10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________________________________________

Form 10-K

þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2011
¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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.)
One Energy Plaza, 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	New York Stock Exchange
2011 Series I 6.5% Junior Subordinated Debentures due 2061	New York Stock Exchange

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files).  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 (Do not check if a smaller reporting company) Smaller Reporting company o

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

On June 30, 2011, the aggregate market value of the Registrant’s voting and non-voting common equity held by non-affiliates was approximately $8.5 billion (based on the New York Stock Exchange closing price on such date). There were 169,403,378 shares of common stock outstanding at January 31, 2012.

Certain information in DTE Energy Company’s definitive Proxy Statement for its 2012 Annual Meeting of Common Shareholders to be held May 3, 2012, 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, 2011

TABLE OF CONTENTS

		Page
Definitions		1
Forward-Looking Statements		3
PART I
Items 1 & 2.	Business and Properties	4
Item 1A.	Risk Factors	17
Item 1B.	Unresolved Staff Comments	21
Item 3.	Legal Proceedings	21
Item 4.	Mine Safety Disclosures	22
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
Item 6.	Selected Financial Data	26
Item 7.	Management’s Discussion And Analysis of Financial Condition and Results of Operations	26
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	46
Item 8.	Financial Statements and Supplementary Data	49
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	118
Item 9A.	Controls and Procedures	118
Item 9B.	Other Information	118
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	118
Item 11.	Executive Compensation	118
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	118
Item 13.	Certain Relationships and Related Transactions, and Director Independence	118
Item 14.	Principal Accountant Fees and Services	118
PART IV
Item 15.	Exhibits and Financial Statement Schedules	118
Signatures		127
EX-12.49
EX-21.7
EX-23.25
EX-31.71
EX-31.72
EX-32.71
EX-32.72
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

DEFINITIONS

ASC	Accounting Standards Codification
ASU	Accounting Standards Update
CIM	A Choice Incentive Mechanism authorized by the MPSC that allows Detroit Edison to recover or refund non-fuel revenues lost or gained as a result of fluctuations in electric Customer Choice sales.
Citizens	Citizens Fuel Gas Company, which distributes natural gas in Adrian, Michigan
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	Michigan legislation giving customers 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
FTRs	Financial transmission rights are financial instruments that entitle the holder to receive payments related to costs incurred for congestion on the transmission grid.
GCR	A Gas Cost Recovery mechanism authorized by the MPSC that allows MichCon to recover through rates its natural gas costs.
MCIT	Michigan Corporate Income Tax
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 is an Independent System Operator and the Regional Transmission Organization serving the Midwest United States and Manitoba, Canada.
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.
NRC	United States Nuclear Regulatory Commission
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.

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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.
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 costs.
RDM	A Revenue Decoupling Mechanism authorized by the MPSC that is designed to minimize the impact on revenues of changes in average customer usage of electricity and natural gas.
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.
Subsidiaries	The direct and indirect subsidiaries of DTE Energy Company
Unconventional Gas	Includes those gas and oil deposits that originated and are stored in coal bed, tight sandstone and shale formations.
VIE	Variable Interest Entity
Units of Measurement
Bcf	Billion cubic feet of gas
Bcfe	Conversion metric using a standard ratio of one barrel of oil and/or natural gas liquids to 6 Mcf of natural gas equivalents.
BTU	Heat value (energy content) of fuel
dth/d	Decatherms per day
kWh	Kilowatthour of electricity
Mcf	Thousand cubic feet of gas
MMcf	Million cubic feet of gas
MW	Megawatt of electricity
MWh	Megawatthour of electricity

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FORWARD-LOOKING STATEMENTS

Certain information presented herein includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 with respect to the financial condition, results of operations and business of DTE Energy. Words such as “anticipate,” “believe,” “expect,” “projected” and “goals” signify forward-looking statements. Forward-looking statements are not guarantees of future results and conditions, but rather are subject to numerous assumptions, risks and uncertainties that may cause actual future results to be materially different from those contemplated, projected, estimated or budgeted. Many factors may impact forward-looking statements including, but not limited to, the following:

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

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

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

• economic conditions and population changes in our geographic area resulting in changes in demand, customer conservation, increased thefts of electricity and gas and high levels of uncollectible accounts receivable;

• environmental issues, laws, regulations, and the increasing costs of remediation and compliance, including actual and potential new federal and state requirements;

• health, safety, financial, environmental and regulatory risks associated with ownership and operation of nuclear facilities;

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

• volatility in the short-term natural gas storage markets impacting third-party storage revenues;

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

• instability in capital markets which could impact availability of short and long-term financing;

• the timing and extent of changes in interest rates;

• the level of borrowings;

• the potential for losses on investments, including nuclear decommissioning and benefit plan assets and the related increases in future expense and contributions;

• the potential for increased costs or delays in completion of significant construction projects;

• the uncertainties of successful exploration of unconventional gas and oil resources and challenges in estimating gas and oil reserves with certainty;

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

• unplanned outages;

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

• employee relations and the impact of collective bargaining agreements;

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

• cost reduction efforts and the maximization of plant and distribution system performance;

• the effects of competition;

• 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;

• binding arbitration, litigation and related appeals; and

• the risks discussed in our public filings with the Securities and Exchange Commission.

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

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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 other 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 2.1 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, transportation, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan and the sale of storage and transportation capacity.

Our other businesses are involved in 1) natural gas pipelines, gathering and storage; 2) unconventional gas and oil project development and production; 3) power and industrial projects and coal transportation and marketing; 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 Investors - Reports and Filings 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 23 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

• The Electric Utility segment consists principally of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million residential, commercial and industrial customers in southeastern Michigan.

Gas Utility

• The Gas Utility segment consists of MichCon and Citizens. MichCon is engaged in the purchase, storage, transportation, distribution and sale of natural gas to approximately 1.2 million residential, commercial and industrial customers throughout Michigan and the sale of storage and transportation capacity. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.

Non-Utility Operations

• Gas Storage and Pipelines consists of natural gas pipelines, gathering and storage businesses.

• Unconventional Gas Production is engaged in unconventional gas and oil project development and production.

• Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers; provide coal transportation and marketing; and sell

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electricity from biomass-fired energy projects.

• Energy Trading consists of energy marketing and trading operations.

Corporate and Other, includes various holding company activities, 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 principally 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 fossil-fuel 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 three major classes of customers: residential, commercial and industrial, principally throughout southeastern Michigan.

Revenue by Service

	2011		2010		2009
	(In millions)
Residential	$	2,182	$	2,052	$	1,820
Commercial	1,704		1,629		1,702
Industrial	692		688		730
Other	458		479		299
Subtotal	5,036		4,848		4,551
Interconnection sales (1)	118		145		163
Total Revenue	$	5,154	$	4,993	$	4,714

_______________________________________

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

Weather, economic factors, competition and electricity prices affect sales levels to customers. Our peak load and highest total system sales generally occur during the third quarter of the year, driven by air conditioning and other cooling-related demands. Our operations are not dependent upon a limited number of customers, and the loss of any one or a few customers would not have a material adverse effect on Detroit Edison.

Fuel Supply and Purchased Power

Our power is generated from a variety of fuels and is supplemented with purchased power. We expect to have an adequate supply of fuel and purchased power to meet our obligation to serve customers. Our generating capability is heavily dependent upon the availability of coal. Coal is purchased from various sources in different geographic areas under agreements that vary in both pricing and terms. We expect to obtain the majority of our coal requirements through long-term contracts,

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with the balance to be obtained through short-term agreements and spot purchases. We have long-term and short term contracts for the purchase of approximately 29 million tons of low-sulfur western coal to be delivered from 2012 through 2014 and approximately 6 million tons of Appalachian coal to be delivered from 2012 through 2014. All of these contracts have pricing schedules. We have approximately 95% of our 2012 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 our expected western rail requirements under contract for the next four years. All of our expected eastern coal rail requirements are under contract through 2012 and approximately 50% of this requirement is under contract in 2013. Our expected vessel transportation requirements for delivery of purchased coal to our generating facilities are under contract through 2014.

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, 2011 are as follows:

	Location by Michigan	Summer Net Rated Capability (1)
Plant Name	County	(MW)	(%)	Year in Service
Fossil-fueled Steam-Electric
Belle River (2)	St. Clair	1,047	10.0	1984 and 1985
Greenwood	St. Clair	782	7.5	1979
Harbor Beach	Huron	93	0.9	1968
Monroe (3)	Monroe	2,893	27.7	1971, 1973 and 1974
River Rouge	Wayne	525	5.0	1957 and 1958
St. Clair	St. Clair	1,382	13.3	1953, 1954, 1959, 1961 and 1969
Trenton Channel	Wayne	674	6.5	1949 and 1968
		7,396	70.9
Oil or Gas-fueled Peaking Units	Various	1,026	9.8	1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric Fermi 2 (4)	Monroe	1,086	10.4	1988
Hydroelectric Pumped Storage Ludington (5)	Mason	917	8.9	1973
		10,425	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) The Belle River capability represents Detroit Edison’s entitlement to 81% 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.

(3) The Monroe generating plant provided 38% of Detroit Edison’s total 2011 power generation.

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

(5) 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.

In December 2011, the Connors Creek (239 MW) and Marysville (84 MW) generating plants and Unit No. 5 at the St. Clair generating plant (250 MW) were retired consistent with Detroit Edison's operational plan.

In 2008, a renewable portfolio standard was established for Michigan electric providers targeting 10% of electricity sold to retail customers from renewable energy by 2015. Detroit Edison has approximately 500 MW of owned or contracted renewable energy at December 31, 2011 representing approximately 6% of electricity sold to retail customers. Approximately

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120 MW is in commercial operation at December 31, 2011 with an additional 380 MW expected in commercial operation in 2012 or early 2013.

Detroit Edison owns and operates 671 distribution substations with a capacity of approximately 33,516,000 kilovolt-amperes (kVA) and approximately 428,300 line transformers with a capacity of approximately 24,421,000 kVA.

Circuit miles of electric distribution lines owned and in service as of December 31, 2011:

	Circuit Miles
Operating Voltage-Kilovolts (kV)	Overhead	Underground
4.8 kV to 13.2 kV	28,544	14,105
24 kV	182	696
40 kV	2,277	382
120 kV	54	8
	31,057	15,191

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, an unrelated company, 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 Notes 3, 8, 11 and 19 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. We also partner with federal, state and local officials to attempt to increase the share of low-income funding allocated to our customers. Changes in the level of funding provided to our low-income customers will affect the level of uncollectible expense.

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 and network reliability we continue to make capital investments in our generating plants and distribution system, which will improve plant availability, operating efficiencies and environmental compliance in areas that have a positive impact on reliability 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, subject to limits. Customers choosing to purchase power from alternative electric suppliers represented approximately 10% of retail sales in 2011 and 2010 and 3% of retail sales in 2009. Customers

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participating in the electric Customer Choice program consist primarily of industrial and commercial customers whose MPSC-authorized full service rates exceed market costs. MPSC rate orders and 2008 energy legislation enacted by the State of Michigan are adjusting the pricing disparity over five years and have placed a 10% cap on the total potential Customer Choice related migration, mitigating some of the unfavorable effects of electric Customer Choice on our financial performance. In addition, we had a Choice Incentive Mechanism, which was an over/under recovery mechanism that measured non-fuel revenues lost or gained as a result of fluctuations in electric Customer Choice sales. Effective with the October 2011 MPSC rate order, this mechanism has been terminated and our customer rates reflect the current level of electric Customer Choice sales. We expect that in 2012 customers choosing to purchase power from alternative electric suppliers will represent approximately 10% of retail sales.

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

	2011		2010		2009
	(In millions)
Gas sales	$	1,150	$	1,281	$	1,443
End user transportation	194		185		144
Intermediate transportation	58		69		69
Storage and other	103		113		132
Total Revenue	$	1,505	$	1,648	$	1,788

• 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 is 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 transportation system to transport the natural gas to storage fields, processing plants, pipeline interconnections or other locations.

• Storage and other — Includes revenues from natural gas storage, 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. We are minimizing the impacts of changes in average customer usage through regulatory mechanisms which decouple our revenue levels from sales volumes.

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.

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Natural Gas Supply

Our gas distribution system has a planned maximum daily send-out capacity of 2.4 Bcf, with approximately 65% of the volume coming from underground storage for 2011. 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 the New York Mercantile Exchange and published price indices to approximate current market prices combined with MPSC approved fixed price supplies with varying terms and volumes through 2014.

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

	Availability (MMcf/d)	Contract Expiration
Great Lakes Gas Transmission L.P.	80	2013
Viking Gas Transmission Company	51	2013
Vector Pipeline L.P.	50	2015
ANR Pipeline Company	195	2017
Panhandle Eastern Pipeline Company	75	2029

Properties

We own distribution, storage and transportation properties that are located in the State of Michigan. Our distribution system includes approximately 19,000 miles of distribution mains, approximately 1,175,000 service pipelines and approximately 1,309,000 active meters. We own approximately 2,000 miles of transmission pipelines that deliver natural gas to the distribution districts and interconnect our storage fields with the sources of supply and the market areas.

We own storage properties relating to four underground natural gas storage fields with an aggregate working gas storage capacity of approximately 138 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 transportation 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 own 67 miles of transportation and gathering (non-utility) 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 18 of the Notes to Consolidated Financial Statements in Item 8 of the Report.

Regulation

MichCon's business is 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 operating-related matters. MichCon'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. MichCon operates natural gas storage and transportation facilities in Michigan as intrastate facilities regulated by the MPSC and provides intrastate storage and transportation services pursuant to an MPSC-approved tariff.

MichCon also provides interstate storage and transportation services in accordance with an Operating Statement on file with the FERC. The FERC's jurisdiction is limited and extends to the rates, non-discriminatory requirements, and the terms and conditions applicable to storage and transportation provided by MichCon in interstate markets. FERC granted MichCon authority to provide storage and related services in interstate commerce at market-based rates. MichCon provides transportation services in interstate commerce at cost-based rates approved by the MPSC and filed with the FERC.

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We are subject to the requirements of other regulatory agencies with respect to safety, the environment and health.

See Note 11 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. We also partner with federal, state and local officials to attempt to increase the share of low-income funding allocated to our customers. Changes in the level of funding provided to our low- income customers will affect the level of uncollectible expense.

Strategy and Competition

Our strategy is to be the preferred provider of natural gas services in Michigan. We expect future sales volumes to decline as a result of economic conditions, a decrease in the number of customers, reduced natural gas usage by customers due to more efficient furnaces and appliances, and an increased emphasis on conservation of energy usage. We are minimizing the impacts of changes in average customer usage through regulatory mechanisms which decouple our revenue levels from sales volumes. 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 transportation pipeline system has enabled us to market 400 to 500 Bcf annually for intermediate storage and transportation services for Michigan gas producers, marketers, distribution companies and other pipeline companies. We operate in a central geographic location with connections to major Midwestern 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 three 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, weather and natural gas pricing.

GAS STORAGE AND PIPELINES

Description

Gas Storage and Pipelines controls two natural gas storage fields and has ownership interests in two interstate pipelines serving the Midwest, Ontario and Northeast markets. The pipeline and storage assets are primarily supported by long-term, fixed-price revenue contracts.

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Properties

The Gas Storage and Pipelines business holds the following property:

Property
Classification	% Owned		Description	Location
Pipelines
Vector Pipeline	40	%	348-mile pipeline with 1,300 MMcf per day capacity	IL, IN, MI & Ontario
Millennium Pipeline	26	%	182-mile pipeline with 525 MMcf per day capacity	NY
MichCon Pipeline	100	%	543-mile pipeline	MI
Storage
Washington 10	100	%	74 Bcf of storage capacity	MI
Washington 28	50	%	16 Bcf of storage capacity	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 10 and 28 storage facilities and for the MichCon pipeline.

Regulation

The Gas Storage and Pipelines business operates natural gas storage facilities in Michigan as intrastate facilities regulated by the MPSC and provides intrastate storage and related services pursuant to an MPSC-approved tariff. We also provide interstate services in accordance with an Operating Statement on file with the FERC. Vector and Millennium Pipelines provide interstate transportation services in accordance with their FERC-approved tariffs.

Strategy and Competition

Our Gas Storage and Pipelines business expects to continue its steady growth plan by expanding existing assets and developing new assets that are typically supported with long-term customer commitments. We have competition from other pipelines and storage providers. The Gas Storage and Pipelines business focuses on asset development opportunities in the Midwest-to-Northeast region to supply natural gas to meet growing demand. Much of the growth in demand for natural gas is expected to occur in the Eastern Canada and the Northeast U.S. regions. We believe that the Vector and Millennium pipelines are well positioned to provide access routes and low-cost expansion options to these markets. In addition, we believe that Millennium Pipeline is well positioned for growth related to production from the Marcellus shale, especially with respect to Marcellus production in Northern Pennsylvania and along the southern tier of New York. Gas Storage and Pipelines has executed an agreement with Southwestern Energy Services Company to support its Bluestone lateral and gathering system. Bluestone is a 40 mile pipeline in Susquehanna County, Pennsylvania and Broome County, New York scheduled to be in service in 2012. We expect to continue steady growth in the Gas Storage and Pipelines business and are evaluating new pipeline and storage investment opportunities that could include additional Millennium expansions and laterals, Bluestone laterals and gathering expansions and other Marcellus midstream development or partnering opportunities.

UNCONVENTIONAL GAS PRODUCTION

Description

Our Unconventional Gas Production business is engaged in natural gas and oil exploration, development and production primarily within the Barnett shale in north Texas. Our acreage covers an area that produces high Btu gas which provides a significant contribution to revenues from the value of natural gas liquids extracted from the gas stream. During this period of low natural gas prices, these natural gas liquids, with prices correlated to crude oil prices, have provided a significant increase to our realized wellhead price. Our drilling efforts have and will continue to target liquids rich gas and oil producing horizons. Total capital investment of $28 million and production of 5.1 Bcfe in 2011 were slightly higher than 2010. Oil production increased 58% over 2010 levels as a result of recent drilling in the Marble Falls formation, shallow reserves lying above the Barnett shale, while gas production showed a 3% decline. We executed on leasing opportunities to optimize our existing portfolio by acquiring acreage at attractive prices in 2011, bringing our total net acreage position to 87,377 acres, net of impairments and expirations.

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Properties and Other

The following information pertains to our interests in the Barnett shale as of December 31:

	2011		2010		2009
Producing Wells (1)(2)(3)	214		194		174
Developed Lease Acreage (1)(3)(4)	16,768		15,928		14,968
Undeveloped Lease Acreage (1)(3)(5)	70,609		54,318		48,399
Production Volume (Bcfe)(6)	5.1		4.8		5.0
Proved Reserves (Bcfe)(7)	186		201		234
Capital Expenditures (in millions)	$	28	$	26	$	26
Future Undiscounted Cash Flows (in millions)(8)	$	448	$	478	$	392
Average Gas Price (per Mcf)	$	7.03	$	5.99	$	4.34
Average Oil Price (per Barrel)	$	92.79	$	76.41	$	58.47

_______________________________________

(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 impaired properties.

(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) Production volume is reported on a Bcf equivalent basis using a standard ratio of one barrel of oil and/or natural gas liquids to 6 Mcf of natural gas equivalents.

Production Volume By Product
	2011		2010		2009
Natural Gas	46	%	51	%	57	%
Natural Gas Liquids	35		36		34
Crude Oil	19		13		9
	100	%	100	%	100	%

(7) The decreases in proved reserves for 2011 and 2010 are primarily due to removal of 20 Bcfe and 17 Bcfe, respectively, of reserves that exceeded the five-year development limit for the Proved Undeveloped classification, and other revisions to estimates.

Proved Reserves By Product
	2011		2010		2009
Natural Gas	50	%	54	%	57	%
Natural Gas Liquids	39		41		40
Crude Oil	11		5		3
	100	%	100	%	100	%

(8) Represents the standardized measure of undiscounted future net cash flows 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 that we may enter into from time to time.

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Strategy and Competition

We plan to focus on optimizing the productivity of our wells and to seek opportunities for monetization of properties in 2012. The majority of our acreage position has rights to shallow reserves lying above the Barnett shale, specifically the Marble Falls formation. Recent drilling efforts have been largely successful in finding oil and high BTU gas. We anticipate the continued development of this liquids play which is expected to add value to our asset base. We expect total capital investment of $30 - 35 million to drill approximately 30 new wells and continue to acquire select acreage and achieve production of approximately 6 - 7 Bcfe, compared with 5 Bcfe in 2011. The majority of the drilling activity is expected to occur during the first half of 2012.

Due to increased activity in other shale plays throughout the country, the availability of service providers has decreased. However, we do not expect this to have a significant impact on our drilling plans or operations, since most oilfield services have been secured for the next 12 months.

From time to time, we may use financial derivative contracts to manage a portion of our exposure to changes in the price of natural gas and oil on our forecasted sales volume. At December 31, 2011, we had no long-term fixed price contracts relating to natural gas and had the following financial contracts in place with our Energy Trading affiliate related to our projected oil production:

	2012
Oil Volume (in MBbl)	72
Price (in Bbl)	$	101.73

POWER AND INDUSTRIAL PROJECTS

Description

Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers; provide coal transportation and marketing; and sell electricity from biomass-fired energy projects. This business segment provides services using project assets usually located on or near the customers' premises in the steel, automotive, pulp and paper, airport and other industries as follows:

Steel, Steel Industry Fuel, and Petroleum Coke:  We produce metallurgical coke from two coke batteries with a capacity of 1.4 million tons per year. We have an investment in a third coke battery with a capacity of 1.2 million tons per year. We are investors in entities which sell steel industry fuel at three coke battery sites. Steel industry fuels facilities recycle tar decanter sludge, a byproduct of the coking process. Tax credits were generated in 2009 and 2010 from steel industry fuel activities. The ability to generate tax credits from the steel industry fuel process expired at December 31, 2010. We also provide pulverized coal and petroleum coke to the steel, pulp and paper, and other industries.

Onsite Energy:  We provide power generation, steam production, chilled water production, wastewater treatment and compressed air supply to industrial customers. We provide utility-type services using project assets usually located on or near the customers' premises in the automotive, airport, chemical and other industries.

Wholesale Power and Renewables:  We own and operate four biomass-fired electric generating plants with a capacity of 183 MWs. We own a coal-fired power plant currently undergoing conversion to biomass with an expected in-service date in 2013. The electric output is sold under long term power purchase agreements. We also 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.

