.12		(.20	)		.23		.09		.24
Cumulative effect of accounting change		—		—			—		—		.01

Total	$	.76	$	(.19	)	$	1.06	$	.80	$	2.43


(1)		In the second quarter of 2007, the Company recorded a $900 million ($580 million after-tax) gain on the Antrim sale transaction and $323 million ($210 million after-tax) of losses on hedge contracts associated with the Antrim sale. In the second quarter of 2006, the Company recorded impairments, reserves and deferrals of potential gains in the synthetic fuel business. See Note 3.

(2)		In the fourth quarter of 2007, the Company recorded adjustments that increased operating income by $20 million ($13 million after-tax) to correct prior amounts. These adjustments were primarily to record property, plant and equipment and deferred CTA costs at Detroit Edison for expenditures that had been expensed in earlier quarters of 2007.

137


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

None.


Item 9A.		Controls and Procedures

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


Item 9B.		Other Information

Annual Incentive Plan

On February 25, 2008, the Organization and Compensation Committee of the DTE Energy Company (“Company”) Board of Directors approved 2008 performance measures and targets for Anthony F. Earley Jr., David E. Meador, Gerard M. Anderson and Bruce D. Peterson under the Company’s Annual Incentive Plan (“AIP”). These named executive officers and other executives may receive cash awards under the AIP. For 2008, the AIP has seven annual measures for Messrs. Earley, Meador, Anderson and Peterson weighted as follows in determining the total annual incentive award: Company earnings per share (30%), Company cash flow (30%), customer satisfaction improvement (10%), MPSC complaint reduction improvement (10%), safety (10%), diversity hiring minority (5%) and diversity hiring female (5%).

On February 25, 2008, the Organization and Compensation Committee also approved AIP performance measures and targets for Robert J. Buckler, a named executive officer. For 2008, the AIP has eight annual measures for Mr. Buckler weighted as follows in determining the total annual incentive award: Detroit Edison net income (20%), Detroit Edison cash flow (20%), customer satisfaction improvement (15%), MPSC complaint reduction improvement (15%), Company earnings per share (10%), safety (10%), diversity hiring minority (5%) and diversity hiring female (5%). Detroit Edison is a wholly owned subsidiary of the Company.

Based on market comparisons, each officer position is assigned a target award expressed as a percentage of base salary. Targets for these officers range from 60% to 100%, including the Chief Executive Officer. Award amounts paid to each officer are determined as follows: (1) The executive's most recent year-end base salary is multiplied by an AIP target percentage to arrive at the target award; (2) the overall performance payout percentage, which can range from 0% to 175%, is determined based on final results compared to threshold, target and maximum levels for each objective; (3) the target award is then multiplied by the performance payout percentage to arrive at the calculated award; and (4) the calculated award is then adjusted by an individual performance modifier (assessment of an individual executive's achievements for the year), which can range from 0% to 150%, to arrive at the final award.

For 2008, the AIP for Messrs. Earley, Meador, Anderson and Peterson has an additional incremental component related to the "amount of monetization proceeds" measure from the 2007 AIP. Results for this measure, which comprised 10% of the target total 2007 annual incentive award, will be recalculated based on the original 2007 incentive metrics but using a December 31, 2008 target completion date. Calculated award amounts will be reduced by the amounts paid with respect to this measure as part of the 2007 AIP and paid as an additional component of 2008 AIP awards to these named executive officers.

Long-Term Incentive Plan

On February 25, 2008, the Organization and Compensation Committee of the Company’s Board of Directors approved 2008 performance measures and targets for executive officers under the DTE Energy Company 2006 Long-Term Incentive Plan (“LTIP”). The LTIP, which was approved by our shareholders, rewards long-term growth and profitability by providing a vehicle through which officers, other key employees and outside directors may receive stock-based compensation. Stock-based compensation directly links individual performance with shareholder interests. Based on market comparisons, each officer position is assigned a target award expressed as a percentage of base salary. The target award may be modified by the Organization and Compensation Committee and is then delivered in the form of restricted stock, stock options and performance shares. Targets for these officers range from 115% to 275%, including the Chief Executive Officer.

Performance shares: Performance shares entitle the executive to receive a specified number of shares, or a cash payment equal to the fair market value of the shares, or a combination thereof, depending on the level of achievement of performance measures. The performance measurement period for the 2008 award is January 1, 2008 through December 31, 2010. Payments earned under the 2008 award can range from 0% to 200% of target, based upon achievement of three corporate performance measures weighted as follows: (1) balance sheet health (20%), (2) total shareholder return vs. total shareholder return of peer group companies (40%), and (3) business unit specific measures (40%). For Messrs. Earley, Meador, Anderson and Peterson, the business unit specific measure is Company earnings per share growth rate. For Mr. Buckler, the business unit specific measure is Detroit Edison’s average return on equity.