Reduced Emissions Fuel: We own and operate nine reduced emissions fuel facilities. Our facilities blend a proprietary additive with coal used in coal-fired power plants resulting in reduced emissions of Nitrogen Oxide (NO) and Mercury (Hg). Qualifying facilities are eligible to generate tax credits for ten years upon achieving certain criteria. The value of a tax credit is adjusted annually by an inflation factor published annually by the Internal Revenue Service. The value of the tax credit is reduced if the reference price of coal exceeds certain thresholds. The economic benefit of the reduced emissions fuel facilities is dependent upon the generation of production tax credits. We placed in service five facilities in 2009 and an additional four facilities in 2011. To optimize income and cash flow from the reduced emissions fuel operations, we sold membership interests in 2011 at two of the facilities that are located at Detroit Edison sites, which in substance, represented a sale of production tax credits. Although both sales included a modest up-front payment from the tax investor, the bulk of the proceeds will be received, and the income for all of the proceeds will be recognized, as production tax credits are generated. We continue to optimize these facilities by seeking tax investors for facilities operating at Detroit Edison and other utility sites. Additionally, we intend to relocate certain underutilized facilities, located at Detroit Edison sites, to alternative coal-fired power plants which may provide increased production and emission reduction opportunities in 2012 and future years.

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Coal Services:  The business provides coal transportation and related services including fuel to our customers with significant energy requirements which include electric utilities, merchant power producers, integrated steel mills and large industrial companies. We specialize in minimizing fuel costs and maximizing reliability of supply for those energy-intensive customers. We own and operate a coal transloading terminal which provides storage and blending services for our customers. We also engage in coal marketing which includes the marketing and trading of physical coal and coal financial instruments, and forward contracts for the purchase and sale of emission allowances.

Properties and Other

The following are significant properties operated by the Power and Industrial projects segment:

Facility	Location	Service Type
Steel, Steel Industry Fuel, and Petroleum Coke
Pulverized Coal Operations	MI & MD	Pulverized Coal
Coke Production	MI, PA & IN	Metallurgical Coke Supply/Steel Industry Fuels
Other Investment in Coke Production and Petroleum Coke	IN & MS	Metallurgical Coke Supply/Steel Industry Fuels, and Pulverized Petroleum Coke
On-Site Energy
Automotive	Various sites in	Electric Distribution, Chilled Water,
	MI, IN, OH & NY	Waste Water, Steam, Cooling Tower Water, Reverse Osmosis Water, Compressed Air, Mist and Dust Collectors,
		Steam and Chilled Water
Airports	MI & PA	Electricity, Hot and Chilled Water
Chemical Manufacturing	KY	Electricity, Steam and Natural Gas
Wholesale Power and Renewables
Pulp and Paper	AL	Electric Generation and Steam
Renewables	CA & WI	Electric Generation
Landfill Gas Recovery	Various U.S. sites	Electric Generation and Landfill Gas
Other Industries
Reduced Emissions Fuel	MI, OK, IL	Reduced Emission Fuel Supply
Coal Services	IL	Coal Terminal and Blending

	2011	2010	2009
	(In millions)
Production Tax Credits Generated (Allocated to DTE Energy)
Coke Battery (1)	$—	$—	$5
Steel Industry Fuels (2)	—	29	4
Power Generation	4	2	2
Landfill Gas Recovery	1	1	1
Reduced Emission Fuel	1	1	—

_______________________________________

(1) Tax laws enabling production tax credits related to two coke battery facilities expired on December 31, 2009.

(2) Tax laws enabling the steel industry fuel tax credits expired on December 31, 2010.

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Regulation

Certain electric generating facilities within Power and Industrial Projects have market-based rate authority from the FERC to sell power. The facilities are subject to FERC reporting requirements and market behavior rules. Certain Power and Industrial projects are also subject to the applicable laws, rules and regulations related to the Commodity Futures Trading Commission, U.S. Department of Homeland Security and Department of Energy.

Strategy and Competition

Power and Industrial Projects will continue leveraging its energy-related operating experience and project management capability to develop and grow our steel; renewable power; on-site energy; coal marketing, storage and blending; landfill gas recovery; and reduced emission fuel businesses. We also will continue to pursue opportunities to provide asset management and operations services to third parties. There are limited competitors for our existing disparate businesses who provide similar products and services.

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, new and pending legislation, the number of competitors and our ability to achieve sustainable margins. We plan to maximize the effectiveness of our related businesses as we expand. 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:

• Monetizing and relocating our reduced emission fuel facilities;

• Acquiring and developing landfill gas recovery facilities, renewable energy projects, and other energy projects which may qualify for tax credits; and

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

ENERGY TRADING

Description

Energy Trading focuses on physical and financial power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, and optimization of contracted natural gas pipeline transportation and storage, and power transmission and generating capacity positions. Energy Trading also provides natural gas, power and ancillary services to various utilities and producers which may include the management of associated storage and transportation contracts on the customers’ behalf under FERC Asset Management Arrangements. 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. These financial instruments are generally accounted for under the mark-to-market method, which results in the recognition in earnings 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 Energy Trading portfolio are economically hedged. Most financial instruments and physical power and gas contracts are deemed derivatives; whereas, gas inventory, power transmission, pipeline transportation and certain 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. The segment’s strategy is to economically manage the price risk of these underlying non-derivative contracts and assets with futures, forwards, swaps and options. This results in gains and losses that are recognized in different interim and annual accounting periods.

Regulation

Energy Trading has market-based rate authority from the FERC to sell power and blanket authority from the FERC to sell natural gas at market prices. Energy Trading is subject to FERC reporting requirements and market behavior rules. Energy Trading is also subject to the applicable laws, rules and regulations related to the Commodity Futures Trading Commission, U.S. Department of Homeland Security and Department of Energy.

Strategy and Competition

Our strategy for the Energy 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, financial

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institutions, traders, utilities and other energy providers. The Energy Trading business is dependent upon the availability of capital and an investment grade credit rating. The Company believes it has ample available capital capacity to support Energy Trading activities. We monitor our use of capital closely to ensure that our commitments do not exceed capacity. A material credit restriction would negatively impact our financial performance. Competitors with greater access to capital or at a lower cost may have a competitive advantage. We have risk management and credit processes to monitor and mitigate risk.

CORPORATE AND OTHER

Description

Corporate and Other includes various holding company activities and holds certain non-utility debt and energy-related investments.

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. Actual costs to comply could vary substantially. 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:

	Electric		Gas		Non-Utility		Total
	(In millions)
Air	$	1,921	$	—	$	—	$	1,921
Water	80		—		13		93
Contaminated and other sites	17		37		—		54
Estimated total future expenditures through 2021	$	2,018	$	37	$	13	$	2,068
Estimated 2012 expenditures	$	255	$	17	$	10	$	282
Estimated 2013 expenditures	$	311	$	5	$	2	$	318

Air - Detroit Edison is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze, mercury and other air pollution. These rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, mercury and other emissions. Further, additional rulemakings could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants over the next few years.

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 completed studies and expected future studies, Detroit Edison may be required to install additional control technologies to reduce the impacts of the water intakes. In addition, there are proposed rules that may require the installation of cooling towers at some facilities at a cost substantially greater than was initially estimated for other mitigative technologies. The EPA has also issued an information collection request to begin a review of steam electric effluent guidelines.

Contaminated and Other 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, have been designated as manufactured gas plant (MGP) sites. Gas Utility owns, or previously owned, fifteen such former MGP sites. Detroit Edison owns, or previously owned, three former MGP sites. The Company anticipates the cost amortization methodology approved by the MPSC for MichCon, which allows MichCon to amortize the MGP costs over a ten-year period beginning with the year subsequent to the year the MGP costs were incurred, and the cost deferral and rate recovery mechanism for Citizens Fuel Gas approved by the City of Adrian, will prevent MGP environmental costs from having a material adverse impact on the Company’s results of operations.

We are also in the process of cleaning up other sites where contamination is present as a result of historical and ongoing utility operations. These other sites include an engineered ash storage facility, electrical distribution substations, gas pipelines, and underground and aboveground storage tank locations. Cleanup activities associated with these sites will be conducted over the next several years. 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 these sites and affect the Company’s financial position and cash flows.

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The EPA has published proposed rules to regulate coal ash, which may result in a designation as a hazardous waste. The EPA could apply some, or all, of the disposal and reuse standards that have been applied to other existing hazardous wastes. Some of the regulatory actions currently being contemplated could have a significant impact on our operations and financial position and the rates we charge our customers. It is not possible to quantify the impact of those expected rulemakings at this time.

See Notes 11 and 19 of the Notes to Consolidated Financial Statements in Item 8 of this Report and Management’s Discussion and Analysis in Item 7 of this Report.

EMPLOYEES

We had approximately 9,800 employees as of December 31, 2011, of which approximately 5,000 were represented by unions. There are several bargaining units for the Company’s represented employees. The majority of represented employees are under contracts that expire in August 2012 and June and October 2013.

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 changed 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. Our regulators also may decide to disallow recovery of certain costs in customers' rates if they determine that those costs do not meet the standards for recovery under our governing laws and regulations. Our utilities typically self-implement base rate changes six months after rate case filings in accordance with Michigan law. However, if the final rates authorized by our regulators in the final rate order are lower than the amounts we collected during the self-implementation period, we must refund the difference with interest. Our regulators may also disagree with our rate calculations under the various tracking and decoupling mechanisms that are intended to mitigate the risk to our utilities of certain aspects of our business. If we cannot agree with our regulators on an appropriate reconciliation of those mechanisms, it may impact our ability to recover certain costs through our customer rates. Our regulators may also decide to eliminate more of these mechanisms in future rate cases, which may make it more difficult for us to recover our costs in the rates we charge customers. We cannot predict what rates an MPSC order will adopt in future rate cases.New legislation, regulations or interpretations could change how our business operates, impact our ability to recover costs through rates or require us to incur additional expenses.

Changes to 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. MPSC rate orders and 2008 energy legislation enacted by the State of Michigan are phasing out the pricing disparity over five years and have placed a 10 percent cap on the total potential Customer Choice related migration. However, even with the electric Customer Choice-related relief received in recent Detroit Edison rate orders and the legislated 10 percent cap on participation in the electric Customer Choice program, there continues to be legislative and financial risk associated with the electric Customer Choice program. Electric Customer Choice migration is sensitive to market price and full service electric price changes.

Regional and national economic conditions can have an unfavorable impact on us.  Our utility and non-utility businesses follow the economic cycles of the customers we serve and credit risk of counterparties we do business with. Our utilities and certain non-utility businesses provide services to the domestic automotive and steel industries which have undergone considerable financial distress, exacerbating the decline in regional economic conditions. Should national or regional economic conditions deteriorate, reduced volumes of electricity and gas, and demand for energy services we supply, collections of accounts receivable, reductions in federal and state energy assistance funding, and potentially higher levels of lost or stolen gas could result in decreased earnings and cash flow.

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Environmental laws and liability may be costly.  We are subject to and affected by 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 and can negatively affect the affordability of the rates we charge to our customers.

Uncertainty around future environmental regulations creates difficulty planning long-term capital projects in our generation fleet and gas distribution businesses.These laws and regulations require us to seek a variety of environmental licenses, permits, inspections and other regulatory approvals. We could be required to install expensive pollution control measures or limit or cease activities based on these regulations. Additionally, we may become a responsible party for environmental cleanup 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 and our unconventional gas production 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.

Future environmental regulation of natural gas extraction techniques including hydraulic fracturing being discussed both at the United States federal level and by some states may affect the profitability of natural gas extraction businesses which could affect demand for and profitability of our gas transportation businesses.

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, changes in federal nuclear regulation 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/or price of energy commodities and/or related services may impact our financial results.  We are dependent on coal for much of our electrical generating capacity. Our access to natural gas supplies is critical to ensure reliability of service for our utility gas customers. Our non-utility businesses, including our energy transportation business, are also dependent upon supplies and prices of energy commodities and services. Price fluctuations, fuel supply disruptions and changes in transportation costs could have a negative impact on the amounts we charge our utility customers for electricity and gas and on the profitability of our non-utility businesses. We have hedging strategies and regulatory recovery mechanisms in place to mitigate some of the negative fluctuations in commodity supply prices in our utility and non-utility businesses, but there can be no assurances that our financial performance will not be negatively impacted by price fluctuations. The price of energy also impacts the market for our non-utility businesses that compete with utilities and alternative electric suppliers or provide energy transportation services.

The supply and/or price of other industrial raw and finished inputs and/or related services may impact our financial results.  We are dependent on supplies of certain commodities, such as copper and limestone, among others, and industrial materials and services in order to maintain day-to-day operations and maintenance of our facilities. Price fluctuations or supply interruptions for these commodities and other items could have a negative impact on the amounts we charge our customers for our utility products and on the profitability of our non-utility businesses.

Adverse changes in our credit ratings may negatively affect us.  Regional and national economic conditions, 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 below investment grade could restrict or discontinue our ability to access capital markets and could result in an increase in our borrowing costs, a reduced level of capital expenditures and could impact future earnings and cash flows. In addition, a reduction in our credit rating may require us to post collateral related to various physical or financially settled contracts for the purchase of energy-related commodities, products and services, which could impact our liquidity.

Our ability to access capital markets is important.  Our ability to access capital markets is important to operate our businesses. In the past, turmoil in credit markets has constrained, and may again in the future constrain, our ability as well as the ability of our subsidiaries to issue new debt, including commercial paper, and refinance existing debt at reasonable interest rates. In addition, the level of borrowing by other energy companies and the market as a whole could limit our access to capital

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markets. Our long term revolving credit facilities do not expire until 2015, but we regularly access capital markets to refinance existing debt or fund new projects at our utilities, and we cannot predict the pricing or demand for those future transactions.

Poor investment performance of pension and other postretirement benefit plan holdings and other factors impacting benefit plan costs could unfavorably impact our liquidity and results of operations.  Our costs of providing non-contributory defined benefit pension plans and other postretirement benefit 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 debt and equity markets affects the value of assets that are held in trust to satisfy future obligations under our plans. We have significant benefit obligations and hold significant assets in trust to satisfy these obligations. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the pension and postretirement benefit plan assets will increase the funding requirements under our pension and postretirement benefit plans if the actual asset returns do not recover these declines in the foreseeable future. Additionally, our pension and postretirement benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, resulting in increasing benefit expense and funding requirements. Also, if future increases in pension and postretirement benefit costs as a result of reduced plan assets are not recoverable from Detroit Edison or MichCon customers, the results of operations and financial position of our company could be negatively affected. Without sustained growth in the plan 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.

Construction and capital improvements to our power facilities and distribution systems subject us to risk. We are managing ongoing and planning future significant construction and capital improvement projects at multiple power generation and distribution facilities and our gas distribution system. Many factors that could cause delays or increased prices for these complex projects are beyond our control, including the cost of materials and labor, subcontractor performance, timing and issuance of necessary permits, construction disputes and weather conditions. Failure to complete these projects on schedule and on budget for any reason could adversely affect our financial performance and operations at the affected facilities and businesses.

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 be required to post collateral to support trading operations, which could be substantial. If access to liquidity to support trading activities is curtailed, we could experience decreased earnings potential and cash flows. Energy trading activities take place in volatile markets and expose us to risks related to commodity price movements. We routinely have speculative trading positions in the market, within strict policy guidelines we set, resulting from the management of our business portfolio. To the extent speculative trading positions exist, fluctuating commodity prices can improve or diminish our financial results and financial position. We manage our exposure by establishing and enforcing strict risk limits and risk management procedures. During periods of extreme volatility, these risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities.

Our non-utility businesses 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 and a corresponding decline in our shareholder value.

Our estimates of gas reserves are subject to change.  While great care is exercised in utilizing historical information and assumptions to develop reasonable estimates of future production and cash flow, we cannot provide absolute 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.

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 and electricity from alternative sources. We generated production tax credits from coke production, landfill gas recovery, biomass fired electric generation, reduced emission fuel, renewable energy credits, steel industry fuel and gas production operations. All production tax credits

19

taken after 2008 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.

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 electric distribution system infrastructure and require us to perform emergency repairs and incur material unplanned expenses. The expenses of storm restoration efforts may not be fully recoverable through the regulatory process.

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.

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.

Renewable portfolio standards and energy efficiency programs may affect our business.  We are subject to existing Michigan and potential future federal legislation and regulation requiring us to secure sources of renewable energy. Under the current Michigan legislation we will be required in the future to provide a specified percentage of our power from Michigan renewable energy sources. We are developing a strategy for complying with the existing state legislation, but we do not know what requirements may be added by federal legislation. In addition, there could be additional state requirements increasing the percentage of power required to be provided by renewable energy sources. We are actively engaged in developing renewable energy projects and identifying third party projects in which we can invest. We cannot predict the financial impact or costs associated with these future projects.

We are also required by Michigan legislation to implement energy efficiency measures and provide energy efficiency customer awareness and education programs. These requirements necessitate expenditures and implementation of these programs creates the risk of reducing our revenues as customers decrease their energy usage. We do not know how these programs will impact our business and future operating results.

Threats of terrorism or cyber attacks could affect our business.  We may be threatened by problems such as computer viruses or terrorism that may disrupt our operations and could harm our operating results. Our industry requires the continued operation of sophisticated information technology systems and network infrastructure. Despite our implementation of security measures, all of our technology systems are vulnerable to disability or failures due to hacking, viruses, acts of war or terrorism and other causes. If our information technology systems were to fail and we were unable to recover in a timely way, we might be unable to fulfill critical business functions, which could have a material adverse effect on our business, operating results, and financial condition.

In addition, our generation plants, gas pipeline and storage facilities and electrical distribution facilities in particular may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products. We have increased security as a result of past events and we may be required by our regulators or by the future terrorist threat environment to make investments in security that we cannot currently predict.

Failure to maintain the security of personally identifiable information could adversely affect us.  In connection with our business we collect and retain personally identifiable information of our customers, shareholders and employees. Our customers, shareholders and employees expect that we will adequately protect their personal information, and the United States regulatory environment surrounding information security and privacy is increasingly demanding. A significant theft, loss or fraudulent use of customer, shareholder, employee or DTE Energy data by cybercrime or otherwise could adversely impact our reputation and could result in significant costs, fines and litigation.

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.

A work interruption may adversely affect us.  Unions represent approximately 5,000 of our employees. Our contract with one union representing about 500 of our electrical linemen is due to expire in August 2012. We cannot predict the outcome of those negotiations. 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.

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If our goodwill becomes impaired, we may be required to record a charge to earnings.  We annually review the carrying value of goodwill associated with acquisitions made by the Company for impairment. Factors that may be considered for purposes of this analysis include any change in circumstances indicating that the carrying value of our goodwill may not be recoverable such as a decline in stock price and market capitalization, future cash flows, and slower growth rates in our industry. We cannot predict the timing, strength or duration of any economic slowdown or subsequent recovery, worldwide or in the economy or markets in which we operate; however, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable, the Company may take a non-cash impairment charge, which could potentially materially impact our results of operations and financial position.

We may not be fully covered by insurance.  We have a comprehensive insurance program in place to provide coverage for various types of risks, including catastrophic damage as a result of acts of God, terrorism or a combination of other significant unforeseen events that could impact our operations. Economic losses might not be covered in full by insurance or our insurers may be unable to meet contractual obligations.

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 periods they are resolved.

In April 2006, the prior owners of the coke battery facility in Pennsylvania that the Company purchased in 2008 received a Notice of Violation/Finding of Violation (NOV/FOV) from the EPA alleging violations of the lowest achievable emission rate requirements associated with visible emissions from the combustion stack, door leaks and charging activities at the coke battery facility. The EPA has also alleged certain violations of the Clean Water Act, but has not issued a notice of violation in connection with these alleged violations. The Company is in the process of negotiating a Consent Order with the EPA to settle these historic air and water issues. The Company expects to enter into the Consent Order during the first quarter of 2012.

In February 2008, DTE Energy was named as one of approximately 24 defendant oil, power and coal companies in a lawsuit filed in a United States District Court. The plaintiffs, the Native Village of Kivalina and City of Kivalina, which are home to approximately 400 people in Alaska, claim that the defendants' business activities have contributed to global warming and, as a result, higher temperatures are damaging the local economy and leaving the island more vulnerable to storm activity in the fall and winter. As a result, the plaintiffs are seeking damages of up to $400 million for relocation costs associated with moving the village to a safer location, as well as unspecified attorney's fees and expenses. On October 15, 2009, the U.S. District Court granted defendants' motions dismissing all of plaintiffs' federal claims in the case on two independent grounds: (1) the court lacks subject matter jurisdiction to hear the claims because of the political question doctrine; and (2) plaintiffs lack standing to bring their claims. The court also dismissed plaintiffs' state law claims because the court lacked supplemental jurisdiction over them after it dismissed the federal claims; the dismissal of the state law claims was without prejudice. The plaintiffs have appealed to the U.S. Court of Appeals for the Ninth Circuit.

In July 2009, DTE Energy received a NOV/FOV from the EPA alleging, among other things, that five of Detroit Edison's power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and operating permit requirements under the Clean Air Act. In June 2010, the EPA issued a NOV/FOV making similar allegations related to a recent project and outage at Unit 2 of the Monroe Power Plant.

In August 2010, the United States Department of Justice, at the request of EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and Detroit Edison, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require Detroit Edison to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require Detroit Edison to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from Detroit Edison's fleet of coal-fired power plants until the new control equipment is operating. On August 23, 2011, the U.S. District Court judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy and Detroit Edison. On October 20, 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit.

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DTE Energy and Detroit Edison believe that the plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of discussions with the EPA regarding the two NOVs/FOVs, Detroit Edison could be required to install additional pollution control equipment at some or all of the power plants in question, implement early retirement of facilities where control equipment is not economical, engage in supplemental environmental programs, and/or pay fines. DTE Energy and Detroit Edison cannot predict the financial impact or outcome of these matters, or the timing of its resolution.

In October 2010, the Company received a Notice of Violation from the Michigan Department of Natural Resources (MDNRE) alleging that the Michigan coke battery facility violated the visible emission readings and quench water sampling requirements under applicable National Emissions Standards for Hazardous Air Pollutants regulations. This Notice of Violation resulted from the Company self reporting to the MDNRE and the EPA questionable activities by an employee of a contractor hired by the Company to perform visible emissions readings and quench water sampling. The information provided by thecontractor was used by the Company in filing certain reports with the MDNRE and the EPA. The Company has ceased using the contractor for these activities, has retained a new certified contractor to perform the required activities and implemented standard operating procedures designed to prevent a reoccurrence of such a situation. At this time, the Company cannot predict the outcome or financial impact of this issue.

In December 2010, the Company received a Notice of Violation from the Detroit Water and Sewerage Department (DWSD) alleging that effluent discharges from the Michigan coke battery facility violated the City of Detroit Ordinance, the General Pre-Treatment Standards and the terms of a Consent Judgment entered between the Company and the DWSD with respect to the Michigan coke battery facility in March 2009. The Company has settled similar alleged violations with respect to the Michigan coke battery facility with the DWSD in the past. The Company has installed a biological waste water treatment plant at the Michigan coke battery facility in accordance with the Consent Judgment that is designed to meet the effluent limitations and is in the process of optimizing plant performance to minimize any future excursions of the Ordinance and the General Pre-Treatment Standards. The DWSD has demanded payment of $176,000 in penalties in connection with the alleged violations. The Company is actively pursuing a settlement with DWSD, but we cannot predict the outcome or financial impact of this matter.

In August 2011, Allegheny County Health Department (ACHD) issued an Enforcement Order alleging 114 incidents of fugitive pushing emissions at the coke battery facility in Pennsylvania and assessing a civil penalty of $114,000. The Company has appealed the Enforcement Order. The Company is in the process of negotiating a Consent Order with ACHD to settle this Enforcement Order. The Company expects to enter into the consent order in the first half of 2012. The Company is completing a maintenance program designed to minimize future fugitive pushing emissions from the coke battery facility.

For additional discussion on legal matters, see Notes 11 and 19 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Item 4. Mine Safety Disclosures

Not applicable.

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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 per Share
Year	Quarter	High		Low
2011
	First	$	49.36	$	45.17	$	0.5600
	Second	$	52.78	$	48.06	$	0.5875
	Third	$	52.00	$	43.22	$	0.5875
	Fourth	$	55.28	$	47.03	$	0.5875
2010
	First	$	45.93	$	41.25	$	0.5300
	Second	$	49.05	$	43.00	$	0.5300
	Third	$	49.06	$	44.93	$	0.5600
	Fourth	$	47.66	$	44.27	$	0.5600

At December 31, 2011, there were 169,247,282 shares of our common stock outstanding. These shares were held by a total of 71,208 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 $389 million in 2011, $360 million in 2010, and $348 million in 2009. 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.

See Note 13 of the Notes to Consolidated Financial Statements in Item 8 of this Report for information on dividend restrictions.

All of our equity compensation plans that provide for the annual awarding of stock-based compensation have been approved by shareholders. See Note 21 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, 2011.

	Number of Securities to be Issued Upon Exercise of Outstanding Options	Weighted-Average Exercise Price of Outstanding Options	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans
Plans approved by shareholders	2,764,670	$41.25	1,945,035

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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, 2011:

	Number of Shares Purchased (1)	Average Price Paid per Share (1)		Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Average Price Paid per Share	Maximum Dollar Value that May Yet Be Purchased Under the Plans or Programs
01/01/2011 — 01/31/2011	13,893	$	45.30	—	—	—
02/01/2011 — 02/28/2011	631,248	46.81		—	—	—
03/01/2011 — 03/31/2011	25,302	42.28		—	—	—
04/01/2011 — 04/30/2011	3,839	49.13		—	—	—
05/01/2011 — 05/31/2011	139,340	51.28		—	—	—
06/01/2011 — 06/30/2011	181,721	48.85		—	—	—
07/01/2011 — 07/31/2011	6,990	46.20		—	—	—
08/01/2011 — 08/31/2011	60,000	49.95		—	—	—
09/01/2011 — 09/30/2011	71,965	44.90		—	—	—
10/01/2011 — 10/31/2011	2,241	49.02		—	—	—
11/01/2011 — 11/30/2011	155,000	51.10		—	—	—
12/01/2011 — 12/31/2011	102,411	54.11		—	—	—
Total	1,393,950			—

_______________________________________

(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. Also includes shares of common stock withheld to satisfy income tax obligations upon the vesting of restricted stock.

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COMPARISON OF CUMULATIVE FIVE YEAR TOTAL RETURN

Total Return To Shareholders

(Includes reinvestment of dividends)

	Annual Return Percentage Year Ended December 31
Company/Index	2007		2008		2009	2010	2011
DTE Energy Company	(5.03	)	(14.37	)	30.08	9.06	25.76
S&P 500 Index	5.49		(37.00	)	26.46	15.06	2.11
S&P 500 Multi-Utilities Index	10.86		(24.34	)	20.93	11.08	18.41

	Indexed Returns Year Ended December 31
	Base Period
Company/Index	2006	2007	2008	2009	2010	2011
DTE Energy Company	100	94.97	81.32	105.78	115.36	145.08
S&P 500 Index	100	105.49	66.46	84.05	96.71	98.76
S&P 500 Multi-Utilities Index	100	110.86	83.88	101.43	112.67	133.40

Comparison of Cumulative Five Year Total Return

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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.

	2011		2010		2009		2008		2007
	(In millions, except per share amounts)
Operating Revenues	$	8,897	$	8,557	$	8,014	$	9,329	$	8,475
Net Income Attributable to DTE Energy Company
Income from continuing operations (1)	$	711	$	630	$	532	$	526	$	787
Discontinued operations	—		—		—		20		184
Net Income Attributable to DTE Energy Company	$	711	$	630	$	532	$	546	$	971
Diluted Earnings Per Common Share
Income from continuing operations	$	4.18	$	3.74	$	3.24	$	3.22	$	4.61
Discontinued operations	—		—		—		0.12		1.08
Diluted Earnings Per Common Share	$	4.18	$	3.74	$	3.24	$	3.34	$	5.69
Financial Information
Dividends declared per share of common stock	$	2.32	$	2.18	$	2.12	$	2.12	$	2.12
Total assets	$	26,009	$	24,896	$	24,195	$	24,590	$	23,742
Long-term debt, including capital leases	$	7,187	$	7,089	$	7,370	$	7,741	$	6,971
Shareholders’ equity	$	7,009	$	6,722	$	6,278	$	5,995	$	5,853

_______________________________________

(1) 2011 results include an $87 million income tax benefit related to the enactment of the MCIT. 2008 results include an $80 million after-tax gain on the sale of a portion of the Barnett shale properties. 2007 results include a $580 million after-tax gain on the Antrim sale transaction and $210 million after-tax loss on hedge contracts associated with the Antrim sale.

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

EXECUTIVE OVERVIEW

DTE Energy is a diversified energy company with 2011 operating revenues of approximately $8.9 billion and approximately $26 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:

	2011		2010		2009
	(In millions, except per share amounts)
Net income attributable to DTE Energy Company	$	711	$	630	$	532
Diluted earnings per common share	$	4.18	$	3.74	$	3.24

The increase in 2011 Net income attributable to DTE Energy as compared to 2010 was driven by higher earnings in Energy Trading, partially offset by lower earnings in the Electric and Gas Utilities and in the Power and Industrial Projects segment. The 2011 increase is also due to an income tax benefit of $87 million in the Corporate and Other segment related to the enactment of the MCIT in the second quarter of 2011. The increase in 2010 Net income attributable to DTE Energy as compared to 2009 was primarily due to improved results in the Electric and Gas Utilities and in the Power and Industrial Projects segment, partially offset by lower earnings in Energy Trading.

Please see detailed explanations of segment performance in the following Results of Operations section.

DTE Energy's strategy is to achieve long-term earnings growth, a strong balance sheet and an attractive dividend yield.

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Our utilities' growth will be driven by mandated environmental and renewable investments in addition to base infrastructure investments. We are focused on executing plans to achieve operational excellence and customer satisfaction with a focus on customer affordability. We operate in a constructive regulatory environment and have solid relationships with our regulators.

We have significant investments in our non-utility businesses. We employ disciplined investment criteria when assessing meaningful, low-risk growth opportunities that leverage our assets, skills and expertise and provide diversity in earnings and geography. Specifically, we invest in targeted energy markets with attractive competitive dynamics where meaningful scale is in alignment with our risk profile. We expect growth opportunities in the Gas Storage and Pipelines and Power and Industrial Projects segments.

A key priority for DTE Energy is to maintain a strong balance sheet which facilitates access to capital markets and reasonably priced short-term and long-term financing. Near-term growth will be funded through internally generated cash flows, expected monetization of our Unconventional Gas Production business, issuance of debt and issuance of equity through our dividend reinvestment plan and pension and other employee benefit plans. We have adopted an enterprise risk management program that, among other things, is designed to monitor and manage our exposure to earnings and cash flow volatility related to commodity price changes, interest rates and counterparty credit risk.

CAPITAL INVESTMENTS

Our utility businesses require significant base capital investments each year in order to maintain and improve the reliability of their asset bases, including power generation plants, distribution systems, storage fields and other facilities and fleets. Detroit Edison's capital investments over the 2012-2016 period are estimated at $4 billion for base capital investments, $1.3 billion to $1.8 billion for mandated environmental requirements and $900 million for renewable and energy efficiency expenditures. MichCon's capital investments over the 2012-2016 period are estimated at $675 million for base capital investments, $250 million for gas main renewal and $115 million for meter move out programs. Detroit Edison and MichCon both plan to seek regulatory approval in general rate case filings to include these capital expenditures within our regulatory rate base consistent with prior general rate case filing treatment. Detroit Edison is implementing a 20-year renewable energy plan to address the provisions of Michigan Public Act 295 of 2008, with the goals of delivering cleaner renewable electric generation to its customers, further diversifying Detroit Edison's and the State of Michigan's sources of electric supply and addressing the state and national goals of increasing energy independence. Detroit Edison routinely files renewable energy plans, requests for approval of renewable contracts and for recovery of renewable capital expenditures with the MPSC as the implementation of the 20-year renewable energy plan progresses.

In April 2010, the Company signed an agreement with the U.S. Department of Energy for a grant of approximately $84 million in matching funds on total anticipated spending of approximately $168 million related to the accelerated deployment of smart grid technology in Michigan through 2012. The smart grid technology includes the establishment of an advanced metering infrastructure and other technologies that address improved electric distribution service. See Note 2 of the Notes to Consolidated Financial Statements.

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. Actual costs to comply could vary substantially. We expect to continue recovering environmental costs related to utility operations through rates charged to our customers.

Detroit Edison is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. These 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 $1.7 billion through 2011. The Company estimates Detroit Edison will make capital expenditures of approximately $255 million in 2012 and up to approximately $1.9 billion of additional capital expenditures through 2021 based on current regulations.

Climate regulation and/or legislation has been proposed and discussed within the U.S. Congress and the EPA, however the current 112^th Congress is not expected to pass any major energy or climate bills. Meanwhile, the EPA is implementing regulatory actions under the Clean Air Act to address emissions of greenhouse gases. EPA regulation of greenhouse gases (GHGs) began in 2011 and requires the best available control technology (BACT) for new major sources or modifications to existing major sources that cause significant increases in GHG emissions. The impact of this rule is uncertain until BACT is

27

better defined by the permitting agencies. Pending or future legislation or other regulatory actions could have a material impact on our operations and financial position and the rates we charge our customers. Impacts include expenditures for environmental equipment beyond what is currently planned, financing costs related to additional capital expenditures, the purchase of emission offsets from market sources and the retirement of facilities where control equipment is not economical. We would seek to recover these incremental costs through increased rates charged to our utility customers. Increased costs for energy produced from traditional sources could also increase the economic viability of energy produced from renewable and/or nuclear sources and energy efficiency initiatives and the development of market-based trading of carbon offsets providing business opportunities for our utility and non-utility segments. It is not possible to quantify these impacts on DTE Energy or its customers at this time.

See Note 19 of the Notes to the Consolidated Financial Statements and Items 1. and 2. Business and Properties for further discussion of Environmental Matters.

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:

• improving Electric and Gas Utility customer satisfaction;

• continuing to improve employee engagement;

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

• managing the growth of our utility asset base;

• optimizing our cost structure across all business segments;

• managing cash, capital and liquidity to maintain or improve our financial strength; and

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

We will continue to pursue opportunities to grow our businesses in a disciplined manner if we can secure opportunities that meet our strategic, financial and risk criteria.

RESULTS OF OPERATIONS

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

	2011			2010			2009
	(In millions)
Net Income Attributable to DTE Energy by Segment:
Electric Utility	$	434		$	441		$	376
Gas Utility	110			127			80
Gas Storage and Pipelines	57			51			49
Unconventional Gas Production	(6		)	(11		)	(9		)
Power and Industrial Projects	38			85			31
Energy Trading	52			6			75
Corporate and Other	26			(69		)	(70		)
Net Income Attributable to DTE Energy Company	$	711		$	630		$	532

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ELECTRIC UTILITY

Our Electric Utility segment consists principally of Detroit Edison.

Electric Utility results are discussed below:

	2011			2010			2009
	(In millions)
Operating Revenues	$	5,154		$	4,993		$	4,714
Fuel and Purchased Power	1,716			1,580			1,491
Gross Margin	3,438			3,413			3,223
Operation and Maintenance	1,370			1,305			1,277
Depreciation and Amortization	818			849			844
Taxes Other Than Income	240			237			205
Asset (Gains) Losses, Reserves and Impairments, Net	13			(6		)	(2		)
Operating Income	997			1,028			899
Other (Income) and Deductions	298			317			295
Income Tax Expense	265			270			228
Net Income Attributable to DTE Energy Company	$	434		$	441		$	376
Operating Income as a Percent of Operating Revenues	19		%	21		%	19		%

Gross margin increased $25 million in 2011 and increased $190 million in 2010. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statement of Operations. The following table details changes in various gross margin components relative to the comparable prior period:

	2011			2010
	(In millions)
Rate case and Choice Incentive mechanism, net of Revenue Decoupling mechanism and sales volume	$	29		$	84
Restoration tracker	27			35
Securitization bond and tax surcharge	(39		)	40
Low Income Energy Efficiency Fund revenue deferral	(23		)	—
Energy optimization performance incentive	17			—
Regulatory mechanisms and other	14			31
Increase in gross margin	$	25		$	190

	2011	2010	2009
	(In thousands of MWh)
Electric Sales
Residential	15,907	15,726	14,625
Commercial	16,779	16,570	18,200
Industrial	9,739	10,195	9,922
Other	3,136	3,210	3,229
	45,561	45,701	45,976
Interconnection sales (1)	3,512	4,876	5,156
Total Electric Sales	49,073	50,577	51,132
Electric Deliveries
Retail and Wholesale	45,561	45,701	45,976
Electric Customer Choice, including self generators	5,445	5,005	1,477
Total Electric Sales and Deliveries	51,006	50,706	47,453

______________________________

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

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	2011					2010					2009
	(In thousands of MWh)
Power Generated and Purchased
Power Plant Generation
Fossil	35,502			68	%	39,433			73	%	40,595			74	%
Nuclear	8,910			17		7,738			14		7,406			14
	44,412			85		47,171			87		48,001			88
Purchased Power	8,028			15		6,638			13		6,495			12
System Output	52,440			100	%	53,809			100	%	54,496			100	%
Less Line Loss and Internal Use	(3,367		)			(3,232		)			(3,364		)
Net System Output	49,073					50,577					51,132
Average Unit Cost ($/MWh)
Generation (1)	$	22.67				$	18.94				$	18.20
Purchased Power	$	42.78				$	42.38				$	37.74
Overall Average Unit Cost	$	25.75				$	21.83				$	20.53

_______________________________________

(1) Represents fuel costs associated with power plants.

Operation and maintenance expense increased $65 million in 2011 and increased $28 million in 2010. The increase in 2011 is primarily due to higher restoration and line clearance expenses of $41 million, higher generation maintenance and outage expenses of $25 million, higher energy optimization and renewable energy expenses of $19 million, higher employee benefit expense of $9 million, partially offset by reduced contributions of $23 million to the Low Income Energy Efficiency Fund due to a court order, and reduced uncollectible expenses of $7 million. The increase in 2010 is primarily due to higher restoration and line clearance expenses of $40 million, higher energy optimization and renewable energy expenses of $18 million, higher legal expenses of $15 million, partially offset by reduced uncollectible expenses of $20 million, lower generation expenses of $18 million and lower employee benefit-related expenses of $6 million.

Depreciation and amortization expense decreased $31 million in 2011 due primarily to reduced amortization of regulatory assets, partially offset by expense related to higher depreciable base. Depreciation and amortization expense was $5 million higher in 2010 due primarily to expense related to higher depreciable base and increased amortization of regulatory assets.

Taxes other than income were higher by $32 million in 2010 due primarily to a $30 million reduction in property tax expense in 2009 due to refunds received in settlement of appeals of assessments for prior years.

Asset (gains) and losses, reserves and impairments, net increased $19 million in 2011 principally attributable to an accrual of $19 million resulting from management's revisions of the timing and estimate of cash flows for the decommissioning of Fermi 1, partially offset by a revision of $6 million in the timing and estimate of cash flows for the Fermi 1 asbestos removal obligation and other items. See Note 8 of the Notes to the Consolidated Financial Statements.

Outlook  - The base rate and rehearing orders approved by the MPSC in fourth quarter 2011 provide for an annual revenue increase of $188 million and an authorized return on equity of 10.5%. The base rate order terminated Detroit Edison's Restoration, Line Clearance and Uncollectible Expense tracking mechanisms. Termination of these trackers may result in increased volatility in Detroit Edison's results due to weather, the number of storms and uncollectible accounts receivable. The Choice Incentive Mechanism was also terminated in the base rate order. Base rates included electric Customer Choice sales at the capped 10 percent level. See Note 11 of Notes to the Consolidated Financial Statements for further discussion of the rate orders received by Detroit Edison.

We continue to move forward in our efforts to achieve operational excellence, sustained strong cash flows and earn our authorized return on equity. We expect that our planned significant environmental and renewable expenditures will result in earnings growth. Looking forward, additional factors may impact earnings such as the outcome of regulatory proceedings, investment returns and changes in discount rate assumptions in benefit plans and health care costs, and uncertainty of legislative or regulatory actions regarding climate change. We expect to continue our efforts to improve productivity and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.

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GAS UTILITY

Our Gas Utility segment consists of MichCon and Citizens.

Gas Utility results are discussed below:

	2011			2010			2009
	(In millions)
Operating Revenues	$	1,505		$	1,648		$	1,788
Cost of Gas	744			870			1,057
Gross Margin	761			778			731
Operation and Maintenance	394			378			415
Depreciation and Amortization	89			92			107
Taxes Other Than Income	54			55			49
Asset (Gains) and Losses, Net	—			—			(18		)
Operating Income	224			253			178
Other (Income) and Deductions	54			59			59
Income Tax Expense	60			67			39
Net Income Attributable to DTE Energy Company	$	110		$	127		$	80
Operating Income as a Percent of Operating Revenues	15		%	15		%	10		%

Gross margin decreased $17 million in 2011 and increased $47 million in 2010. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statement of Operations. The following table details changes in various gross margin components relative to the comparable prior period:

	2011			2010
	(In millions)
Uncollectible tracking mechanism	$	(27	)	$	(43	)
2010 self-implementation and rate order	(4		)	125
Revenue decoupling mechanism	5			—
Energy optimization performance incentive	7			—
Midstream storage and transportation revenues	(12		)	(20		)
Subsidiaries transferred to Gas Storage and Pipelines segment	(17		)	—
Weather	25			(23		)
Lost and stolen gas	—			13
Other	6			(5		)
Increase (decrease) in gross margin	$	(17	)	$	47

	2011	2010	2009
Gas Markets (in Bcf)
Gas sales	123	118	137
End user transportation	141	140	124
	264	258	261
Intermediate transportation	273	391	463
	537	649	724

Operation and maintenance expense increased $16 million in 2011 and decreased $37 million in 2010. The increase in 2011 is primarily due to the 2010 deferral of $32 million of previously expensed CTA restructuring expenses and increased energy optimization expenses of $10 million, partially offset by reduced uncollectible expenses of $13 million, reduced expenses for subsidiaries transferred to Gas Storage and Pipelines segment of $6 million, lower customer service expenses of $5 million, and lower gas operations expenses of $4 million. The decrease in 2010 is primarily due to reduced uncollectible

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expenses of $35 million and the deferral of $32 million of previously expensed CTA restructuring expenses, partially offset by higher maintenance expenses of $11 million, increased energy optimization expenses of $9 million, higher employee benefit-related expenses of $3 million and contributions of $3 million to the Low Income Energy Efficiency Fund.

Outlook — We continue to move forward in our efforts to achieve operational excellence and sustained strong cash flows and earn our authorized return on equity. We plan to file a base rate case in the second quarter 2012 and expect to self-implement new rates in the fourth quarter 2012 at the beginning of the heating season. Unfavorable economic trends have resulted in a decrease in the number of customers in our service territory, increased customer conservation and continued high levels of theft and uncollectible accounts receivable. The MPSC has provided for an uncollectible expense tracking mechanism which assists in mitigating the impacts of economic conditions in our service territory and a revenue decoupling mechanism that addresses changes in average customer usage due to general economic conditions and conservation. These and other tracking mechanisms and surcharges are expected to result in lower earnings volatility in the future. Looking forward, additional factors may impact earnings such as infrastructure improvement capital programs, the outcome of future regulatory proceedings, investment returns and changes in discount rate assumptions in benefit plans and health care costs. We expect to continue our efforts to improve productivity, minimize lost and stolen gas, and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.

GAS STORAGE AND PIPELINES

Our Gas Storage and Pipelines segment consists of our non-utility gas pipelines and storage businesses.

Gas Storage and Pipelines results are discussed below:

	2011			2010			2009
	(In millions)
Operating Revenues	$	91		$	83		$	82
Operation and Maintenance	16			14			15
Depreciation and Amortization	6			5			5
Taxes Other Than Income	3			2			2
Operating Income	66			62			60
Other (Income) and Deductions	(28		)	(25		)	(23		)
Income Tax Expense	35			32			33
Net Income	59			55			50
Noncontrolling interest	2			4			1
Net Income Attributable to DTE Energy	$	57		$	51		$	49

Net income attributable to DTE Energy increased $6 million and $2 million in 2011 and 2010, respectively. The 2011 increase was primarily driven by earnings from subsidiaries that were transferred from Gas Utility, increased earnings from our pipeline equity investments, and a settlement for customer gas treating services performed in prior years. The 2010 increase was driven by higher gas storage revenues and lower project development costs.

Outlook — Our Gas Storage and Pipelines business expects to continue its steady growth plan and is evaluating new pipeline and storage investment opportunities. Millennium Pipeline has secured customers for its Phase 1 & 2 expansions which are scheduled to be in-service in the fourth quarter of 2012 and the fourth quarter of 2013, respectively. Millennium's total capacity with the Phase 1 & 2 expansion will increase from 525,000 dth/d to over 800,000 dth/d. In addition, we have executed an agreement with Southwestern Energy Services Company to support our Bluestone lateral and gathering system. Bluestone is a 40 mile pipeline in Susquehanna County, Pennsylvania and Broome County, New York designed to initially flow 250,000 dth/d to both Millennium Pipeline and Tennessee Pipeline and is scheduled to be in service in 2012. We plan to spend up to $280 million over the next five years on the Bluestone lateral and gathering system.

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UNCONVENTIONAL GAS PRODUCTION

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

Unconventional Gas Production results are discussed below:

	2011			2010			2009
	(In millions)
Operating Revenues	$	39		$	32		$	31
Operation and Maintenance	21			16			15
Depreciation, Depletion and Amortization	18			15			16
Taxes Other Than Income	3			2			1
Asset (Gains) and Losses, Net	—			10			6
Operating Income (Loss)	(3		)	(11		)	(7		)
Other (Income) and Deductions	6			6			6
Income Tax Benefit	(3		)	(6		)	(4		)
Net Income (Loss) Attributable to DTE Energy Company	$	(6	)	$	(11	)	$	(9	)

Unconventional Gas Production results were impacted by the impairment of expired or expiring leasehold positions in 2010 and 2009. Revenues and expenses increased in 2011 and 2010 as a result of new wells on line, increased liquids prices and higher crude oil production.