Part III


Item 10.		Directors, Executive Officers and Corporate Governance


Item 11.		Executive Compensation


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


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


Item 14.		Principal Accountant Fees and Services

Information required by Part III (Items 10, 11, 12, 13 and 14) of this Form 10-K is incorporated by reference from DTE Energy’s definitive Proxy Statement for its 2008 Annual Meeting of Common Shareholders to be held May 15, 2008. The Proxy Statement will be filed with the Securities and Exchange Commission, pursuant to Regulation 14A, not later than 120 days after the end of our fiscal year covered by this report on Form 10-K, all of which information is hereby incorporated by reference in, and made part of, this Form 10-K, except that the information required by Item 10 with respect to executive officers of the Registrant is included in Part I of this Report.

138

Part IV


Item 15.		Exhibits and Financial Statement Schedules

(a)

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

	(1)		Consolidated financial statements. See “Item 8 – Financial Statements and Supplementary Data.”

	(2)		Financial statement schedules. See “Item 8 – Financial Statements and Supplementary Data.”

	(3)		Exhibits.


(i)		Exhibits filed herewith.

10-73		First Amendment, dated February 8, 2007 to the DTE Energy Company 2006 Long-Term Incentive Plan.

10-74		Second Amendment, dated March 8, 2007 to the DTE Energy Company 2006 Long-Term Incentive Plan.

12-40		Computation of Ratio of Earnings to Fixed Charges.

21-3		Subsidiaries of the Company

23-20		Consent of Deloitte & Touche LLP.

31-37		Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report.

31-38		Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report.

99-25		Sixteenth Amendment, dated as of July 30, 2004, to Master Trust Agreement (“Master Trust”), dated as of June 30, 1994, between The Detroit Edison Company and Fidelity Management Trust Company.

99-26		Eighteenth Amendment, dated as of June 1, 2006, to Master Trust

99-27		Nineteenth Amendment, dated as of July 31, 2007, to Master Trust

(ii)		Exhibits incorporated herein by reference.

3(a)		Amended and Restated Articles of Incorporation of DTE Energy Company, dated December 13, 1995 (Exhibit 3-5 to Form 10-Q for the quarter ended September 30, 1997).

3(b)		Certificate of Designation of Series A Junior Participating Preferred Stock of DTE Energy Company, dated September 23, 1997 (Exhibit 3-6 to Form 10-Q for the quarter ended September 30, 1997).

3(c)		Bylaws of DTE Energy Company, as amended through February 24, 2005 (Exhibit 3.1 to Form 8-K dated February 24, 2005).

4(a)		Amended and Restated Indenture, dated as of April 9, 2001, between DTE Energy Company and Bank of New York, as trustee (Exhibit 4.1 to Registration Statement on Form S-3 (File No. 333-58834)).

4(b)		Supplemental Indenture, dated as of May 30, 2001, between DTE Energy Company and Bank of New York, as trustee (Exhibit 4-226 to Form 10-Q for the quarter ended June 30, 2001). (6.45% Senior Notes due 2006 and 7.05% Senior Notes due 2011).

4(c)		Supplemental Indenture, dated as of April 5, 2002 between DTE Energy Company and Bank of New York, as trustee (Exhibit 4-230 to Form 10-Q for the quarter ended March 31, 2002). (2002 Series A 6.65% Senior Notes due 2009).

139


4(d)		Supplemental Indenture, dated as of April 1, 2003, between DTE Energy Company and Bank of New York, as trustee, creating 2003 Series A 6 3/8% Senior Notes due 2033 (Exhibit 4(o) to Form 10-Q for the quarter ended March 31, 2003). (2003 Series A 6 3/8% Senior Notes due 2033).

4(e)		Supplemental Indenture, dated as of May 15, 2006, between DTE Energy Company and Bank of New York, as trustee (Exhibit 4-239 to Form 10-Q for the quarter ended June 30, 2006). (2006 Series B 6.35% Senior Notes due 2016).

4(f)		Amended and Restated Trust Agreement of DTE Energy Trust I, dated as of January 15, 2002 (Exhibit 4-229 to Form 10-K for the year ended December 31, 2001).