Outlook — We plan to focus on optimizing the productivity of our wells and to seek opportunities for monetization of properties in 2012. The majority of our acreage position has rights to shallow reserves lying above the Barnett shale, specifically the Marble Falls formation. Recent drilling efforts have been largely successful in finding oil and high BTU gas. We anticipate the continued development of this liquids play which is expected to add value to our asset base. We expect total capital investment of $30 - 35 million to drill approximately 30 new wells and continue to acquire select acreage and achieve production of approximately 6 - 7 Bcfe, compared with 5 Bcfe in 2011. The majority of the drilling activity is expected to occur in the first half of 2012.

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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; provide coal transportation, marketing and trading services; and sell electricity from biomass-fired energy projects.

Power and Industrial Projects results are discussed below:

	2011			2010			2009
	(In millions)
Operating Revenues	$	1,129		$	1,144		$	661
Operation and Maintenance	1,025			978			593
Depreciation and Amortization	60			60			40
Taxes other than Income	10			14			9
Asset (Gains) and Losses, Reserves and Impairments, Net	(12		)	(14		)	(6		)
Operating Income	46			106			25
Other (Income) and Deductions	(10		)	13			(1		)
Income Taxes
Expense	17			36			5
Production Tax Credits	(6		)	(33		)	(12		)
	11			3			(7		)
Net Income	45			90			33
Noncontrolling interest	7			5			2
Net Income Attributable to DTE Energy Company	$	38		$	85		$	31

VIEs — As discussed in Note 1 of Notes to the Consolidated Financial Statements, effective January 1, 2010, we adopted the provisions of ASU 2009-17, Amendments to FASB Interpretation 46(R). ASU 2009-17 changed the methodology for determining the primary beneficiary of a VIE from a quantitative risk and rewards-based model to a qualitative determination. The Company re-evaluated prior VIE and primary beneficiary determinations and, as a result, began consolidating five entities. Since these entities were previously accounted for under the equity method, the VIE consolidation had no impact on Net Income Attributable to DTE Energy. As a result of the consolidation of these VIEs, Operating Revenues and Operation and Maintenance expense increased $174 million and $122 million, respectively, in 2010.

Operating revenues decreased $15 million in 2011 and increased $309 million in 2010, net of VIE adjustments. The 2011 decrease is primarily due to $166 million of lower coal transportation and marketing services related to an expired rail transportation contract at significantly below market rates, $21 million of lower volumes associated with the coal blending business and a $20 million decrease from the sale of our rail services business in 2010, partially offset by a $92 million increase related to reduced emissions fuels projects, $74 million increase in coke demand and pricing, and a $26 million increase in new on-site energy services projects. The 2010 increase is attributed primarily to $172 million of higher coke sales and a $156 million increase in on-site services, partially offset by a $18 million decrease in coal trading and transportation services.

Operation and maintenance expense increased $47 million in 2011 and increased $263 million in 2010, net of VIE adjustments. The 2011 increase is due primarily to a $103 million increase in coal costs, a $93 million increase related to reduced emission fuels projects, and a $25 million increase in new on-site energy services projects, partially offset by $127 million lower coal transportation and marketing services related to the expired rail transportation contract, $19 million decrease from the sale of our rail services business in 2010, $17 million lower volumes primarily associated with the coal blending business and $11 million of lower coke battery operating costs. The 2010 increase is due primarily to $118 million of higher coke production and a $154 million increase in on-site services, partially offset by $10 million of lower coal trading and transportation services.

Asset (Gains) Losses decreased by $2 million in 2011 and increased by $8 million in 2010. The 2011 decrease was due to an asset impairment related to our landfill gas recovery business of $11 million, partially offset by installment gains of $9 million from the sale of a coke battery. The 2010 increase is due primarily to the sale of DTE Rail Services and an increase in installment gains from the sale of a coke battery.

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Other (income) and deductions were higher by $23 million in 2011 and lower by $14 million in 2010. The increase in 2011 was due primarily to the production of refined coal from our reduced emissions fuels projects giving rise to tax credits which the Company has sold to third parties and gains on the extinguishment of debt related to our landfill gas recovery business. The decrease in 2010 was due primarily to lower equity earnings in various projects and higher intercompany interest associated with project investment.

Production tax credits decreased by $27 million in 2011 due primarily to the expiration of steel industry fuels credits as of December 31, 2010, partially offset by tax credits earned from reduced emission fuel projects. The increase of $21 million in 2010 was due primarily to a full year of steel industry fuels tax credits.

Outlook — The Company has constructed and placed in service nine reduced emission fuel facilities. The Company has sold a membership interest in two of these facilities that are located at the Detroit Edison sites. Additionally, the Company has constructed two facilities located at third party owned coal-fired power plants. We continue to optimize these facilities by seeking tax investors for facilities operating at Detroit Edison and other utility sites. Additionally, we intend to relocate four underutilized facilities, located at Detroit Edison sites, to alternative coal-fired power plants which may provide increased production and emission reduction opportunities in 2012 and future years. The executed and planned sales of membership interests in the reduced emission fuel facilities represent, in substance, the sale of production tax credits. The proceeds from these sales are expected to be received by the Company on an installment basis, and the Company will recognize the related income as production tax credits are generated by the respective facilities.

We expect sustained production levels of metallurgical coke and pulverized coal supplied to steel industry customers for 2012. Substantially all of the metallurgical coke is under long-term contracts. Our on-site energy services will continue to be delivered in accordance with the terms of long-term contracts. Environmental and economic trends are creating growth opportunities for renewable power. The increasing number of states with renewable portfolio standards and energy efficiency mandates provides investment opportunity in waste-wood power generation. In addition to the four facilities that will be in operation in 2012, we are converting an additional facility to be placed in service in 2013. We will continue to look for additional investment opportunities and other energy projects at favorable prices.

Power and Industrial Projects will continue to leverage its extensive energy-related operating experience and project management capability to develop additional energy projects to serve energy intensive industrial customers.

ENERGY TRADING

Energy Trading focuses on physical and financial power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, and optimization of contracted natural gas pipeline transportation and storage, and power transmission and generating capacity positions. Energy Trading also provides natural gas, power and related services, and the supply or purchase of renewable energy credits to various utilities which may include the management of associated storage and transportation contracts on the customers’ behalf.

Energy Trading results are discussed below:

	2011		2010		2009
	(In millions)
Operating Revenues	$	1,276	$	875	$	804
Fuel, Purchased Power and Gas	1,112		786		603
Gross Margin	164		89		201
Operation and Maintenance	63		59		71
Depreciation and Amortization	3		5		5
Taxes Other Than Income	3		2		3
Operating Income	95		23		122
Other (Income) and Deductions	9		12		10
Income Tax Expense	34		5		37
Net Income Attributable to DTE Energy Company	$	52	$	6	$	75

Gross margin increased $75 million in 2011 and decreased $112 million in 2010. The overall increase in gross margin in 2011 was the result of improved economic performance, coupled with the absence of prior year timing losses. We experienced timing-related earnings volatility based on market movement related to derivative contracts.

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The increase in 2011 represents a $25 million increase in realized margins and $50 million increase in unrealized margins. The $25 million increase in realized margins is due to $73 million of favorable results, primarily in our power and gas trading and power full requirements strategies, offset by $48 million of unfavorable results, primarily in our power origination, gas structured and gas full requirements strategies. The $50 million increase in unrealized margins is due to $63 million of favorable results, primarily in our power full requirements, gas structured and gas trading strategies, offset by $13 million of unfavorable results, primarily in our power transmission strategy.

The decrease in 2010 represents a $78 million decrease in realized margins and $34 million decrease in unrealized margins. The $78 million decrease in realized margins is due to $108 million of unfavorable results, primarily in our power and gas trading and gas full requirements strategies, offset by $30 million of favorable results, primarily in our power full requirements and power origination strategies. The $34 million decrease in unrealized margins is due to $56 million of unfavorable results, primarily in our power trading strategy and the absence of prior year timing-related gains related to our gas transportation strategy. These decreases were offset by $22 million of favorable results, primarily due to timing-related gains in our gas full requirements strategy.

Operation and maintenance expense increased $4 million in 2011 and decreased $12 million in 2010. The 2011 increase was primarily due to higher incentive costs and the 2010 decrease was primarily due to lower incentive costs, both of which were impacted by economic performance.

Income tax provision increased $29 million in 2011, due to higher pretax income. Income taxes decreased $32 million in 2010, due to lower pretax income, partially offset by $10 million of favorable tax-related adjustments in 2009 resulting from the settlement of federal income tax audits.

Outlook — In the near term, we expect market conditions to remain challenging and the profitability of this segment may be impacted by the volatility or lack thereof in commodity prices in the markets we participate in and the uncertainty of impacts associated with financial reform, regulatory changes and changes in operating rules of regional transmission organizations.

The Energy Trading portfolio includes financial instruments, physical commodity contracts and gas inventory, as well as contracted natural gas pipeline transportation and storage, and power transmission and generation capacity positions. Energy Trading also provides natural gas, power and related services, and the supply or purchase of renewable energy credits to various utilities and producers which may include the management of associated storage and transportation contracts on the customers' behalf under FERC Asset Management Arrangements. Significant portions of the Energy Trading portfolio are economically hedged. Most financial instruments and physical power and gas contracts are deemed derivatives, whereas natural gas inventory, power transmission, pipeline transportation and certain storage assets are not derivatives. As a result, we will experience earnings volatility as derivatives are marked-to-market without revaluing the underlying non-derivative contracts and assets. Our strategy is to economically manage the price risk of these underlying non-derivative contracts and assets with futures, forwards, swaps and options. This results in gains and losses that are recognized in different interim and annual accounting periods.

See also the “Fair Value” section that follows.

CORPORATE AND OTHER

Corporate and Other includes various holding company activities and holds certain non-utility debt and energy-related investments.

The 2011 net income of $26 million was an improvement of $95 million from the 2010 net loss of $69 million. The improvement resulted primarily from an income tax benefit of $87 million related to the enactment of the MCIT in the second quarter of 2011 and lower interest costs. See Note 12 of the Notes to Consolidated Financial Statements in Item 8 of this report.

The 2010 net loss of $69 million was an improvement of $1 million from the 2009 net loss of $70 million. The net $1 million improvement was a result of the 2009 donation to the DTE Energy Foundation of $10 million and lower impairments of investments of $3 million, partially offset by higher state and local taxes of $3 million, higher tax related interest of $5 million and increased financing costs of $5 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. We believe that we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements. In 2012, we expect that cash from operations will be $1.9 billion due to

36

lower working capital requirements. We anticipate base level utility capital investments, environmental, renewable and energy optimization expenditures and expenditures for non-utility businesses in 2012 of approximately $1.9 billion. We plan to seek regulatory approval to include utility capital expenditures in our regulatory rate base consistent with prior treatment. Capital spending for growth of existing or new non-utility businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria.

	2011			2010			2009
	(In millions)
Cash and Cash Equivalents
Cash Flow From (Used For)
Operating activities:
Net income	$	720		$	639		$	535
Depreciation, depletion and amortization	995			1,027			1,020
Deferred income taxes	220			457			205
Asset (gains) and losses, reserves and impairments, net	(21		)	(5		)	(10		)
Working capital and other	94			(293		)	69
	2,008			1,825			1,819
Investing activities:
Plant and equipment expenditures — utility	(1,382		)	(1,011		)	(960		)
Plant and equipment expenditures — non-utility	(102		)	(88		)	(75		)
Proceeds from sale of assets	18			56			83
Restricted cash and other investments	(94		)	(183		)	(112		)
	(1,560		)	(1,226		)	(1,064		)
Financing activities:
Issuance of long-term debt	1,179			614			427
Redemption of long-term debt	(1,455		)	(663		)	(486		)
Short-term borrowings, net	269			(177		)	(417		)
Issuance of common stock	—			36			35
Repurchase of common stock	(18		)	—			—
Dividends on common stock and other	(420		)	(396		)	(348		)
	(445		)	(586		)	(789		)
Net Increase (Decrease) in Cash and Cash Equivalents	$	3		$	13		$	(34	)

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.

Cash from operations totaling $2 billion in 2011 was $183 million higher than the comparable 2010 period. The operating cash flow comparison primarily reflects cash generated from working capital items, partially offset by lower net income after adjusting for non-cash and non-operating items (depreciation, depletion and amortization, deferred income taxes and gains on sales of assets).

Cash from operations totaling $1.8 billion in 2010, was consistent with the comparable 2009 period. The operating cash flow comparison primarily reflects higher net income after adjusting for non-cash and non-operating items, offset by cash used for working capital items.

Cash from Investing Activities

Cash inflows associated with investing activities are primarily generated from the sale of assets, while cash outflows are the result of plant and equipment expenditures. In any given year, we will look to realize cash from under-performing or non-strategic assets or matured fully valued assets.

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Capital spending within the utility business is primarily to maintain and improve our electric generation and electric and gas distribution infrastructure and to comply with environmental regulations and renewable energy requirements.

Capital spending within our non-utility businesses is primarily 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 used for investing activities was higher in both 2011 and 2010 due primarily to increased capital expenditures by our utility and non-utility businesses.

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.

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 percent to 52 percent, to ensure it is consistent with our objective to have a strong investment grade debt rating.

Net cash used for financing activities was $445 million in 2011, compared to net cash used for financing activities of approximately $586 million for the same period in 2010. The change was primarily attributable to increased short-term borrowings and long-term debt issuances, partially offset by increased long-term debt redemptions.

Net cash used for financing activities was $586 million in 2010, compared to net cash used for financing activities of approximately $789 million for the same period in 2009. The change was primarily attributable to decreased payments for short-term borrowings. Increases in issuances of long-term debt were offset by increased long-term debt redemptions.

Outlook

We expect cash flow from operations to increase over the long-term primarily as a result of growth from our utilities and non-utility businesses. We expect growth in our utilities to be driven primarily by new and existing state and federal regulations that will result in additional environmental and renewable energy investments which will increase the base from which rates are determined. Our non-utility growth is expected from additional investments primarily in our Gas Storage and Pipelines and Power and Industrial Projects segments.

We may be impacted by the delayed collection of underrecoveries of our various recovery and tracking mechanisms as a result of timing of MPSC orders. Energy 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 and maintaining flexibility in the timing and extent of our long-term capital projects.

We have approximately $500 million in long-term debt maturing in the next twelve months. Most of these maturities relate to Securitization and other Detroit Edison issues. The repayment of the principal amount of the Securitization debt is funded through a surcharge payable by Detroit Edison’s electric customers. The repayment of the other Detroit Edison debt is expected to be refinanced with long-term debt.

In October 2011, the Company completed an early renewal of its $1.0 billion and $800 million syndicated unsecured revolving credit facilities before their scheduled expiration in August 2012 and August 2013, respectively. The new $1.8 billion five-year facility will expire in October 2016 and has covenants similar to the prior facilities. DTE Energy has approximately $1.4 billion of available liquidity at December 31, 2011.

We expect to issue equity of approximately $300 million through our dividend reinvestment plan and pension and other employee benefit plans.

At the discretion of management, and depending upon financial market conditions, we anticipate making up to a $240 million contribution to the pension plans in 2012. In January 2012, the Company contributed $140 million to its other postretirement benefit plans. At the discretion of management, the Company may make up to an additional $120 million contribution to its VEBA trusts in 2012.

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The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 provided for a special allowance for bonus depreciation in 2011 and 2012. Bonus depreciation is accelerated depreciation on certain types of business equipment that allows a tax deduction of either 50% or 100% of the cost of qualifying property in the year the asset is placed in service. DTE Energy expects to generate up to approximately $120 million in cash from 2012 bonus depreciation deductions, a significant portion of which is expected to result from Detroit Edison property, plant and equipment expenditures during the qualifying period. The cash benefit is an acceleration of tax deductions that the Company would otherwise have received over 20 years.

We believe we have sufficient operating flexibility, cash resources and funding sources to maintain adequate amounts of liquidity and to meet our future operating cash and capital expenditure needs. However, virtually all of our businesses are capital intensive, or require access to capital, and the inability to access adequate capital could adversely impact earnings and cash flows.

See Notes 11, 12, 15, 17, and 20 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Contractual Obligations

The following table details our contractual obligations for debt redemptions, leases, purchase obligations and other long-term obligations as of December 31, 2011:

	Total		2012		2013-2014		2015-2016		2017 and Beyond
	(In millions)
Long-term debt:
Mortgage bonds, notes and other	$	6,770	$	355	$	1,329	$	836	$	4,250
Securitization bonds	643		164		374		105		—
Junior subordinated debentures	280		—		—		—		280
Capital lease obligations	35		9		16		10		—
Interest	5,507		423		740		574		3,770
Operating leases	195		37		53		38		67
Electric, gas, fuel, transportation and storage purchase obligations (1)	5,080		2,112		1,920		333		715
Other long-term obligations (2)(3)(4)	235		164		33		13		25
Total obligations	$	18,745	$	3,264	$	4,465	$	1,909	$	9,107

_______________________________________

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

(2) Includes liabilities for unrecognized tax benefits of $48 million.

(3) Excludes other long-term liabilities of $184 million not directly derived from contracts or other agreements.

(4) At December 31, 2011, we met the minimum pension funding levels required under the Employee Retirement Income Security Act of 1974 (ERISA) and the Pension Protection Act of 2006 for our defined benefit pension plans. We may contribute more than the minimum funding requirements for our pension plans and may also make contributions to our benefit plans and our postretirement benefit plans; however, these amounts are not included in the table above as such amounts are discretionary. Planned funding levels are disclosed in the Capital Resources and Liquidity and Critical Accounting Estimates sections of MD&A and in Note 20 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

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. The Company’s credit ratings affect our cost of capital and other terms of financing as well as our ability to access the credit and commercial paper markets. 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.

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As part of the normal course of business, Detroit Edison, MichCon and various non-utility subsidiaries of the Company routinely enter into physical or financially settled contracts for the purchase and sale of electricity, natural gas, coal, capacity, storage and other energy-related products and services. Certain of these contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit in the event that the senior unsecured debt rating of DTE Energy is downgraded below investment grade. Certain of these contracts for Detroit Edison and MichCon contain similar provisions in the event that the senior unsecured debt rating of the particular utility is downgraded below investment grade. The amount of such collateral which could be requested fluctuates based upon commodity prices and the provisions and maturities of the underlying transactions and could be substantial. Also, upon a downgrade below investment grade, we could have restricted access to the commercial paper market and if DTE Energy is downgraded below investment grade our non-utility businesses, especially the Energy Trading and Power and Industrial Projects segments, could be required to restrict operations due to a lack of available liquidity. A downgrade below investment grade could potentially increase the borrowing costs of DTE Energy and its subsidiaries and may limit access to the capital markets. The impact of a downgrade will not affect our ability to comply with our existing debt covenants. While we currently do not anticipate such a downgrade, we cannot predict the outcome of current or future credit rating agency reviews.

In January 2011, Fitch Ratings revised the rating outlook for Detroit Edison from stable to positive due to improvement in its credit protection measures as a result of supportive regulatory policies in Michigan. In January 2012, due to several factors including improved and sustained earnings and an overall constructive regulatory environment, Fitch Ratings raised Detroit Edison's senior secured debt rating from 'A-' to 'A' and raised MichCon's senior secured debt rating from 'BBB+' to 'A-'. At the same time, Fitch Ratings revised the rating outlook for MichCon from stable to positive.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in conformity with generally accepted accounting principles require that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the areas described below require significant judgment in the application of accounting policy or in making estimates and assumptions in matters that are inherently uncertain and that may change in subsequent periods. Additional discussion of these accounting policies can be found in the Notes to Consolidated Financial Statements in Item 8 of this Report.

Regulation

A significant portion of our business is subject to regulation. This results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses. Detroit Edison and MichCon are required to record 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 the discontinuance of this accounting treatment for regulatory assets and liabilities for some or all of our businesses. Management believes that currently available facts support the continued use of regulatory assets and liabilities and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment.

In May 2011, Detroit Edison filed an application with the MPSC for approval of its initial pilot RDM reconciliation for the period February 2010 through January 2011 requesting authority to refund to customers approximately $56 million, plus interest. This amount was accrued by Detroit Edison at December 31, 2011. There are various interpretations and alternative calculation methodologies proposed by parties involved in the reconciliation proceeding relating to the pilot RDM refund calculation that could ultimately be adopted by the MPSC which may result in a range of customer refund amounts from $56 million to $140 million for this initial reconciliation filing under the pilot RDM.

In addition, Detroit Edison has accrued a pilot RDM liability for February 2011 through October 2011 of approximately $71 million, plus interest. Detroit Edison terminated the pilot RDM effective October 2011 as ordered by the MPSC, and has requested a rehearing on this issue asserting that for reconciliation purposes, the pilot RDM should have been considered terminated in April 2011 when Detroit Edison self-implemented rates, consistent with prior MPSC orders. An April 2011 termination would result in a decrease to the liability. However, there can be no assurance that Detroit Edison will prevail in this matter. In addition, similar to the initial reconciliation case, there could be various interpretations and alternative calculation methodologies that could be adopted which may result in a range of refund obligations in excess of the amount accrued. Considering the rehearing request and alternative calculation methodologies, the potential customer refund amount could range from $10 million to $130 million for the second and final pilot RDM period.

The primary uncertainties involved in the calculation methodologies of the pilot RDM for both reconciliation periods include customer class groupings and treatment of fixed customer charges. The Company believes that the calculation methodology used and the resulting refund estimates recorded follow the requirements and intent of the MPSC orders and represent the most probable amount of Detroit Edison's pilot RDM refund liability as of December 31, 2011. An MPSC order

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on the initial filing is expected in the first half of 2012. Detroit Edison is required to file an application with the MPSC for approval of its RDM reconciliation for the 2011 reconciliation period by May 2012. A newly designed RDM will be in effect beginning April 2012.

See Note 11 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Derivatives and Hedging Activities

Derivatives are generally recorded at fair value and shown as Derivative Assets or Liabilities. 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. 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. Substantially all of the commodity contracts entered into by Detroit Edison and MichCon meet the criteria specified for this exception.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets and liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. Management makes certain assumptions it believes that market participants would use in pricing assets and liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and our counterparties is incorporated in the valuation of the assets and liabilities through the use of credit reserves, the impact of which was immaterial at December 31, 2011 and 2010. Management believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

The fair values we calculate for our derivatives may change significantly as inputs and assumptions are updated for new information. Actual cash returns realized on our derivatives may be different from the results we estimate using models. As fair value calculations are estimates based largely on commodity prices, we perform sensitivity analysis on the fair values of our forward contracts. See sensitivity analysis in Item 7A. Quantitative and Qualitative Disclosures About Market Risk. See also the Fair Value section, herein. See Notes 3 and 4 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Allowance for Doubtful Accounts

We establish an allowance for doubtful accounts based on historical losses and management's assessment of existing economic conditions, customer trends, and other factors. The allowance for doubtful accounts for our two utilities is calculated using the aging approach that utilizes rates developed in reserve studies and applies these factors to past due receivable balances. As a result of the reduction in past due receivables in 2011 and further refinements to our reserve studies, our allowance for doubtful accounts decreased significantly from the 2010 balance. 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 expense tracking mechanism that partially mitigates the impact associated with MichCon uncollectible expenses. The MPSC provided for a similar tracking mechanism for Detroit Edison in its rate order received January 2010, however it was terminated effective with the electric rate order in October 2011.

Asset Impairments

Goodwill

Certain of our reporting units have goodwill or allocated goodwill resulting from purchase business combinations. We perform an impairment test for each of our reporting units with goodwill annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In performing Step 1 of the impairment test, we compare the fair value of the reporting unit to its carrying value including goodwill. If the carrying value including goodwill were to exceed the fair value of a reporting unit, Step 2 of the test would be performed. Step 2 of the impairment test requires the carrying value of goodwill to be reduced to its fair value, if lower, as of the test date.

For Step 1 of the test, we estimate the reporting unit's fair value using standard valuation techniques, including techniques which use estimates of projected future results and cash flows to be generated by the reporting unit. Such techniques generally include a terminal value that utilizes an earnings multiple approach, which incorporates the current market values of comparable entities. These cash flow valuations involve a number of estimates that require broad assumptions and significant judgment by management regarding future performance. We also employ market-based valuation techniques to test the reasonableness of the indications of value for the reporting units determined under the cash flow technique.

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We performed our annual impairment test as of October 1, 2011 and determined that no impairment existed. We also compared the aggregate fair value of our reporting units to our overall market capitalization. The implied premium of the aggregate fair value over market capitalization is likely attributable to an acquisition control premium (the price in excess of a stock's market price that investors typically pay to gain control of an entity). The results of the test and key estimates that were incorporated are as follows.

As of October 1, 2011 Valuation Date

Reporting Unit	Goodwill		Fair Value Reduction % (a)		Discount Rate		Terminal Multiple (b)	Valuation Methodology (c)
	($ in millions)
Electric Utility	$	1,208	23	%	7	%	8.0x	DCF, assuming stock sale
Gas Utility	745		16	%	7	%	10.0x	DCF, assuming stock sale
Power and Industrial Projects	26		71	%	10	%	8.0x	DCF, assuming asset sale (d)
Gas Storage and Pipelines	22		75	%	9	%	10.0x	DCF, assuming asset sale
Energy Trading	17		50	%	15	%	n/a	Blended DCF, economic value of trading portfolio
Unconventional Gas Production	2		55	%	11	%	n/a	Blended DCF, transaction multiples
	$	2,020

_______________________________________

(a)	Percentage by which the fair value of the reporting unit would need to decline to equal its carrying value, including goodwill.
(b)	Multiple of enterprise value (sum of debt plus equity value) to earnings before interest, taxes, depreciation and amortization (EBITDA).
(c)	Discounted cash flows (DCF) incorporated 2012-2016 projected cash flows plus a calculated terminal value.
(d)	Asset sales were assumed except for Power and Industrial Projects' reduced emissions fuels projects, which assumed stock sales.

The Gas Utility reporting unit passed Step 1 of the impairment test, however further declines in market multiples, negative regulatory actions or other disruptions in cash flows for the Gas Utility reporting unit could result in an impairment charge in the foreseeable future. For example, at the current discount rate and holding all other variables constant, a 1.5x decrease in the terminal multiple would lower the fair value by approximately $423 million. At the lower fair value, the Gas Utility reporting unit would likely fail Step 1 of the test potentially resulting in a charge for impairment of goodwill following completion of the Step 2 analysis.

We perform an annual impairment test each October. In between annual tests, we monitor our estimates and assumptions regarding estimated future cash flows, including the impact of movements in market indicators in future quarters and will update our impairment analyses if a triggering event occurs. While we believe our assumptions are reasonable, actual results may differ from our projections. To the extent projected results or 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.

Long-Lived Assets

We evaluate the carrying value of our long-lived assets, excluding goodwill, when circumstances indicate that the carrying value of those assets may not be recoverable. Conditions that could have an adverse impact on the cash flows and fair value of the long-lived assets are deteriorating business climate, condition of the asset, or plans to dispose of the asset before the end of its useful life. The review of long-lived assets for impairment requires significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level for which independent cash flows of long-lived assets can be identified from other groups of assets and liabilities. Impairment may occur when the carrying value of the asset exceeds the future undiscounted cash flows. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the long-lived asset over its fair value. An impairment would require us to reduce both the long-lived asset and current period earnings by the amount of the impairment, which would adversely impact our earnings. See Note 10 of Notes to Consolidated Financial Statements in Item 8 of this Report.

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Pension and Postretirement Costs

We sponsor defined benefit pension plans and postretirement benefit plans for eligible employees of the Company. The measurement of the plan obligations and cost of providing benefits under these plans involve various factors, including numerous assumptions and accounting elections. When determining the various assumptions that are required, we consider historical information as well as future expectations. The benefit costs are affected by, among other things, the actual rate of return on plan assets, the long-term expected return on plan assets, the discount rate applied to benefit obligations, the incidence of mortality, the expected remaining service period of plan participants, level of compensation and rate of compensation increases, employee age, length of service, the anticipated rate of increase of health care costs and the level of benefits provided to employees and retirees. Pension and postretirement benefit costs attributed to the segments are included with labor costs and ultimately allocated to projects within the segments, some of which are capitalized.

We had pension costs of $172 million in 2011, $112 million in 2010, and $58 million in 2009. Postretirement benefits costs were $122 million in 2011, $164 million in 2010 and $205 million in 2009. Pension and postretirement benefits costs for 2011 are calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on our plan assets of 8.5% for pension plan assets and 8.75% for postretirement health and life plan assets. In developing our expected long-term rate of return assumptions, we evaluated asset class risk and return expectations, as well as inflation assumptions. Projected returns are based on broad equity, bond and other markets. Our 2012 expected long-term rate of return on pension plan assets is based on an asset allocation assumption utilizing active investment management of 47% in equity markets, 25% in fixed income markets, and 28% 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 are lowering our long-term rate of return assumption for our pension plans and our postretirement health and life plans to 8.25% for 2012. We believe this rate is a reasonable assumption for the long-term rate of return on our plan assets for 2012 given our investment strategy. We will continue to evaluate our actuarial assumptions, including our expected rate of return, at least annually.

We calculate the expected return on pension and other postretirement benefit plan assets by multiplying the expected return on plan assets by the market-related value (MRV) of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments that are to be made during the year. Current accounting rules provide that the MRV of plan assets can be either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For our pension plans, we use a calculated value when determining the MRV of the pension plan assets and recognize changes in fair value over a three-year period. Accordingly, the future value of assets will be impacted as previously deferred gains or losses are recognized. Financial markets in 2011 contributed to our investment performance resulting in unrecognized net losses. As of December 31, 2011, we had $100 million of cumulative losses that remain to be recognized in the calculation of the MRV of pension assets. For our postretirement benefit plans, we use fair value when determining the MRV of postretirement benefit plan assets, therefore all investment losses and gains have been recognized in the calculation of MRV for these plans.

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 pension plan and postretirement benefit payment streams with bond portfolios reflecting actual liability duration unique to our plans. The discount rate determined on this basis decreased to 5.0% at December 31, 2011 from 5.5% at December 31, 2010. We estimate that our 2012 total pension costs will approximate $215 million compared to $172 million in 2011 primarily due to a lower discount rate, lower expected return on assets and higher amortization of net actuarial losses, partially offset by 2012 contributions. Our 2012 postretirement benefit costs will approximate $155 million compared to $122 million in 2011 primarily due to a lower discount rate, lower expected return on plan assets, higher amortization of net actuarial losses and updated assumed long-term retiree medical inflation, partially offset by favorable retiree medical utilization. Our health care trend rate assumes 7.00% for 2012 through 2016, 6.50% in 2017, 6.00% in 2018, 5.50% in 2019 and 5.00% in 2020 and beyond. 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. The MPSC approved the deferral of the non-capitalized portion of MichCon's negative pension expense. MichCon records 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 2011 pension costs by approximately $29 million. Lowering the discount rate and the salary increase assumptions by one percentage point would have increased our 2011 pension costs by approximately $7 million. Lowering the health care cost trend assumptions by one percentage point would have decreased our postretirement benefit service and interest costs for 2011 by approximately $24 million.

The value of our pension and postretirement benefit plan assets was $3.9 billion at December 31, 2011 and December 31, 2010. At December 31, 2011, our pension plans were underfunded by $1.3 billion and our other postretirement benefit plans were underfunded by $1.5 billion. The 2011 and 2010 funding levels were generally similar due to plan sponsor contributions

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in 2011 and 2010, largely offset by the decreased discount rates.

Pension and postretirement costs and pension cash funding requirements may increase in future years without typical returns in the financial markets. We made contributions to our pension plans of $200 million in 2011 and $200 million in 2010. At the discretion of management, consistent with the Pension Protection Act of 2006, and depending upon financial market conditions, we anticipate making contributions to our pension plans of $240 million in 2012 and up to $1.1 billion over the next five years. We made postretirement benefit plan contributions of $111 million and $160 million in 2011 and 2010, respectively. We are required by orders issued by the MPSC to make postretirement benefit contributions at least equal to the amounts included in our utilities' base rates. As a result, we contributed $140 million to our postretirement plans in January 2012 and expect to make up to an additional $120 million contribution to our postretirement plans in 2012 and, subject to MPSC funding requirements, up to $855 million over the next five years. The planned contributions will be made in cash, DTE Energy common stock or a combination of cash and stock.

Effective in June 2011, we discontinued offering future Greater Michigan represented employees a defined benefit pension plan benefit. In its place, the Company will annually contribute an amount equivalent to four percent of an employee's eligible pay to the employee's defined contribution retirement savings plan. Also, for future Greater Michigan represented employees after completion of one year of service, in lieu of offering post-employment health care and life insurance benefits, the Company will contribute an amount equivalent to an additional four percent of an employee's eligible pay to the employee's defined contribution retirement savings plan, plus a one-time contribution of $1,400.

Effective January 1, 2012, we discontinued offering future non-represented employees a cash balance retirement plan benefit. In its place, the Company will annually contribute an amount equivalent to four percent of an employee's eligible pay to the employee's defined contribution retirement savings plan. Also effective January 1, 2012, in lieu of offering future non-represented employees post-employment health care and life insurance benefits, the Company will allocate $4,000 per year to an account in a tax-exempt trust for each employee. The accumulated balance and earnings in an employee's account will vest when the employee has 10 years of service, regardless of age. These funds will be available to the employee to use for health care expenses after the employee leaves the Company.

See Note 20 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- $9 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, 2011, this IBNR liability was approximately $39 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. We account 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. 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. We also have non-income tax obligations related to property, sales and use and employment-related taxes and ongoing appeals related to these tax matters.

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

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our ability to utilize tax attributes, including those in the form of carry-forwards, 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. We believe the resulting tax reserve balances as of December 31, 2011 and December 31, 2010 are appropriately accounted. The ultimate outcome of such matters could result in favorable or unfavorable adjustments to our consolidated financial statements and such adjustments could be material.

See Note 12 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

FAIR VALUE

Derivatives are generally recorded at fair value and shown as Derivative Assets or Liabilities. Contracts we typically classify as derivative instruments include power, gas, oil and certain coal forwards, futures, options and swaps, and foreign currency exchange contracts. Items we do not generally account for as derivatives include natural gas inventory, power transmission, pipeline transportation and certain storage assets. See Notes 3 and 4 of the Notes to Consolidated Financial Statements.

The tables below do not include the expected earnings impact of non-derivative gas storage, transportation and power contracts which are subject to accrual accounting. 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 the timing differences will reverse at the time of physical delivery and/or settlement.

The Company manages its mark-to-market (MTM) risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, it records and manages the energy purchase and sale obligations under its 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).

The Company has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). For further discussion of the fair value hierarchy, see Note 3 of the Notes to Consolidated Financial Statements.

The following tables provide details on changes in our MTM net asset (or liability) position during 2011:

	Total
	(In millions)
MTM at December 31, 2010	$	(44	)
Reclassify to realized upon settlement	(37		)
Changes in fair value recorded to income	159
Amounts recorded to unrealized income	122
Changes in fair value recorded in regulatory liabilities	2
Change in collateral held by others	10
Option premiums paid (received) and other	(41		)
MTM at December 31, 2011	$	49

The table below shows the maturity of our MTM positions:

Source of Fair Value	2012			2013			2014		2015  and  Beyond			Total Fair Value
	(In millions)
Level 1	$	(32	)	$	17		$	10	$	(5	)	$	(10	)
Level 2	(7		)	(34		)	1		—			(40		)
Level 3	29			9			5		1			44
Total MTM before collateral adjustments	$	(10	)	$	(8	)	$	16	$	(4	)	$	(6	)
Collateral adjustments												$	55
Total MTM at December 31, 2011												$	49

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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. However, the Company does not bear significant exposure to earnings risk as such changes are included in the PSCR and GCR regulatory rate-recovery mechanisms. In addition, changes in the price of natural gas can impact the valuation of lost and stolen gas, storage sales revenue and uncollectible expenses at the Gas Utility. Gas Utility manages its market price risk related to storage sales revenue primarily through the sale of long-term storage contracts. The Company is exposed to short-term cash flow or liquidity risk as a result of the time differential between actual cash settlements and regulatory rate recovery.

Our Gas Storage and Pipelines business segment has limited exposure to natural gas price fluctuations and manages its exposure through the sale of long-term storage and transportation contracts.

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

Our Power and Industrial Projects business segment is subject to electricity, natural gas, coal and coal-based product price risk and other risks associated with the weakened U.S. economy. To the extent that commodity price risk has not been mitigated through the use of long-term contracts, we manage this exposure using forward energy, capacity and futures contracts.

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

Credit Risk

Bankruptcies

The Company purchases and sells electricity, gas, coal, coke and other energy products from and to governmental entities and numerous companies operating in the steel, automotive, energy, retail, financial and other industries. Certain of its 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 records provisions for amounts considered at risk of probable loss. The Company believes its accrued amounts are adequate for probable loss. The final resolution of these matters may have a material effect on its consolidated financial statements.

Other

MichCon has an uncollectible expense tracking mechanism that enables it to recover or refund 80 percent of the difference between the actual uncollectible expense each year and the level established in its last rate case. Detroit Edison had an uncollectible expense tracking mechanism which was terminated in Detroit Edison's October 2011 electric rate order. The uncollectible expense tracking mechanisms require annual reconciliation proceedings before the MPSC. See Note 11 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

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.

Trading Activities

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 internal 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, 2011:

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	Credit Exposure Before Cash Collateral		Cash Collateral		Net Credit Exposure
	(In millions)
Investment Grade (1)
A− and Greater	$	171	$	—	$	171
BBB+ and BBB	332		—		332
BBB−	98		—		98
Total Investment Grade	601		—		601
Non-investment grade (2)	7		—		7
Internally Rated — investment grade (3)	147		—		147
Internally Rated — non-investment grade (4)	8		—		8
Total	$	763	$	—	$	763

_______________________________________

(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 (Standard & Poor’s). The five largest counterparty exposures combined for this category represented approximately 35 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 one 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 12 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

We are 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, 2011, we had a floating rate debt-to-total debt ratio of approximately 10 percent (excluding securitized debt).

Foreign Currency Exchange Risk

We have 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 exchange fluctuations, we have entered into a series of foreign currency exchange forward contracts through July 2015.

Summary of Sensitivity Analysis

We performed a sensitivity analysis on the fair values of our commodity contracts, long-term debt obligations and foreign currency exchange forward contracts. The commodity contracts and foreign currency exchange risk listed below principally relate to our energy marketing and trading activities. The sensitivity analysis involved increasing and decreasing forward rates at December 31, 2011 and 2010 by a hypothetical 10% and calculating the resulting change in the fair values.

47

The results of the sensitivity analysis calculations as of December 31, 2011 and 2010:

	Assuming a 10% Increase in Rates						Assuming a 10% Decrease in Rates
	As of December 31,						As of December 31,
Activity	2011			2010			2011			2010			Change in the Fair Value of
	(In millions)
Coal Contracts	$	(2	)	$	1		$	2		$	(1	)	Commodity contracts
Gas Contracts	$	(9	)	$	(11	)	$	13		$	10		Commodity contracts
Power Contracts	$	4		$	(5	)	$	(6	)	$	5		Commodity contracts
Interest Rate Risk	$	(260	)	$	(291	)	$	276		$	313		Long-term debt
Foreign Currency Exchange Risk	$	—		$	6		$	—		$	7		Forward contracts
Discount Rates	$	—		$	—		$	—		$	—		Commodity contracts

For further discussion of market risk, see Note 4 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

48

Item 8. Financial Statements and Supplementary Data

The following consolidated financial statements and financial statement schedule are included herein.

	Page
Controls and Procedures	50
Report of Independent Registered Public Accounting Firm	51
Consolidated Statements of Operations	52
Consolidated Statements of Financial Position	53
Consolidated Statements of Cash Flows	55
Consolidated Statements of Changes in Equity	56
Consolidated Statements of Comprehensive Income	57
Notes to Consolidated Financial Statements	58
Note 1. Organization and Basis of Presentation	58
Note 2. Significant Accounting Policies	60
Note 3. Fair Value	65
Note 4. Financial and Other Derivative Instruments	71
Note 5. Goodwill	75
Note 6. Property, Plant and Equipment	75
Note 7. Jointly Owned Utility Plant	76
Note 8. Asset Retirement Obligations	77
Note 9. Disposals	78
Note 10. Other Impairments and Restructuring	78
Note 11. Regulatory Matters	79
Note 12. Income Taxes	87
Note 13. Common Stock	90
Note 14. Earnings Per Share	91
Note 15. Long-Term Debt	92
Note 16. Preferred and Preference Securities	94
Note 17. Short-Term Credit Arrangements and Borrowings	94
Note 18. Capital and Operating Leases	95
Note 19. Commitments and Contingencies	96
Note 20. Retirement Benefits and Trusteed Assets	101
Note 21. Stock-based Compensation	111
Note 22. Supplemental Cash Flow Information	114
Note 23. Segment and Related Information	115
Note 24. Supplementary Quarterly Financial Information (Unaudited)	117
Financial Statement Schedule
Schedule II — Valuation and Qualifying Accounts	126

49

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 (CEO) and Chief Financial Officer (CFO), 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, 2011, which is the end of the period covered by this report. Based on this evaluation, the Company’s CEO and CFO have concluded that such disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) is accumulated and communicated to the Company’s management, including its CEO and CFO, 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

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Internal control over financial reporting is a process designed by, or under the supervision of, our CEO and CFO, 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.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management of the Company has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on this assessment, management concluded that, as of December 31, 2011, the Company’s internal control over financial reporting was effective based on those criteria.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2011 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm who also audited the Company’s financial statements, as stated in their report which appears herein.

(c) Changes in internal control over financial reporting

There have been no changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

50

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of DTE Energy Company and its subsidiaries at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying indexpresents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, 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 opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed 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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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 its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Detroit, Michigan

February 16, 2012

51

DTE Energy Company

Consolidated Statements of Operations

	Year Ended December 31
	2011			2010			2009
	(In millions, except per share amounts)
Operating Revenues	$	8,897		$	8,557		$	8,014
Operating Expenses
Fuel, purchased power and gas	3,537			3,190			3,118
Operation and maintenance	2,628			2,578			2,372
Depreciation, depletion and amortization	995			1,027			1,020
Taxes other than income	313			308			275
Asset (gains) and losses, reserves and impairments, net	1			(10		)	(20		)
	7,474			7,093			6,765
Operating Income	1,423			1,464			1,249
Other (Income) and Deductions
Interest expense	494			549			545
Interest income	(10		)	(12		)	(19		)
Other income	(117		)	(78		)	(102		)
Other expenses	69			55			43
	436			514			467
Income Before Income Taxes	987			950			782
Income Tax Expense	267			311			247
Net Income	720			639			535
Less Net Income Attributable to Noncontrolling Interests	9			9			3
Net Income Attributable to DTE Energy Company	$	711		$	630		$	532
Basic Earnings per Common Share
Net Income Attributable to DTE Energy Company	$	4.19		$	3.75		$	3.24
Diluted Earnings per Common Share
Net Income Attributable to DTE Energy Company	$	4.18		$	3.74		$	3.24
Weighted Average Common Shares Outstanding
Basic	169			168			164
Diluted	170			169			164
Dividends Declared per Common Share	$	2.32		$	2.18		$	2.12

See Notes to Consolidated Financial Statements

52

DTE Energy Company

Consolidated Statements of Financial Position

	December 31
	2011			2010
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	68		$	65
Restricted cash, principally Securitization	147			120
Accounts receivable (less allowance for doubtful accounts of $162 and $196, respectively)
Customer	1,317			1,351
Other	90			402
Inventories
Fuel and gas	572			460
Materials and supplies	219			202
Deferred income taxes	51			139
Derivative assets	222			131
Regulatory assets	314			100
Other	196			197
	3,196			3,167
Investments
Nuclear decommissioning trust funds	937			939
Other	525			518
	1,462			1,457
Property
Property, plant and equipment	22,541			21,574
Less accumulated depreciation, depletion and amortization	(8,795		)	(8,582		)
	13,746			12,992
Other Assets
Goodwill	2,020			2,020
Regulatory assets	4,539			4,058
Securitized regulatory assets	577			729
Intangible assets	73			67
Notes receivable	123			123
Derivative assets	74			77
Other	199			206
	7,605			7,280
Total Assets	$	26,009		$	24,896

See Notes to Consolidated Financial Statements

53

DTE Energy Company

Consolidated Statements of Financial Position — (Continued)

	December 31
	2011			2010
	(In millions, except shares)
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	782		$	729
Accrued interest	95			111
Dividends payable	99			95
Short-term borrowings	419			150
Current portion long-term debt, including capital leases	526			925
Derivative liabilities	158			142
Other	549			597
	2,628			2,749
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	6,405			6,114
Securitization bonds	479			643
Junior subordinated debentures	280			—
Trust preferred-linked securities	—			289
Capital lease obligations	23			43
	7,187			7,089
Other Liabilities
Deferred income taxes	3,116			2,632
Regulatory liabilities	1,019			1,328
Asset retirement obligations	1,591			1,498
Unamortized investment tax credit	65			75
Derivative liabilities	89			110
Accrued pension liability	1,298			866
Accrued postretirement liability	1,484			1,275
Nuclear decommissioning	148			149
Other	331			358
	9,141			8,291
Commitments and Contingencies (Notes 11 and 19)
Equity
Common stock, without par value, 400,000,000 shares authorized, 169,247,282 and 169,428,406 shares issued and outstanding, respectively	3,417			3,440
Retained earnings	3,750			3,431
Accumulated other comprehensive loss	(158		)	(149		)
Total DTE Energy Company Equity	7,009			6,722
Noncontrolling interests	44			45
Total Equity	7,053			6,767
Total Liabilities and Equity	$	26,009		$	24,896