4(g)		Amended and Restated Trust Agreement of DTE Energy Trust II, dated as of June 1, 2004 (Exhibit 4(q) to Form 10-Q for the quarter ended June 30, 2004).

4(h)		Trust Agreement of DTE Energy Trust III (Exhibit 4-21 to Registration Statement on Form S-3 (File No. 333-99955).

10(a)		Form of 1995 Indemnification Agreement between DTE Energy Company and its directors and officers (Exhibit 3L (10-1) to Form 8-B dated January 2, 1996).

10(b)		Form of Indemnification Agreement dated as of December 6., 2007 between DTE Energy Company and each of Anthony F. Earley, Jr., Gerard M. Anderson, Robert J. Buckler and David E. Meador. (Exhibit 10-1 to Form 8-K dated December 6, 2007).

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

10(d)		Certain arrangements pertaining to the employment of Gerard M. Anderson with The Detroit Edison Company, dated October 6, 1993 (Exhibit 10-48 to The Detroit Edison Company’s Form 10-K for the year ended December 31, 1993).

10(e)		Certain arrangements pertaining to the employment of David E. Meador with The Detroit Edison Company, dated January 14, 1997 (Exhibit 10-5 to Form 10-K for the year ended December 31, 1996).

10(f)		Certain arrangements pertaining to the employment of Bruce D. Peterson, dated May 22, 2002 (Exhibit 10-48 to Form 10-Q for the quarter ended June 30, 2002).

10(g)		Termination and Consulting Agreement, dated as of October 4, 1999, among DTE Energy Company, MCN Energy Group Inc., DTE Enterprises Inc. and A.R. Glancy, III (Exhibit 10-41 to Form 10-K for the year ended December 31, 2001).

10(h)		Amended and Restated Post-Employment Income Agreement, dated March 23, 1998, between The Detroit Edison Company and Anthony F. Earley, Jr. (Exhibit 10-21 to Form 10-Q for the quarter ended March 31, 1998).

10(i)		Executive Post-Employment Income Arrangement, dated March 27, 1989, between The Detroit Edison Company and S. Martin Taylor (Exhibit 10-22 to Form 10-Q for the quarter ended March 31, 1998).

10(j)		DTE Energy Company Annual Incentive Plan (Exhibit 10-44 to Form 10-Q for the quarter ended March 31, 2001).

10(k)		DTE Energy Company 2001 Stock Incentive Plan (Exhibit 10-43 to Form 10-Q for the quarter ended March 31, 2001).

10(l)		DTE Energy Company 2006 Long-Term Incentive Plan (Annex A to DTE Energy’s Definitive Proxy Statement dated March 24, 2006).

10(m)		DTE Energy Company Deferred Stock Compensation Plan for Non-Employee Directors (as amended and restated effective as of January 1, 1999) (Exhibit 10-30 to Form 10-K for the year ended December 31, 1998).

140


10(n)		First Amendment to the DTE Energy Company Deferred Stock Compensation Plan for Non-Employee Directors, effective January 1, 2001 (Exhibit 10-66 to Form 10-K for the year ended December 31, 2006).

10(o)		Second Amendment to the DTE Energy Company Deferred Stock Compensation Plan for Non-Employee Directors, effective January 1, 2005 (Exhibit 10-67 to Form 10-K for the year ended December 31, 2006).

10(p)		Third Amendment to the DTE Energy Company Deferred Stock Compensation Plan for Non-Employee Directors, effective January 1, 2006 (Exhibit 10-68 to Form 10-K for the year ended December 31, 2006).

10(q)		DTE Energy Company Retirement Plan for Non-Employee Directors’ Fees (as amended and restated effective as of December 31, 1998) (Exhibit 10-31 to Form 10-K for the year ended December 31, 1998).

10(r)		DTE Energy Company Plan for Deferring the Payment of Director’s Fees (as amended and restated effective as of January 1, 1999) (Exhibit 10-29 to Form 10-K for the year ended December 31, 1998).

10(s)		DTE Energy Company Supplemental Savings Plan, effective as of December 6, 2001 (Exhibit 10-44 to Form 10-Q for the quarter ended June 30, 2002).

10(t)		Amendment to the DTE Energy Company Supplemental Savings Plan (Exhibit 10-54 to Form 10-Q for the quarter ended September 30, 2004).

10(u)		DTE Energy Company Executive Deferred Compensation Plan, effective as of January 1, 2002 (Exhibit 10-45 to Form 10-Q for the quarter ended June 30, 2002).