See Notes to Consolidated Financial Statements

54

DTE Energy Company

Consolidated Statements of Cash Flows

	Year Ended December 31
	2011			2010			2009
	(In millions)
Operating Activities
Net income	$	720		$	639		$	535
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	995			1,027			1,020
Deferred income taxes	220			457			205
Asset (gains) and losses, reserves and impairments, net	(21		)	(5		)	(10		)
Changes in assets and liabilities, exclusive of changes shown separately (Note 22)	94			(293		)	69
Net cash from operating activities	2,008			1,825			1,819
Investing Activities
Plant and equipment expenditures — utility	(1,382		)	(1,011		)	(960		)
Plant and equipment expenditures — non-utility	(102		)	(88		)	(75		)
Proceeds from sale of assets	18			56			83
Restricted cash for debt redemption, principally Securitization	(5		)	(32		)	2
Proceeds from sale of nuclear decommissioning trust fund assets	80			377			295
Investment in nuclear decommissioning trust funds	(97		)	(410		)	(315		)
Consolidation of VIEs	—			19			—
Investment in Millennium Pipeline Project	(3		)	(49		)	(15		)
Other	(69		)	(88		)	(79		)
Net cash used for investing activities	(1,560		)	(1,226		)	(1,064		)
Financing Activities
Issuance of long-term debt	1,179			614			427
Redemption of long-term debt	(1,455		)	(663		)	(486		)
Short-term borrowings, net	269			(177		)	(417		)
Issuance of common stock	—			36			35
Repurchase of common stock	(18		)	—			—
Dividends on common stock	(389		)	(360		)	(348		)
Other	(31		)	(36		)	—
Net cash used for financing activities	(445		)	(586		)	(789		)
Net Increase (Decrease) in Cash and Cash Equivalents	3			13			(34		)
Cash and Cash Equivalents at Beginning of Period	65			52			86
Cash and Cash Equivalents at End of Period	$	68		$	65		$	52

See Notes to Consolidated Financial Statements

55

DTE Energy Company

Consolidated Statements of Changes in Equity

									Accumulated Other Comprehensive Loss			Non-Controlling Interest
	Common Stock					Retained Earnings
	Shares		Amount												Total
	(Dollars in millions, shares in thousands)
Balance, December 31, 2008	163,020		$	3,175		$	2,985		$	(165	)	$	43		$	6,038
Net income	—		—			532			—			3			535
Dividends declared on common stock	—		—			(349		)	—			—			(349		)
Issuance of common stock	1,109		35			—			—			—			35
Benefit obligations, net of tax	—		—			—			7			—			7
Foreign currency translation, net of tax	—		—			—			2			—			2
Net change in unrealized losses on derivatives, net of tax	—		—			—			1			—			1
Net change in unrealized losses on investments, net of tax	—		—			—			8			—			8
Contributions from noncontrolling interests	—		—			—			—			4			4
Stock-based compensation, distributions to noncontrolling interests and other	1,271		47			—			—			(12		)	35
Balance, December 31, 2009	165,400		$	3,257		$	3,168		$	(147	)	$	38		$	6,316
Net income	—		—			630			—			9			639
Dividends declared on common stock	—		—			(367		)	—			—			(367		)
Issuance of common stock	777		36			—			—			—			36
Contribution of common stock to pension plan	2,224		100			—			—			—			100
Benefit obligations, net of tax	—		—			—			15			—			15
Foreign currency translation, net of tax	—		—			—			1			—			1
Net change in unrealized losses on derivatives, net of tax	—		—			—			2			—			2
Net change in unrealized losses on investments, net of tax	—		—			—			(20		)	—			(20		)
Stock-based compensation, distributions to noncontrolling interests and other	1,027		47			—			—			(2		)	45
Balance, December 31, 2010	169,428		$	3,440		$	3,431		$	(149	)	$	45		$	6,767
Net Income	—		—			711			—			9			720
Dividends declared on common stock	—		—			(392		)	—			—			(392		)
Repurchase of common stock	(1,184	)	(58		)	—			—			—			(58		)
Benefit obligations, net of tax	—		—			—			(9		)	—			(9		)
Stock-based compensation, distributions to noncontrolling interests and other	1,003		35			—			—			(10		)	25
Balance, December 31, 2011	169,247		$	3,417		$	3,750		$	(158	)	$	44		$	7,053

See Notes to Consolidated Financial Statements

56

DTE Energy Company

Consolidated Statements of Comprehensive Income

The following table displays comprehensive income:

	2011			2010			2009
	(In millions)
Net income	$	720		$	639		$	535
Other comprehensive income (loss), net of tax:
Benefit obligations:
Benefit obligations, net of taxes of $(5), $3 and $4	(9		)	5			7
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $—, $5 and $—	—			10			—
	(9		)	15			7
Net unrealized gains on derivatives:
Gains during the period, net of taxes of $—, $1 and $2	—			1			3
Amounts reclassified to income, net of taxes of $—, $1 and $(1)	—			1			(2		)
	—			2			1
Net unrealized gains (losses) on investments:
Gains (losses) during the period, net of taxes of $—, $(6) and $3	—			(10		)	5
Amounts reclassified to income, net of taxes of $—, $— and $2	—			—			3
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $—, $(5) and $—	—			(10		)	—
	—			(20		)	8
Foreign currency translation, net of taxes of $—, $— and $1	—			1			2
Comprehensive income	711			637			553
Less comprehensive income attributable to noncontrolling interests	9			9			3
Comprehensive income attributable to DTE Energy Company	$	702		$	628		$	550

See Notes to Consolidated Financial Statements

57

DTE Energy Company

Notes to Consolidated Financial Statements

NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION

Corporate Structure

DTE Energy owns the following businesses:

• Detroit Edison, an electric utility engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan;

• MichCon, a natural gas utility engaged in the purchase, storage, transportation, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan and the sale of storage and transportation capacity; and

• Other businesses involved in 1) natural gas pipelines, gathering and storage; 2) unconventional gas and oil 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. Certain activities of Detroit Edison and MichCon, as well as various other aspects of businesses under DTE Energy are regulated by the FERC. In addition, the Company is regulated by other federal and state regulatory agencies including the NRC, the EPA and the MDEQ.

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

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.

Certain prior year balances were reclassified to match the current year’s financial statement presentation.

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.

Effective January 1, 2010, the Company adopted the provisions of ASU 2009-17, Amendments to FASB Interpretation 46(R). ASU 2009-17 changed the methodology for determining the primary beneficiary of a VIE from a quantitative risk and rewards-based model to a qualitative determination. There is no grandfathering of previous consolidation conclusions. As a result, the Company re-evaluated all prior VIE and primary beneficiary determinations. The requirements of ASU 2009-17 were adopted on a prospective basis.

The Company evaluates whether an entity is a VIE whenever reconsideration events occur. The Company consolidates VIEs for which it is the primary beneficiary. If the Company is not the primary beneficiary and an ownership interest is held, the VIE is accounted for under the equity method of accounting. When assessing the determination of the primary beneficiary, the Company considers all relevant facts and circumstances, including: the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb the expected losses and/or the right to receive the expected returns of the VIE. The Company performs ongoing reassessments of all VIEs to determine if the primary beneficiary status has changed.

Legal entities within the Company’s Power and Industrial Projects segment enter into long-term contractual arrangements with customers to supply energy-related products or services. The entities are generally designed to pass-through the commodity risk associated with these contracts to the customers, with the Company retaining operational and customer default risk. These entities generally are VIEs. In addition, the Company has interests in certain VIEs that we share control of all significant activities for those entities with our partners, and therefore are accounted for under the equity method.

58

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The Company has variable interests in VIEs through certain of its long-term purchase contracts. As of December 31, 2011, the carrying amount of assets and liabilities in the Consolidated Statement of Financial Position that relate to its variable interests under long-term purchase contracts are predominately related to working capital accounts and generally represent the amounts owed by the Company for the deliveries associated with the current billing cycle under the contracts. The Company has not provided any form of financial support associated with these long-term contracts. There is no significant potential exposure to loss as a result of its variable interests through these long-term purchase contracts.

In 2001, Detroit Edison financed a regulatory asset related to Fermi 2 and certain other regulatory assets through the sale of rate reduction bonds by a wholly-owned special purpose entity, Securitization. Detroit Edison performs servicing activities including billing and collecting surcharge revenue for Securitization. This entity is a VIE, and is consolidated by the Company.

DTE Energy had interests in various unconsolidated trusts that were formed for the purpose of issuing preferred securities and lending the gross proceeds to the Company. DTE Energy reviewed these interests and determined they were VIEs, but the Company was not the primary beneficiary as it did not have variable interests in the trusts and therefore, the trusts were not consolidated by the Company. See Note 15.

The maximum risk exposure for consolidated VIEs is reflected on the Company’s Consolidated Statements of Financial Position. For non-consolidated VIEs, the maximum risk exposure is generally limited to its investment and amounts which it has guaranteed.

The following table summarizes the major balance sheet items for consolidated VIEs as of December 31, 2011and December 31, 2010. Amounts at December 31, 2011 for consolidated VIEs that are either (1) assets that can be used only to settle obligations of the VIE or (2) liabilities for which creditors do not have recourse to the general credit of the primary beneficiary are segregated in the restricted amounts column. VIEs, in which the Company holds a majority voting interest and is the primary beneficiary, that meet the definition of a business and whose assets can be used for purposes other than the settlement of the VIE’s obligations have been excluded from the table below.

	December 31, 2011
	Securitization		Other		Total		Restricted Amounts
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	25	$	25	$	—
Restricted cash	107		7		114		114
Accounts receivable	34		17		51		36
Inventories	—		183		183		—
Other current assets	—		1		1		—
Property, plant and equipment	—		73		73		23
Securitized regulatory assets	577		—		577		577
Other assets	10		6		16		16
	$	728	$	312	$	1,040	$	766
LIABILITIES
Accounts payable and accrued current liabilities	$	14	$	24	$	38	$	14
Current portion long-term debt, including capital leases	164		7		171		171
Other current liabilities	55		—		55		55
Mortgage bonds, notes and other	—		30		30		30
Securitization bonds	479		—		479		479
Capital lease obligations	—		14		14		14
Other long term liabilities	7		2		9		8
	$	719	$	77	$	796	$	771

59

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

	December 31, 2010
	Securitization		Other		Total		Restricted Amounts
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	4	$	4	$	—
Restricted cash	104		8		112		112
Accounts receivable	42		8		50		44
Inventories	—		99		99		—
Other current assets	—		1		1		—
Property, plant and equipment	—		54		54		38
Securitized regulatory assets	729		—		729		729
Other assets	13		9		22		21
	$	888	$	183	$	1,071	$	944
LIABILITIES
Accounts payable and accrued current liabilities	$	17	$	27	$	44	$	18
Current portion long-term debt, including capital leases	150		7		157		157
Other current liabilities	62		6		68		66
Mortgage bonds, notes and other	—		35		35		35
Securitization bonds	643		—		643		643
Capital lease obligations	—		23		23		23
Other long term liabilities	6		7		13		12
	$	878	$	105	$	983	$	954

Amounts for non-consolidated VIEs as of December 31, 2011 and December 31, 2010 are as follows:

	December 31, 2011		December 31, 2010
	(In millions)
Other investments	$	117	$	98
Notes receivable	7		6
Trust preferred — linked securities	—		289

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

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 electricity and gas provided but unbilled at the end of each month. Rates for Detroit Edison and MichCon include provisions to adjust billings for fluctuations in fuel and purchased power costs, cost of natural gas and certain other costs. Revenues are adjusted for differences between actual costs and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are recorded on the Consolidated Statement of Financial Position and are recovered or returned to customers through adjustments to the billing factors.

Detroit Edison had a CIM, which was an over/under recovery mechanism that measured non-fuel revenues lost or gained as a result of fluctuations in electric Customer Choice sales. If annual electric Customer Choice sales exceeded the baseline amount from Detroit Edison's most recent rate case, 90 percent of its lost non-fuel revenues associated with sales above that level may be recovered from full service customers. If annual electric Customer Choice sales decreased below the baseline, the Company must refund 90 percent of its increase in non-fuel revenues associated with sales below that level to full service customers. The CIM

60

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

was terminated effective with the October 20, 2011 MPSC rate order. On January 17, 2012, Detroit Edison filed an application with the MPSC for approval of its CIM reconciliation for 2011.

Detroit Edison and MichCon had RDMs in place in 2011 designed to minimize the impact on revenues of changes in average customer usage of electricity and natural gas. The electric RDM enabled Detroit Edison to recover or refund the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established in the MPSC order. The 2011 pilot RDM established in Detroit Edison's 2009 rate case was terminated by the MPSC in October 2011, but the Company has requested rehearing on this point asserting the termination should have occurred in April 2011. Detroit Edison will have a newly designed RDM that will be effective in April 2012. See Note 11 for further discussion of the newly designed RDM. The June 2010 MPSC order in MichCon's 2009 rate case provided for the implementation of a pilot gas RDM effective July 1, 2010, which enables MichCon to recover or refund the change in revenue resulting from the difference in weather-adjusted average sales per customer compared to the base average sales per customer established in the MPSC order. The gas RDM is subject to review in future MPSC proceedings during the pilot program. The gas RDM addresses changes in customer usage due to general economic conditions and conservation, but does not shield MichCon from the impacts of lost customers or weather variations.

See Note 11 for further discussion of recovery mechanisms authorized by the MPSC.

Non-utility businesses recognize revenues as services are provided and products are delivered. Revenues and energy costs related to trading contracts are presented on a net basis in the Consolidated Statements of Operations. Commodity derivatives used for trading purposes are accounted for using the mark-to-market method with unrealized gains and losses recorded in Operating Revenues.

Accounting for ISO Transactions

Detroit Edison participates in the energy market through MISO. MISO requires that we submit hourly day-ahead, real time and FTR bids and offers for energy at locations across the MISO region. Detroit Edison accounts for MISO transactions on a net hourly basis in each of the day-ahead, real-time and FTR markets and net transactions across all MISO energy market locations. In any single hour Detroit Edison records net purchases in Fuel, purchased power and gas and net sales in Operating revenues on the Consolidated Statements of Operations. Detroit Edison records net sale billing adjustments when invoices are received.

Energy Trading participates in the energy markets through various independent system operators and regional transmission organizations (ISOs and RTOs). These markets require that we submit hourly day-ahead, real time bids and offers for energy at locations across each region. We submit bids in the annual and monthly auction revenue rights and FTR auctions to the regional transmission organizations. Energy Trading accounts for these transactions on a net hourly basis for the day-ahead, real-time and FTR markets. These transactions are related to our trading contracts which are presented on a net basis in Operating revenues in the Consolidated Statements of Income.

Detroit Edison and Energy Trading record expense accruals for future net purchases adjustments based on historical experience, and reconcile accruals to actual expenses when invoices are received from MISO, the ISOs and RTOs.

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 accumulated other comprehensive loss for the year ended December 31, 2011 include unrealized gains and losses from derivatives accounted for as cash flow hedges, unrealized gains and losses on available for sale securities, the Company’s interest in comprehensive income of equity investees, changes in benefit obligations, consisting of deferred actuarial losses, prior service costs and transition amounts related to pension and other postretirement benefit plans, and foreign currency translation adjustments.

	Net Unrealized Gain/(Loss) on Derivatives			Net Unrealized Gain/(Loss) on Investments			Benefit Obligations			Foreign Currency Translation		Accumulated Other Comprehensive Loss
							(In millions)
Beginning balances	$	(4	)	$	(30	)	$	(116	)	$	1	$	(149	)
Current period change, net of tax	—			—			(9		)	—		(9		)
Ending balance	$	(4	)	$	(30	)	$	(125	)	$	1	$	(158	)

61

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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, primarily Securitization bonds, and partnership operating agreements. Restricted cash designated for interest and principal payments within one year is classified as a current asset.

Receivables

Accounts receivable are primarily composed of trade receivables and unbilled revenue. Our accounts receivable are stated at net realizable value.

The allowance for doubtful accounts for Detroit Edison and MichCon is generally calculated using the aging approach that utilizes rates developed in reserve studies. We establish an allowance for uncollectible accounts based on historical losses and management’s assessment of existing economic conditions, customer trends, and other factors. Customer accounts are generally considered delinquent if the amount billed is not received by the due date, which is typically in 21 days, however, factors such as assistance programs may delay aggressive action. We assess late payment fees on trade receivables based on past-due terms with customers. Customer accounts are written off when collection efforts have been exhausted, generally one year after service has been terminated.

The customer allowance for doubtful accounts for our other businesses is calculated based on specific review of probable future collections based on receivable balances in excess of 30 days.

Unbilled revenues of $597 million and $575 million are included in customer accounts receivable at December 31, 2011 and 2010, respectively.

Notes Receivable

Notes receivable, or financing receivables, are primarily comprised of capital lease receivables and loans and are included in Notes receivable and Other current assets on the Company’s Consolidated Statements of Financial Position.

Notes receivable are typically considered delinquent when payment is not received for periods ranging from 60 to 120 days. The Company ceases accruing interest (nonaccrual status), considers a note receivable impaired, and establishes an allowance for credit loss when it is probable that all principal and interest amounts due will not be collected in accordance with the contractual terms of the note receivable. Cash payments received on nonaccrual status notes receivable, that do not bring the account contractually current, are first applied to contractually owed past due interest, with any remainder applied to principal. Accrual of interest is generally resumed when the note receivable becomes contractually current.

In determining the allowance for credit losses for notes receivable, we consider the historical payment experience and other factors that are expected to have a specific impact on the counterparty’s ability to pay. In addition, the Company monitors the credit ratings of the counterparties from which we have notes receivable.

Inventories

The Company generally values inventory at average cost.

Gas inventory of $52 million and $43 million as of December 31, 2011and 2010, respectively, at MichCon is determined using the last-in, first-out (LIFO) method. At December 31, 2011, the replacement cost of gas remaining in storage exceeded the LIFO cost by $95 million. At December 31, 2010, the replacement cost of gas remaining in storage exceeded the LIFO cost by $147 million.

Property, Retirement and Maintenance, and Depreciation, Depletion and Amortization

Property is stated at cost and includes construction-related labor, materials, overheads and, for utility property, an allowance for funds used during construction (AFUDC). The cost of utility properties retired, including the cost of removal, less salvage value, is charged to accumulated depreciation. Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2.

Utility property at Detroit Edison and MichCon is depreciated over its estimated useful life using straight-line rates approved by the MPSC.

Non-utility property is depreciated over its estimated useful life using straight-line and units-of-production methods.

62

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The Company credits depreciation, depletion and amortization expense when it establishes regulatory assets for plant-related costs such as depreciation or plant-related financing costs. The Company charges depreciation, depletion and amortization expense when it amortizes these regulatory assets. The Company credits interest expense to reflect the accretion income on certain regulatory assets.

Approximately $23 million and $3 million of expenses related to Fermi 2 refueling outages were accrued at December 31, 2011 and December 31, 2010, respectively. Amounts are accrued on a pro-rata basis over an 18-month period that coincides with scheduled refueling outages at Fermi 2. This accrual of outage costs matches the regulatory recovery of these costs in rates set by the MPSC. See Note 11.

The cost of nuclear fuel is capitalized. The amortization of nuclear fuel is included within Fuel, purchased power, and gas in the Consolidated Statement of Operations and is recorded using the units-of-production method.

Unconventional Gas Production

The Company follows the successful efforts method of accounting for investments in oil and 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 contains proved reserves. If an exploratory well does not contain 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 properties without economical quantities of proved reserves are expensed as incurred. An impairment loss is recorded if the net capitalized costs of proved gas properties exceed the aggregate related undiscounted future net revenues. 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. Depreciation, depletion and amortization of proved gas properties are determined using the units-of-production method.

Long-Lived Assets

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

Intangible Assets

The Company has certain intangible assets relating to emission allowances, renewable energy credits and non-utility contracts. Summary of intangible assets as of December 31:

(In millions)	2011		2010
Emission allowances	$	9	$	9
Renewable energy credits	27		17
Contract intangible assets	65		63
	101		89
Less accumulated amortization	28		22
Intangible assets, net	$	73	$	67

Emission allowances and renewable energy credits are charged to expense, using average cost, as the allowances and credits are consumed in the operation of the business. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 3 to 20 years. Intangible assets amortization expense was $5 million in 2011, $4 million in 2010 and $4 million in 2009. Amortization expense of intangible assets is estimated to be $3 million annually for 2012 through 2016.

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 net impact on the Consolidated Statements of Operations.

63

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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.

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 equity 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 equity investment being written down to its estimated fair value. See Note 3.

Offsetting Amounts Related to Certain Contracts

The Company offsets 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 agreement, which reduces the Company’s total assets and total liabilities. As of December 31, 2011 and December 31, 2010, the total cash collateral posted, net of cash collateral received, was $71 million and $77 million, respectively. Derivative assets and derivative liabilities are shown net of collateral of $19 million and $74 million, respectively, as of December 31, 2011 and $9 million and $53 million, respectively, as of December 31, 2010. The Company recorded cash collateral paid of $16 million not related to unrealized derivative positions as of December 31, 2011. The Company recorded cash collateral received of $2 million and cash collateral paid of $35 million not related to unrealized derivative positions, as of December 31, 2010. These amounts are included in accounts receivable and accounts payable and are recorded net by counterparty.

Government Grants

Grants are recognized when there is reasonable assurance that the grant will be received and that any conditions associated with the grant will be met. When grants are received related to Property, Plant and Equipment, the Company reduces the basis of the assets on the Consolidated Statements of Financial Position, resulting in lower depreciation expense over the life of the associated asset. Grants received related to expenses are reflected as a reduction of the associated expense in the period in which the expense is incurred.

Other Accounting Policies

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

Note	Title
3	Fair Value
4	Financial and Other Derivative Instruments
5	Goodwill
8	Asset Retirement Obligations
11	Regulatory Matters
12	Income Taxes
20	Retirement Benefits and Trusteed Assets
21	Stock-based Compensation

64

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 3 — FAIR VALUE

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The Company makes certain assumptions it believes that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and its counterparties is incorporated in the valuation of assets and liabilities through the use of credit reserves, the impact of which was immaterial at December 31, 2011 and December 31, 2010. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

A fair value hierarchy has been established, that prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement in its entirety. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The Company classifies fair value balances based on the fair value hierarchy defined as follows:

• Level 1 — Consists of unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access as of the reporting date.

• Level 2 — Consists of inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

• Level 3 — Consists of unobservable inputs for assets or liabilities whose fair value is estimated based on internally developed models or methodologies using inputs that are generally less readily observable and supported by little, if any, market activity at the measurement date. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

65

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2011:

	Level 1			Level 2			Level 3			Netting Adjustments (2)			Net Balance at December 31, 2011
	(In millions)
Assets:
Nuclear decommissioning trusts	$	577		$	360		$	—		$	—		$	937
Other investments (1)	57			54			—			—			111
Derivative assets:
Foreign currency exchange contracts	—			3			—			(3		)	—
Commodity Contracts:
Natural Gas	1,926			78			20			(1,991		)	33
Electricity	—			523			224			(490		)	257
Other	23			2			6			(25		)	6
Total derivative assets	1,949			606			250			(2,509		)	296
Total	$	2,583		$	1,020		$	250		$	(2,509	)	$	1,344
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(5	)	$	—		$	3		$	(2	)
Interest rate contracts	—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(1,940		)	(126		)	(14		)	1,976			(104		)
Electricity	—			(513		)	(192		)	565			(140		)
Other	(19		)	(1		)	—			20			—
Total derivative liabilities	(1,959		)	(646		)	(206		)	2,564			(247		)
Total	$	(1,959	)	$	(646	)	$	(206	)	$	2,564		$	(247	)
Net Assets as of December 31, 2011	$	624		$	374		$	44		$	55		$	1,097
Assets:
Current	$	1,571		$	520		$	181		$	(2,050	)	$	222
Noncurrent (3)	1,012			500			69			(459		)	1,122
Total Assets	$	2,583		$	1,020		$	250		$	(2,509	)	$	1,344
Liabilities:
Current	$	(1,603	)	$	(527	)	$	(152	)	$	2,124		$	(158	)
Noncurrent	(356		)	(119		)	(54		)	440			(89		)
Total Liabilities	$	(1,959	)	$	(646	)	$	(206	)	$	2,564		$	(247	)
Net Assets as of December 31, 2011	$	624		$	374		$	44		$	55		$	1,097

66

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2010:

	Level 1			Level 2			Level 3			Netting Adjustments (2)			Net Balance at December 31, 2010
	(In millions)
Assets:
Nuclear decommissioning trusts	$	599		$	340		$	—		$	—		$	939
Other investments (1)	56			55			—			—			111
Derivative assets:
Foreign currency exchange contracts	—			20			—			(20		)	—
Commodity Contracts:
Natural Gas	1,846			128			12			(1,960		)	26
Electricity	—			649			117			(589		)	177
Other	68			4			4			(71		)	5
Total derivative assets	1,914			801			133			(2,640		)	208
Total	$	2,569		$	1,196		$	133		$	(2,640	)	$	1,258
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(30	)	$	—		$	20		$	(10	)
Interest rate contracts	—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(1,844		)	(263		)	(11		)	1,955			(163		)
Electricity	—			(653		)	(63		)	643			(73		)
Other	(63		)	(8		)	—			66			(5		)
Total derivative liabilities	(1,907		)	(955		)	(74		)	2,684			(252		)
Total	$	(1,907	)	$	(955	)	$	(74	)	$	2,684		$	(252	)
Net Assets as of December 31, 2010	$	662		$	241		$	59		$	44		$	1,006
Assets:
Current	$	1,299		$	663		$	49		$	(1,880	)	$	131
Noncurrent (3)	1,270			533			84			(760		)	1,127
Total Assets	$	2,569		$	1,196		$	133		$	(2,640	)	$	1,258
Liabilities:
Current	$	(1,290	)	$	(730	)	$	(21	)	$	1,899		$	(142	)
Noncurrent	(617		)	(225		)	(53		)	785			(110		)
Total Liabilities	$	(1,907	)	$	(955	)	$	(74	)	$	2,684		$	(252	)
Net Assets as of December 31, 2010	$	662		$	241		$	59		$	44		$	1,006

(1) Excludes cash surrender value of life insurance investments.

(2) Amounts represent the impact of master netting agreements that allow the Company to net gain and loss positions and cash collateral held or placed with the same counterparties.

(3) Includes $111 million of other investments that are included in the Consolidated Statements of Financial Position in Other Investments at December 31, 2011 and December 31, 2010.

67

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2011 and 2010:

	Year Ended December 31, 2011
	Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets as of January 1, 2011	$	1		$	54		$	4		$	59
Transfers into Level 3	—			4			—			4
Transfers out of Level 3	1			(25		)	—			(24		)
Total gains:
Included in earnings	7			77			3			87
Recorded in regulatory assets/liabilities	—			—			2			2
Purchases, issuances and settlements:
Purchases	—			3			—			3
Settlements	(3		)	(81		)	(3		)	(87		)
Net Assets as of December 31, 2011	$	6		$	32		$	6		$	44
The amount of total gains included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at December 31, 2011	$	8		$	65		$	2		$	75

	Year Ended December 31, 2010
	Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets as of January 1, 2010	$	2		$	19		$	3		$	24
Changes in fair value included in earnings	4			64			1			69
Changes in fair value recorded in regulatory assets/liabilities	—			—			6			6
Purchases, issuances and settlements	(8		)	(73		)	(6		)	(87		)
Transfers in/out of Level 3	3			44			—			47
Net Assets as of December 31, 2010	$	1		$	54		$	4		$	59
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at December 31, 2010	$	(4	)	$	(6	)	$	1		$	(9	)

Transfers in/out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level and for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. Transfers in and transfers out of Level 3 are reflected as if they had occurred at the beginning of the period. For the year ended December 31, 2011, $25 million of net assets reflecting inputs related to certain power transactions identified as observable due to available broker quotes were transferred from Level 3 to Level 2, and $4 million of net assets reflecting inputs related to certain power transactions identified as unobservable due to lack of available broker quotes were transferred from Level 2 to Level 3. For the year ended December 31, 2010, $35 million of net liabilities reflecting inputs related to certain power transactions identified as observable due to available broker quotes were transferred from Level 3 to Level 2, and $9 million of net assets reflecting inputs related to certain power transactions identified as unobservable due to lack of available broker quotes were transferred from Level 2 to Level 3. No significant transfers between Levels 1 and 2 occurred in years ended December 31, 2011 and December 31, 2010.

68

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Nuclear Decommissioning Trusts and Other Investments

The nuclear decommissioning trusts and other investments hold debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices in actively traded markets. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued based on the underlying securities, using quoted prices in actively traded markets. Non-exchange-traded fixed income securities are valued based upon quotations available from brokers or pricing services. A primary price source is identified by asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustees determine that another price source is considered to be preferable. DTE Energy has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, DTE Energy selectively corroborates the fair values of securities by comparison of market-based price sources.

Derivative Assets and Liabilities

Derivative assets and liabilities are comprised of physical and financial derivative contracts, including futures, forwards, options and swaps that are both exchange-traded and over-the-counter traded contracts. Various inputs are used to value derivatives depending on the type of contract and availability of market data. Exchange-traded derivative contracts are valued using quoted prices in active markets. DTE Energy considers the following criteria in determining whether a market is considered active: frequency in which pricing information is updated, variability in pricing between sources or over time and the availability of public information. Other derivative contracts are valued based upon a variety of inputs including commodity market prices, broker quotes, interest rates, credit ratings, default rates, market-based seasonality and basis differential factors. DTE Energy monitors the prices that are supplied by brokers and pricing services and may use a supplemental price source or change the primary price source of an index if prices become unavailable or another price source is determined to be more representative of fair value. DTE Energy has obtained an understanding of how these prices are derived. Additionally, DTE Energy selectively corroborates the fair value of its transactions by comparison of market-based price sources. Mathematical valuation models are used for derivatives for which external market data is not readily observable, such as contracts which extend beyond the actively traded reporting period.

Fair Value of Financial Instruments

The fair value of long-term debt is determined by using quoted market prices when available and a discounted cash flow analysis based upon estimated current borrowing rates when quoted market prices are not available. The table below shows the fair value and the carrying value for long-term debt securities. Certain other financial instruments, such as notes payable, customer deposits and notes receivable are not shown as carrying value approximates fair value. See Note 4 for further fair value information on financial and derivative instruments.

	December 31, 2011						December 31, 2010
	Fair Value			Carrying Value			Fair Value			Carrying Value
Long-Term Debt	$	8.8	billion	$	7.7	billion	$	8.5	billion	$	8.0	billion

Nuclear Decommissioning Trust Funds

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 Consolidated Statements of Financial Position. 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. See Note 8.

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

	December 31 2011		December 31 2010
	(In millions)
Fermi 2	$	915	$	910
Fermi 1	3		3
Low level radioactive waste	19		26
Total	$	937	$	939

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DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

At December 31, 2011, investments in the nuclear decommissioning trust funds consisted of approximately 57% in publicly traded equity securities, 41% in fixed debt instruments and 2% in cash equivalents. At December 31, 2010, investments in the nuclear decommissioning trust funds consisted of approximately 61% in publicly traded equity securities, 38% in fixed debt instruments and 1% in cash equivalents. The debt securities at both December 31, 2011 and December 31, 2010 had an average maturity of approximately 7 and 6 years, respectively.

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
	2011			2010			2009
	(In millions)
Realized gains	$	46		$	192		$	37
Realized losses	$	(38	)	$	(83	)	$	(55	)
Proceeds from sales of securities	$	80		$	377		$	295

Realized gains and losses from the sale of securities for the Fermi 2 and the low level radioactive waste funds are recorded to the Regulatory asset and Nuclear decommissioning liability. The following table sets forth the fair value and unrealized gains for the nuclear decommissioning trust funds:

	Fair Value		Unrealized Gains
	(In millions)
As of December 31, 2011
Equity securities	$	533	$	80
Debt securities	385		22
Cash and cash equivalents	19		—
	$	937	$	102
As of December 31, 2010
Equity securities	$	572	$	77
Debt securities	361		11
Cash and cash equivalents	6		—
	$	939	$	88

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.

Unrealized losses incurred by the Fermi 2 trust are recognized as a Regulatory asset. Detroit Edison recognized $67 million and $26 million of unrealized losses as Regulatory assets at December 31, 2011 and 2010, 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, unrealized losses incurred by the Fermi 1 trust are recognized in earnings immediately. There were no unrealized losses recognized in 2011, 2010 and 2009 for Fermi 1.

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DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Other Available- For- Sale Securities

The following table summarizes the fair value of the Company’s investment in available-for-sale debt and equity securities, excluding nuclear decommissioning trust fund assets:

	December 31, 2011				December 31, 2010
(In millions)	Fair Value		Carrying value		Fair Value		Carrying Value
Cash equivalents	$	140	$	140	$	133	$	133
Equity securities	$	5	$	5	$	6	$	6

At December 31, 2011 and 2010, these securities are comprised primarily of money-market and equity securities. During the year ended December 31, 2011 and December 31, 2010no amounts of unrealized losses on available for sale securities were reclassified out of other comprehensive income into losses for the periods. Gains related to trading securities held at December 31, 2011, 2010, and 2009 were $3 million, $7 million and $8 million, respectively.

NOTE 4 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

The Company recognizes all derivatives at their fair value as Derivative Assets or Liabilities on the Consolidated Statements of Financial Position unless they qualify for certain scope exceptions, including the 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 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 the derivative 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 exchange. The Company has risk management policies to monitor and manage 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 Power and Industrial Projects segment. Contracts classified as derivative instruments include power, gas, oil and certain coal forwards, futures, options and swaps, and foreign currency exchange contracts. Items not classified as derivatives include natural gas inventory, unconventional gas and oil reserves, power transmission, pipeline transportation and certain storage assets.

Electric Utility — 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 contracts 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 settled. This results in the deferral of unrealized gains and losses as Regulatory assets or liabilities until realized.

Gas Utility — MichCon purchases, stores, transports, distributes and sells natural gas and sells storage and transportation capacity. MichCon has fixed-priced contracts for portions of its expected gas supply requirements through 2014. Substantially all of these contracts meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. MichCon may also sell forward transportation and storage capacity contracts. Forward transportation and storage contracts are not derivatives and are therefore accounted for under the accrual method.

Gas Storage and Pipelines — This segment is primarily engaged in services related to the transportation and storage of natural gas. Primarily fixed-priced contracts are used in the marketing and management of transportation and storage services. Generally these contracts are not derivatives and are therefore accounted for under the accrual method.

Unconventional Gas Production — The Unconventional Gas Production business is engaged in unconventional natural gas and oil project development and production. The Company may use derivative contracts to manage changes in the price of natural gas and crude oil.

Power and Industrial Projects — Business units within this segment manage and operate onsite energy and pulverized coal projects, coke batteries, landfill gas recovery and power generation assets. These businesses utilize fixed-priced contracts in the marketing and management of their assets. These contracts are generally not derivatives and are therefore accounted for under the accrual method. The segment also engages in coal marketing which includes the marketing and trading of physical

71

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

coal and coal financial instruments, and forward contracts for the purchase and sale of emission allowances. Certain of these physical and financial coal contracts and contracts for the purchase and sale of emission allowances are derivatives and are accounted for by recording changes in fair value to earnings.

Energy Trading — Commodity Price Risk — Energy Trading markets and trades electricity and natural gas physical products and energy financial instruments, and provides energy and asset 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 unless hedge accounting criteria are met.

Energy Trading — Foreign Currency Exchange Risk — Energy Trading has foreign currency exchange forward contracts to economically hedge fixed Canadian dollar commitments existing under power purchase and sale contracts and gas transportation contracts. The Company enters into these contracts to mitigate price volatility with respect to fluctuations of the Canadian dollar relative to the U.S. dollar. These derivatives are accounted for by recording changes in fair value to earnings unless hedge accounting criteria are met.

Corporate and Other — 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 through 2033. In 2012, the Company estimates reclassifying less than $1 million of losses to earnings.

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, 2011 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to have a material adverse effect on the Company’s financial statements.

Derivative Activities

The Company manages its mark-to-market (MTM) risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, it records and manages the energy purchase and sale obligations under its 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). The following describe the four categories of activities represented by their operating characteristics and key risks:

• Asset Optimization — Represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas production and trades associated with power transmission, gas 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.

• Marketing and Origination — Represents derivative activity transacted by originating substantially hedged positions with wholesale energy marketers, producers, end users, utilities, retail aggregators and alternative energy suppliers.

• Fundamentals Based 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.

• Other — Includes derivative activity at Detroit Edison related to FTRs and forward contracts related to emissions. Changes in the value of derivative contracts at Detroit Edison are recorded as Derivative Assets or Liabilities, with an offset to Regulatory Assets or Liabilities as the settlement value of these contracts will be included in the PSCR

72

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

mechanism when realized.

The following tables present the fair value of derivative instruments as of December 31, 2011:

	Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	3	$	(5	)
Commodity Contracts:
Natural Gas	2,024		(2,080		)
Electricity	747		(705		)
Other	31		(20		)
Total derivatives not designated as hedging instruments:	$	2,805	$	(2,810	)
Total derivatives:
Current	$	2,272	$	(2,282	)
Noncurrent	533		(529		)
Total derivatives	$	2,805	$	(2,811	)

	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	2,272		$	533		$	(2,282	)	$	(529	)
Counterparty netting	(2,050		)	(440		)	2,050			440
Collateral adjustment	—			(19		)	74			—
Total derivatives as reported	$	222		$	74		$	(158	)	$	(89	)

The following tables present the fair value of derivative instruments as of December 31, 2010:

	Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	20	$	(30	)
Commodity Contracts:
Natural Gas	1,986		(2,118		)
Electricity	766		(716		)
Other	76		(71		)
Total derivatives not designated as hedging instruments:	$	2,848	$	(2,935	)
Total derivatives:
Current	$	2,011	$	(2,041	)
Noncurrent	837		(895		)
Total derivatives	$	2,848	$	(2,936	)

73

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	2,011		$	837		$	(2,041	)	$	(895	)
Counterparty netting	(1,871		)	(760		)	1,871			760
Collateral adjustment	(9		)	—			28			25
Total derivatives as reported	$	131		$	77		$	(142	)	$	(110	)

The effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for years ended December 31, 2011 and December 31, 2010 is as follows:

	Location of Gain (Loss) Recognized in Income on Derivatives	Gain (Loss) Recognized in Income on Derivatives for Years Ended December 31
Derivatives not Designated as Hedging Instruments		2011			2010
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	(2	)	$	(14	)
Commodity Contracts:
Natural Gas	Operating Revenue	58			61
Natural Gas	Fuel, purchased power and gas	(21		)	(8		)
Electricity	Operating Revenue	115			80
Other	Operating Revenue	9			9
Other	Operation and maintenance	—			(5		)
Total		$	159		$	123

The effects of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position were $3 million in gains related to FTRs recognized in Regulatory liabilities for the year ended December 31, 2011, and $1 million in losses related to Emissions recognized in Regulatory assets and $6 million in gains related to FTRs recognized in Regulatory liabilities, for the year ended December 31, 2010.

The following represents the cumulative gross volume of derivative contracts outstanding as of December 31, 2011:

Commodity	Number of Units
Natural Gas (MMBtu)	770,624,682
Electricity (MWh)	48,286,149
Foreign Currency Exchange ($ CAD)	34,904,696

Various non-utility subsidiaries of the Company have entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade. Certain of these provisions (known as “hard triggers”) state specific circumstances under which the Company can be asked to post collateral upon the occurrence of a credit downgrade, while other provisions (known as “soft triggers”) are not as specific. For contracts with soft triggers, it is difficult to estimate the amount of collateral which may be requested by counterparties and/or which the Company may ultimately be required to post. The amount of such collateral which could be requested fluctuates based on commodity prices (primarily gas, power and coal) and the provisions and maturities of the underlying transactions. As of December 31, 2011, the value of the transactions for which the Company would have been exposed to collateral requests had DTE Energy’s credit rating been below investment grade on such date under both hard trigger and soft trigger provisions was approximately $315 million. In circumstances where an entity is downgraded below investment grade and collateral requests are made as a result, the requesting parties often agree to accept less than the full amount of their exposure to the downgraded entity.

74

NOTE 5 — 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, 2011and December 31, 2010 is as follows:

	2011		2010
	(In millions)
Balance as of January 1	$	2,020	$	2,024
Goodwill attributable to sale of subsidiary in Power and Industrial Projects segment	—		(4		)
Balance at December 31	$	2,020	$	2,020

In September 2011, the FASB issued ASU No. 2011-08, Intangibles-Goodwill and Other (Topic 350)—Testing Goodwill for Impairment, which is intended to simplify how entities test for goodwill impairment by permitting an entity the option of performing a qualitative assessment to determine whether further impairment testing is necessary. The standard will be effective for annual and interim goodwill impairments tests for fiscal years beginning after December 15, 2011. The adoption of ASU 2011-08 is not expected to have a material impact to the Company's financial statements.

NOTE 6 — PROPERTY, PLANT AND EQUIPMENT

Summary of property by classification as of December 31:

	2011			2010
	(In millions)
Property, Plant and Equipment
Electric Utility
Generation	$	9,785		$	9,268
Distribution	7,003			6,800
Total Electric Utility	16,788			16,068
Gas Utility
Distribution	2,561			2,460
Storage	406			395
Other	902			991
Total Gas Utility	3,869			3,846
Non-utility and other	1,884			1,660
Total	22,541			21,574
Less Accumulated Depreciation, Depletion and Amortization
Electric Utility
Generation	(3,946		)	(3,850		)
Distribution	(2,580		)	(2,568		)
Total Electric Utility	(6,526		)	(6,418		)
Gas Utility
Distribution	(1,041		)	(1,019		)
Storage	(127		)	(108		)
Other	(413		)	(512		)
Total Gas Utility	(1,581		)	(1,639		)
Non-utility and other	(688		)	(525		)
Total	(8,795		)	(8,582		)
Net Property, Plant and Equipment	$	13,746		$	12,992

AFUDC capitalized during 2011 and 2010 was approximately $10 million.

75

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The composite depreciation rate for Detroit Edison was approximately 3.3% in 2011, 2010 and 2009. The composite depreciation rate for MichCon was 2.3% in 2011, 2.5% in 2010 and 3.1% in 2009.

The average estimated useful life for each major class of utility property, plant and equipment as of December 31, 2011 follows:

	Estimated Useful Lives in Years
Utility	Generation	Distribution	Transmission
Electric	46	43	N/A
Gas	N/A	62	61

The estimated useful lives for major classes of non-utility assets and facilities ranges from 3 to 55 years.

Capitalized software costs are classified as Property, plant and equipment and the related amortization is included in Accumulated depreciation, depletion and amortization 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 capitalized software costs on a straight-line basis over the expected period of benefit, ranging from 3 to 20 years.

Capitalized software costs amortization expense was $65 million in 2011 and 2010 and $66 million in 2009. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2011 were $623 million and $300 million, respectively. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2010 were $602 million and $252 million, respectively. Amortization expense of capitalized software costs is estimated to be approximately $64 million annually for 2012 through 2016.

Gross property under capital leases was $57 million and $153 million at December 31, 2011 and December 31, 2010, respectively. Accumulated amortization of property under capital leases was $34 million and $114 million at December 31, 2011 and December 31, 2010, respectively.

NOTE 7 — JOINTLY OWNED UTILITY PLANT

Detroit Edison has joint ownership interest in two power plants, Belle River and Ludington Hydroelectric Pumped Storage. Detroit Edison’s share of direct expenses of the jointly owned plants are included in Fuel, purchased power and gas and Operation and maintenance expenses in the Consolidated Statements of Operations. Ownership information of the two utility plants as of December 31, 2011 was as follows:

	Belle River			Ludington Hydroelectric Pumped Storage
In-service date	1984-1985			1973
Total plant capacity	1,270		MW	1,872		MW
Ownership interest	*			49		%
Investment (in millions)	$	1,645		$	199
Accumulated depreciation (in millions)	$	943		$	158

_______________________________________

* 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.

76

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 8 — ASSET RETIREMENT OBLIGATIONS

The Company has a legal retirement obligation for the decommissioning costs for its Fermi 1 and Fermi 2 nuclear plants, gas production facilities, gas gathering facilities and various other operations. The Company has conditional retirement obligations for gas pipelines, asbestos at certain of its power plants, 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 when they are incurred, which generally is 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. In its regulated operations, the Company recognizes regulatory assets or liabilities for timing differences in expense recognition for legal asset retirement costs that are currently recovered in rates.

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 2011 follows:

	(In millions)
Asset retirement obligations at January 1, 2011	$	1,514
Accretion	93
Liabilities incurred	10
Liabilities settled	(23		)
Revision in estimated cash flows	(1		)
Asset retirement obligations at December 31, 2011	1,593
Less amount included in current liabilities	(2		)
	$	1,591

In 2001, Detroit Edison began the final decommissioning of Fermi 1, with the goal of removing the remaining radioactive material and terminating the Fermi 1 license. In 2011, based on management decisions revising the timing and estimate of cash flows, Detroit Edison accrued an additional $19 million with respect to the decommissioning of Fermi 1. Management intends to suspend decommissioning activities and place the facility in safe storage status. The expense amount has been recorded in Asset (gains) and losses, reserves and impairments, net on the Consolidated Statements of Operations. In addition, based on updated studies revising the timing and estimate of cash flows, a reduction of approximately $20 million was made to the Detroit Edison asset retirement obligation for asbestos removal with approximately $6 million of the decrease associated with Fermi 1 recorded in Asset (gains) and losses, reserves and impairments, net on the Consolidated Statements of Operations.