10(v)		First Amendment to the DTE Energy Company Executive Deferred Compensation Plan, effective as of October 1, 2003, (Exhibit 10-61 to Form 10-K for the year ended December 31, 2005).

10(w)		Second Amendment to the DTE Energy Company Executive Deferred Compensation Plan (Exhibit 10-55 to Form 10-Q for the quarter ended September 30, 2004).

10(x)		Third Amendment to the DTE Energy Company Executive Deferred Compensation Plan, effective December 31, 2006 (Exhibit 10-69 to Form 10-K for the year ended December 31, 2006).

10(y)		DTE Energy Company Supplemental Retirement Plan, effective as of January 1, 2002 (Exhibit 10-46 to Form 10-Q for the quarter ended June 30, 2002).

10(z)		First Amendment to the DTE Energy Company Supplemental Retirement Plan, effective January 1, 2002 (Exhibit 10-70 to Form 10-K for the year ended December 31, 2006).

10(aa)		Amendment to the DTE Energy Company Supplemental Retirement Plan (Exhibit 10-53 to Form 10-Q for the quarter ended September 30, 2004).

10(bb)		DTE Energy Company Executive Supplemental Retirement Plan, effective as of January 1, 2001 (Exhibit 10-51 to Form 10-Q for the quarter ended September 30, 2004).

10(cc)		First Amendment to the DTE Energy Company Executive Supplemental Retirement Plan (Exhibit 10-52 to Form 10-Q for the quarter ended September 30, 2004).

10(dd)		Second Amendment to the DTE Energy Company Executive Supplemental Retirement Plan (Exhibit 10-60 to Form 10-K for the year ended December 31, 2005).

10(ee)		Third Amendment to the DTE Energy Company Executive Supplemental Retirement Plan (Exhibit 10-65 to Form 10-Q for the quarter ended September 30, 2006).

10(ff)		Fourth Amendment to the DTE Energy Company Executive Supplemental Retirement Plan (Exhibit 10-72 to Form 10-Q for the quarter ended September 30, 2007).

141


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

10(hh)		Description of Executive Life Insurance Plan (Exhibit 10-47 to Form 10-Q for the quarter ended June 30, 2002).

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

10(jj)		DTE Energy Affiliates Nonqualified Plans Master Trust, effective as of May 1, 2003 (Exhibit 10-49 to Form 10-Q for the quarter ended March 31, 2003).

10(kk)		Form of Change-in-Control Severance Agreement, dated as of March 11, 2005, between DTE Energy Company and each of Anthony F. Earley, Jr., Gerard M. Anderson, Robert J. Buckler, Stephen E. Ewing and David E. Meador (Exhibit 10-56 to Form 10-K for the year ended December 31, 2004).

10(ll)		Form of DTE Energy Five-Year Credit Agreement, dated as of October 17, 2005, by and among DTE Energy, the lenders party thereto, Citibank, N.A., as Administrative Agent, and Barclays Bank PLC and JPMorgan Chase Bank, N. A. as Co-Syndication Agents (Exhibit 10.1 to Form 8-K dated October 17, 2005).

10(mm)		Amendment No. 1 to Five-Year Credit Agreement, dated as of January 10, 2007, by and among, DTE Energy Company, the lenders party thereto, Citibank, N.A., as Administrative Agent, and Barclays Bank PLC and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.1 to Form 8-K dated January 10, 2007).

10(nn)		Form of Second Amended and Restated Five-Year Credit Agreement, dated as of October 17, 2005, by and among DTE Energy, the lenders party thereto, Citibank, N.A., as Administrative Agent, and Barclays Bank PLC and JPMorgan Chase Bank, N.A. as Co-Syndication Agents (Exhibit 10.2 to Form 8-K dated October 17, 2005).

10(oo)		Amendment No. 1 to Second Amended and Restated Five-Year Credit Agreement, dated as of January 10, 2007 by and among DTE Energy Company, the lenders party thereto, and Citibank, N.A., as Administrative Agent and Barclays Bank PLC and JP Morgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.2 to Form 8-K dated January 10, 2007).

10(pp)		Form of Director Restricted Stock Agreement (Exhibit 10.1 to Form 8-K dated June 23, 2005).

10(qq)		Form of Director Restricted Stock Agreement pursuant to the DTE Energy Company Long-Term Incentive Plan (Exhibit 10.1 to Form 8-K dated June 29, 2006).

10(rr)		Form of Change-in-Control Severance Agreement, dated as of November 8, 2007, between DTE Energy Company and each of Anthony F Earley, Jr., Gerard M. Anderson, Robert J. Buckler, and David E. Meador (Exhibit 10-71 to Form 10-Q for the quarter ended September 30, 2007).

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

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

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

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

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

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

142


99(g)		Sixth Amendment, dated as of September 1, 1998, to Master Trust (Exhibit 99-15 to Form 10-K for the year ended December 31, 2004).

99(h)		Seventh Amendment, dated as of December 15, 1999, to Master Trust (Exhibit 99-16 to Form 10-K for the year ended December 31, 2004).

99(i)		Eighth Amendment, dated as of February 1, 2000, to Master Trust (Exhibit 99-17 to Form 10-K for the year ended December 31, 2004).

99(j)		Ninth Amendment, dated as of April 1, 2000, to Master Trust (Exhibit 99-18 to Form 10-K for the year ended December 31, 2004).

99(k)		Tenth Amendment, dated as of May 1, 2000, to Master Trust (Exhibit 99-19 to Form 10-K for the year ended December 31, 2004).

99(l)		Eleventh Amendment, dated as of July 1, 2000, to Master Trust (Exhibit 99-20 to Form 10-K for the year ended December 31, 2004).

99(m)		Twelfth Amendment, dated as of August 1, 2000, to Master Trust (Exhibit 99-21 to Form 10-K for the year ended December 31, 2004).

99(n)		Thirteenth Amendment, dated as of December 21, 2001, to Master Trust (Exhibit 99-22 to Form 10-K for the year ended December 31, 2004).

99(o)		Fourteenth Amendment, dated as of March 1, 2002, to Master Trust (Exhibit 99-23 to Form 10-K for the year ended December 31, 2004).

99(p)		Fifteenth Amendment, dated as of January 1, 2002, to Master Trust (Exhibit 99-24 to Form 10-K for the year ended December 31, 2004).

(iii)		Exhibits furnished herewith.

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

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

143

DTE Energy Company

Schedule II – Valuation and Qualifying Accounts


	Year Ending December 31,
(in Millions)	2007			2006			2005
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statement of Financial Position)
Balance at Beginning of Period	$	170		$	136		$	129
Additions:
Charged to costs and expenses		133			120			106
Charged to other accounts (1)		12			7			9
Deductions (2)		(133	)		(93	)		(108	)

Balance At End of Period	$	182		$	170		$	136


(1)		Collection of accounts previously written off.

(2)		Uncollectible accounts written off.


	Year Ending December 31,
(in Millions)	2007			2006		2005
Note Receivable Reserve
Balance at Beginning of Period	$	65		$	—	$	—
Additions:
Charged to costs and expenses — shown as deduction in the Consolidated Statement of Financial Position from:
Other Current Assets		—			50		—
Notes Receivable		—			15		—
Deductions		(61	)		—		—

Balance At End of Period	$	4		$	65	$	—

144

Signatures

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


		DTE ENERGY COMPANY

		(Registrant)

Date: March 7, 2008	By	/s/ ANTHONY F. EARLEY, JR.

		Anthony F. Earley, Jr.
		Chairman of the Board and
		Chief Executive Officer

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


By	/s/ ANTHONY F. EARLEY, JR.	By	/s/ DAVID E. MEADOR

	Anthony F. Earley, Jr.		David E. Meador
	Chairman of the Board and		Executive Vice President and
	Chief Executive Officer		Chief Financial Officer

By	/s/ PETER B. OLEKSIAK	By	/s/ JOHN E. LOBBIA

	Peter B. Oleksiak		John E. Lobbia, Director
	Vice President and Controller, and
	Chief Accounting Officer

By	/s/ LILLIAN BAUDER	By	/s/ GAIL J. McGOVERN

	Lillian Bauder, Director		Gail J. McGovern, Director

By	/s/ W. FRANK FOUNTAIN	By	/s/ EUGENE A. MILLER

	W. Frank Fountain, Director		Eugene A. Miller, Director

By	/s/ ALLAN D. GILMOUR	By	/s/ CHARLES W. PRYOR, JR.

	Allan D. Gilmour, Director		Charles W. Pryor, Jr., Director

By	/s/ ALFRED R. GLANCY III	By	/s/ JOSUE ROBLES, JR.

	Alfred R. Glancy III, Director		Josue Robles, Jr., Director

By	/s/ FRANK M. HENNESSEY	By	/s/ RUTH G. SHAW

	Frank M. Hennessey, Director		Ruth G. Shaw, Director

		By	/s/ JAMES H. VANDENBERGHE

			James H. Vandenberghe, Director

Date: March 7, 2008

145