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 Consolidated Statements of Financial Position. In October 2011, the MPSC approved Detroit Edison's request for a reduction to the nuclear decommissioning surcharge under the assumption that it would request an extension of the Fermi 2 license for an additional 20 years beyond the term of the existing license which expires in 2025. Detroit Edison expects to request the license extension in 2014. This proposed extension of the license, including the associated impact on spent nuclear fuel, resulted in a revision in estimated cash flows for the Fermi 2 asset retirement obligation of approximately $22 million. It is estimated that the cost of decommissioning Fermi 2 is $1.4 billion in 2011 dollars and $10 billion in 2045 dollars, using a 6% inflation rate. Approximately $1.4 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.

The NRC has jurisdiction over the decommissioning of nuclear power plants and requires minimum 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

77

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

decommissioning. The decommissioning assets, anticipated earnings thereon and future revenues from decommissioning collections will be used to decommission Fermi 2. The Company expects the liabilities to be reduced to zero at the conclusion of the decommissioning activities. If amounts remain in the trust funds for Fermi 2 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 liability. The decommissioning of Fermi 1 is funded by Detroit Edison. Contributions to the Fermi 1 trust are discretionary. See Note 3 for additional discussion of Nuclear Decommissioning Trust Fund Assets.

NOTE 9 — DISPOSALS

Sale of Rail Services Assets

In 2010, the Company sold certain non-strategic rail services assets for gross proceeds of approximately $23 million. The Company recognized a gain of approximately $5 million, net of a write-off of goodwill of approximately $4 million.

Sale of Gathering and Processing Assets

In 2009, the Company sold certain non-strategic gas gathering and processing assets in northern Michigan for gross proceeds of approximately $45 million, which approximated its carrying value, including goodwill of approximately $13 million.

NOTE 10 — OTHER IMPAIRMENTS AND RESTRUCTURING

Other Impairments — Barnett Shale

Our Unconventional Gas Production segment recorded pre-tax impairment losses of $1 million, $10 million and $6 million in 2011, 2010 and 2009, respectively. The impairments related primarily to the write-off of expired or expiring leasehold positions that the Company does not intend to drill.

Restructuring Costs

In 2005, the Company initiated a company-wide review of its operations called the Performance Excellence Process. The Company incurred CTA restructuring expense. In September 2006, the MPSC issued an order approving a settlement agreement that allowed Detroit Edison and MichCon, commencing in 2006, to defer the incremental CTA. Further, the order provided 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. The recovery of these costs for Detroit Edison was provided for by the MPSC in the order approving the settlement in the show cause proceeding and in the December 23, 2008 MPSC rate order. Detroit Edison amortized deferred CTA costs of $18 million in 2011, 2010 and 2009. The September 2006 order did not provide a regulatory recovery mechanism for MichCon, therefore MichCon expensed CTA incurred during the period 2006 through 2008. The June 2010 MPSC order provided for MichCon’s recovery of the regulatory unamortized balance of CTA. At June 30, 2010, MichCon deferred and recognized in income approximately $32 million ($20 million after-tax) of previously expensed CTA. The non-pension component of CTA of approximately $21 million is included in Regulatory assets. The pension component of CTA of approximately $11 million is included in Regulatory liabilities. MichCon amortized approximately $3 million and $2 million of deferred CTA costs in 2011 and 2010, respectively. Amounts expensed are recorded in Operation and maintenance expense on the Consolidated Statements of Operations. Deferred amounts are recorded in Regulatory assets and Regulatory liabilities on the Consolidated Statements of Financial Position. See Note 11.

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DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 11 — 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. Regulation results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses.

Regulatory Assets and Liabilities

Detroit Edison and MichCon are required to record regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Continued applicability of regulatory accounting treatment 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 discontinuance of this accounting treatment for regulatory assets and liabilities for some or all of our 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 use of regulatory assets and liabilities and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment.

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

	2011			2010
	(In millions)
Assets
Recoverable pension and postretirement costs:
Pension	$	2,208		$	1,742
Postretirement costs	778			624
Asset retirement obligation	420			336
Recoverable Michigan income taxes	324			383
Recoverable income taxes related to securitized regulatory assets	316			400
Choice incentive mechanism	166			105
Accrued PSCR/GCR revenue	147			52
Cost to achieve Performance Excellence Process	116			137
Other recoverable income taxes	81			85
Unamortized loss on reacquired debt	64			65
Recoverable restoration expense	58			19
Deferred environmental costs	49			41
Recoverable uncollectible expense	42			90
Enterprise Business Systems costs	18			21
Recoverable revenue decoupling	18			5
Other	48			53
	4,853			4,158
Less amount included in current assets	(314		)	(100		)
	$	4,539		$	4,058
Securitized regulatory assets	$	577		$	729

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	2011			2010
	(In millions)
Liabilities
Asset removal costs	$	419		$	479
Refundable Michigan income taxes	—			418
Renewable energy	192			125
Refundable revenue decoupling	127			47
Negative pension offset	120			129
Refundable income taxes	66			77
Energy Optimization	34			27
Refundable uncollectible expense	31			—
Accrued PSCR/GCR refund	26			8
Low Income Energy Efficiency Fund	26			—
Fermi 2 refueling outage	23			3
Refundable self implemented rates	1			52
Refundable costs under PA 141	—			33
Refundable restoration expense	—			15
Other	8			9
	1,073			1,422
Less amount included in current liabilities	(54		)	(94		)
	$	1,019		$	1,328

As noted below, regulatory assets for which costs have been incurred have been included (or are expected to be included, for costs incurred subsequent to the most recently approved rate case) in Detroit Edison or MichCon’s rate base, thereby providing a return on invested costs. Certain regulatory assets do not result from cash expenditures and therefore do not represent investments included in rate base or have offsetting liabilities that reduce rate base.

ASSETS

• Recoverable pension and postretirement costs — Accounting rules for pension and other postretirement benefit costs require, among other things, the recognition in other comprehensive income of the actuarial gains or losses and the prior service costs that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Detroit Edison and MichCon record the impact of actuarial gains or losses and prior services costs as a Regulatory asset since the traditional rate setting process allows for the recovery of pension and postretirement costs. The asset will reverse as the deferred items are amortized and recognized as components of net periodic benefit costs. (1)

• Asset retirement obligation — This obligation is primarily for Fermi 2 decommissioning costs. The asset captures the timing differences between expense recognition and current recovery in rates and will reverse over the remaining life of the related plant. (1)

• Recoverable Michigan income taxes— In July 2007, the Michigan Business Tax (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 as the related taxable temporary differences reverse and flow through current income tax expense. In May 2011, the MBT was repealed and the Michigan Corporate Income Tax (MCIT) was enacted. The regulatory asset was remeasured to reflect the impact of the MCIT tax rate. (1)

• 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.

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• Choice incentive mechanism (CIM) — Detroit Edison receivable for non-fuel revenues lost as a result of fluctuations in electric Customer Choice sales. The CIM was terminated in the October 20, 2011 MPSC order issued to Detroit Edison.

• 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.

• 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 are amortized over a ten-year period beginning with the year subsequent to the year the costs were deferred.

• Other recoverable income taxes — Income taxes receivable from Detroit Edison’s customers representing the difference in property-related deferred income taxes and amounts previously reflected in Detroit Edison’s rates. This asset will reverse over the remaining life of the related plant. (1)

• 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.

• Recoverable restoration expense — Receivable for the MPSC approved restoration expense tracking mechanism that tracks the difference between actual restoration expense and the amount provided for in base rates, recognized pursuant to the MPSC authorization. The restoration expense tracking mechanism was terminated in the October 20, 2011 MPSC order issued to Detroit Edison.

• Deferred environmental costs — The MPSC approved the deferral of investigation and remediation costs associated with Gas Utility’s former MGP sites. Amortization of deferred costs is over a ten-year period beginning in the year after costs were incurred, with recovery (net of any insurance proceeds) through base rate filings.

• Recoverable uncollectible expense (UETM) — Detroit Edison and MichCon receivable for the MPSC approved uncollectible expense tracking mechanism that tracks the difference in the fluctuation in uncollectible accounts and amounts recognized pursuant to the MPSC authorization. The UETM was terminated in the October 20, 2011 MPSC order issued to Detroit Edison.

• Enterprise Business Systems (EBS) costs — The MPSC approved the deferral and amortization over 10 years beginning in January 2009 of EBS costs that would otherwise be expensed.

• Recoverable revenue decoupling — Amounts recoverable from Detroit Edison customers for the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established by the MPSC. Amounts recoverable from MichCon customers for the change in revenue resulting from the difference in weather-adjusted average sales per customer compared to the base level of average sales per customer established by the MPSC.

• 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.

_______________________________________

(1) Regulatory assets not earning a return.

LIABILITIES

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

• Refundable Michigan income taxes — 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

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impacts of the deferred tax assets will be reflected in rates. In May 2011, the MBT was repealed and the MCIT was enacted. The state deferred tax assets were eliminated under the MCIT and related regulatory liabilities were remeasured to zero.

• Renewable energy — Amounts collected in rates in excess of renewable energy expenditures.

• Refundable revenue decoupling — Amounts refundable to Detroit Edison customers for the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established by the MPSC. Amounts refundable to MichCon customers for the change in revenue resulting from the difference in weather-adjusted average sales per customer compared to the base level of average sales per customer established by the MPSC.

• Negative pension offset — MichCon’s negative pension costs are not included as a reduction to its authorized rates; therefore, the Company is accruing a regulatory liability to eliminate the impact on earnings of the negative pension expense accrued. This regulatory liability will reverse to the extent MichCon’s pension expense is positive in future years.

• 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.

• Energy Optimization (EO) - The EO plan application is designed to help each customer class reduce their electric usage by: 1) building customer awareness of energy efficiency options and 2) offering a diverse set of programs and participation options that result in energy savings for each customer class.

• Refundable uncollectible expense (UETM )— Detroit Edison and MichCon liability for the MPSC approved uncollectible expense tracking mechanism that tracks the difference in the fluctuation in uncollectible accounts and amounts recognized pursuant to the MPSC authorization. The UETM was terminated in the October 20, 2011 MPSC order issued to Detroit Edison.

• Accrued PSCR refund — Liability 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.

• Low Income Energy Efficiency Fund (LIEEF) — Escrow of LIEEF funds collected by Detroit Edison and MichCon as ordered by the MPSC pursuant to July 2011 Michigan Court of Appeals decision.

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

• Refundable self implemented rates — Amounts refundable to customers for base rates implemented by Detroit Edison and MichCon in excess of amounts authorized in MPSC orders.

• Refundable costs under PA 141 — Detroit Edison’s 2007 CIM reconciliation and allocation resulted in the elimination of Regulatory Asset Recovery Surcharge (RARS) balances for commercial and industrial customers. RARS revenues received that exceed the regulatory asset balances are required to be refunded to the affected classes.

• Refundable restoration expense — Amounts refundable for the MPSC approved restoration expense tracking mechanism that tracks the difference between actual restoration expense and the amount provided for in base rates, recognized pursuant to the MPSC authorization. The restoration expense tracking mechanism was terminated in the October 20, 2011 MPSC order issued to Detroit Edison.

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2010 Electric Rate Case Filing

On October 20, 2011, the MPSC issued an order in Detroit Edison's October 29, 2010 rate case filing. The MPSC approved an annual revenue increase of $175 million. Included in the approved increase in revenues was a return on equity of 10.5% on an expected permanent capital structure of 49% equity and 51% debt. Detroit Edison self-implemented a rate increase of $107 million on April 28, 2011. The MPSC stated the net revenue collected due to self-implementation be credited to the 2011 Choice Incentive Mechanism (CIM) regulatory asset, but the order did not define "net revenue." The Company credited the CIM Regulatory Asset for its estimate of the net revenue from self-implementation of approximately $37 million. In November 2011, Detroit Edison petitioned the MPSC for a rehearing and clarification of several issues in the October 2011 MPSC order. On December 20, 2011, the MPSC issued a rehearing order on selected issues, revising the annual revenue increase to $188 million. The rehearing order also affirmed the MPSC's decision to terminate the uncollectible expense tracker mechanism, but deferred ruling on other matters included in Detroit Edison's petition.

Other key aspects of the October 20, 2011 MPSC order include the following:

• adopt a new Revenue Decoupling Mechanism (RDM) effective April 1, 2012, that will compare actual revenue (excluding the impacts of weather) by rate class with the base established in this rate case. The RDM has an annual collar of 1.5% in the first year and 3% in the second and subsequent years. The RDM established in the previous rate case, which considered the impact of weather, was terminated effective October 31, 2011. Therefore, there will be no RDM in place from November 2011 through March 2012;

• recognition of the expiration of a wholesale contract. Since the expiration of the wholesale contract was not until December 31, 2011, the MPSC required Detroit Edison to calculate a customer credit for each kWh sold under the wholesale contract from October 29, 2011 through December 31, 2011, with the credit to be applied in its next PSCR reconciliation;

• the Restoration Expense Tracking Mechanism, Line Clearance Recovery Mechanism, Uncollectible Expense Tracking Mechanism and CIM are terminated as of the date of the order;

• due to uncertainty resulting from the Michigan Court of Appeals overturning collection of the Low Income Energy Efficiency Fund (LIEEF), the MPSC required the continued collection of LIEEF amounts in base rates and placement into escrow pending further orders by the MPSC;

• approval of Detroit Edison's proposal to reduce the Nuclear Decommissioning Surcharge by approximately $20 million annually; and

• implementation of lower depreciation rates previously approved in a June 2011 MPSC order.

2009 Detroit Edison Depreciation Filing

In compliance with an MPSC order, Detroit Edison filed a depreciation case in November 2009. On June 16, 2011, the MPSC issued an order reducing Detroit Edison's composite depreciation rates from 3.33% to 3.06%, effective for accounting and ratemaking purposes, the day after the issuance of the MPSC order in the 2010 rate case.

Renewable Energy Plan (REP)

In August 2010, Detroit Edison filed its reconciliation for the 2009 plan year indicating that the 2009 actual renewable plan revenues and costs approximated the related surcharge revenues and cost of the filed plan. An MPSC order is expected in the first quarter of 2012.

In June 2011, Detroit Edison filed an amended REP with the MPSC requesting authority to continue to recover approximately $100 million of surcharge revenues. The proposed revenues are necessary in order to continue to properly implement Detroit Edison's 20-year REP, to deliver cleaner, renewable electric generation to its customers, to further diversify Detroit Edison's and the State of Michigan's sources of electric supply, and to address the state and national goals of increasing energy independence. On December 20, 2011, the MPSC issued an order approving the amended REP and authorizing the continuation of the surcharges.

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In August 2011, Detroit Edison filed its reconciliation for the 2010 plan year indicating that the 2010 actual renewable plan revenues and costs approximated the related surcharge revenues and cost of the filed plan. An MPSC order is expected in the third quarter of 2012.

Energy Optimization (EO) Plans

In April 2011, Detroit Edison and MichCon filed separate applications for approval of their respective reconciliations of their 2010 EO plan expenses. Specifically, Detroit Edison's EO reconciliation includes a cumulative $21 million net over-recovery at year end 2010 for the 2010 EO plan. MichCon's EO reconciliation includes a cumulative $5.6 million net over-recovery at year end 2010 for the 2010 EO plan. In November 2011, the MPSC approved settlement agreements for Detroit Edison and MichCon which authorized the over-recovery balances be included in the 2011 reconciliations.

In September 2011, Detroit Edison and MichCon filed biennial EO Plans with the MPSC as required. Detroit Edison's EO Plan application proposed the recovery of EO expenditures for the period 2012-2015 of $294 million and further requested approval of surcharges to recover these costs. MichCon's EO Plan application proposed the recovery of EO expenditures for the period 2012-2015 of $103 million and further requested approval of surcharges to recover these costs.

Detroit Edison Restoration Expense Tracker Mechanism (RETM) and Line Clearance Tracker (LCT) Reconciliation

In March 2010, Detroit Edison filed an application with the MPSC for approval of the reconciliation of its 2009 RETM and LCT. The Company's 2009 restoration and line clearance expenses were less than the amount provided in rates. Accordingly, Detroit Edison proposed a refund of approximately $16 million, including interest. On May 10, 2011, the MPSC issued an order approving the proposed refund and Detroit Edison began applying credits to customer bills in July 2011.

In March 2011, Detroit Edison filed an application with the MPSC for approval of the reconciliation of its 2010 RETM and LCT. The Company's 2010 restoration expenses were higher than the amount provided in rates. Accordingly, Detroit Edison requested recovery of $19.5 million. In October 2011, the MPSC approved a settlement agreement reconciling the RETM and approving the LCT report. The MPSC authorized surcharges to recover $19.5 million over a three-month period beginning November 1, 2011.

In January 2012, Detroit Edison filed an application with the MPSC for approval of the reconciliation of its 2011 RETM and LCT. The Company's 2011 restoration expenses were higher than the amount provided in rates. Accordingly, Detroit Edison requested net recovery of approximately $44 million.

Detroit Edison Revenue Decoupling Mechanism (RDM)

In May 2011, Detroit Edison filed an application with the MPSC for approval of its initial pilot RDM reconciliation for the period February 2010 through January 2011, requesting authority to refund to customers approximately $56 million, plus interest. This amount was accrued by Detroit Edison at December 31, 2011. There are various interpretations and alternative calculation methodologies relating to the pilot RDM refund calculation that could ultimately be adopted by the MPSC which may result in a range of customer refund amounts from $56 million to $140 million for this initial reconciliation filing under the pilot RDM.

In addition, Detroit Edison has accrued a pilot RDM liability for February 2011 through October 2011 of approximately $71 million, plus interest. Detroit Edison terminated the pilot RDM effective October 2011, and has requested a rehearing on this issue asserting that for reconciliation purposes, the pilot RDM should have been considered terminated in April 2011, when the Detroit Edison self-implemented rates, consistent with prior MPSC orders. An April 2011 termination would result in a decrease to the liability. However, there can be no assurance that Detroit Edison will prevail in this matter. Similar to the initial reconciliation case, there are various interpretations and alternative calculation methodologies that could be adopted which may result in a range of refund obligations in excess of the amount accrued. Considering these variables, the potential customer refund amount could range from $10 million to $130 million for the second and final pilot RDM period.

The primary uncertainties involved in the calculation methodologies of the pilot RDM for both reconciliation periods include customer class groupings and treatment of fixed customer charges. The Company believes that the calculation methodology used and the resulting refund estimates recorded follow the requirements and intent of the MPSC orders and represent the most probable amount of Detroit Edison's pilot RDM refund liability as of December 31, 2011. An MPSC order on the initial filing is expected in the first half of 2012. Detroit Edison is required to file an application with the MPSC for

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approval of its RDM reconciliation for the period February 2011 through October 2011 by May 2012. A newly designed RDM will be in effect beginning April 2012.

Detroit Edison Uncollectible Expense True-Up Mechanism (UETM)

In March 2011, Detroit Edison filed an application with the MPSC for approval of its UETM for 2010 requesting authority to refund approximately $7 million consisting of costs related to 2010 uncollectible expense. In August 2011, the MPSC approved a settlement agreement for the 2010 UETM authorizing a refund of approximately $7 million to be applied as credits to customer bills beginning September 1, 2011.

Detroit Edison Choice Incentive Mechanism (CIM)

In March 2011, Detroit Edison filed an application with the MPSC for approval of its CIM reconciliation for 2010 requesting recovery of approximately $105 million. On December 6, 2011, the MPSC approved a settlement agreement for the 2010 CIM authorizing surcharges of approximately $105 million effective on a service rendered basis for the 12-month period beginning January 1, 2012.

On January 17, 2012, Detroit Edison filed an application with the MPSC for approval of its CIM reconciliation for the period from January 1, 2011 through October 28, 2011. The termination date of the CIM pursuant to the October 20, 2011 MPSC rate order is October 20, 2011. Detroit Edison requested recovery of approximately $73 million, net of the self implementation credit applied per MPSC order.

Power Supply Cost Recovery Proceedings

The PSCR process is designed to allow Detroit Edison to recover all of its power supply costs if incurred under reasonable and prudent policies and practices. Detroit Edison's power supply costs include fuel and related transportation costs, purchased and net interchange power costs, nitrogen oxide and sulfur dioxide emission allowances costs, urea costs, transmission costs and MISO costs. The MPSC reviews these costs, policies and practices for prudence in annual plan and reconciliation filings.

2010 PSCR Year - In March 2011, Detroit Edison filed the 2010 PSCR reconciliation calculating a net under-recovery of $52.6 million that includes an over-recovery of $15.6 million for the 2009 PSCR year. In addition, the 2010 PSCR reconciliation includes an under-recovery of $7.1 million for the reconciliation of the 2007-2008 Pension Equalization Mechanism, and an over-refund of $3.8 million for the 2011 refund of the self-implemented rate increase related to the 2009 electric rate case filing.

2011 Plan Year - In September 2010, Detroit Edison filed its 2011 PSCR plan case seeking approval of a levelized PSCR factor of 2.98 mills/kWh below the amount included in base rates for all PSCR customers. The filing supports a total power supply expense forecast of $1.2 billion. The plan also includes approximately $36 million for the recovery of its projected 2010 PSCR under-recovery. An MPSC order was issued on December 6, 2011 approving the 2011 PSCR.

2012 Plan Year - In September 2011, Detroit Edison filed its 2012 PSCR plan case seeking approval of a levelized PSCR factor of 4.18 mills/kWh above the amount included in base rates for all PSCR customers. The filing supports a total power supply expense forecast of $1.4 billion. The plan also includes approximately $158 million for the recovery of its projected 2011 PSCR under-recovery.

Low Income Energy Efficiency Fund

The Customer Choice and Electricity Reliability Act of 2000 authorized the creation of the LIEEF administered by the MPSC. The purpose of the fund is to provide shut-off and other protection for low income customers and to promote energy efficiency by all customer classes. Detroit Edison and MichCon collect funding for the LIEEF as part of their base rates and remit the funds to the State of Michigan monthly. In July 2011, the Michigan Court of Appeals issued a decision reversing the portion of MichCon's June 2010 MPSC rate order that permitted MichCon to recover funding for the LIEEF in base rates. In response to the Court of Appeals decision, Detroit Edison and MichCon ceased remitting payments for LIEEF funding to the State of Michigan. In October 2011, the MPSC issued orders directing Detroit Edison and MichCon to continue collecting funds for LIEEF in rates and to escrow the collected funds pending further order by the MPSC. On January 26, 2012, the MPSC issued an order directing Detroit Edison and MichCon to file comprehensive plans by March 1, 2012 for refunding

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previously escrowed LIEEF funds of $23 million and $3 million, respectively. On December 20, 2011, The Vulnerable Household Warmth Fund (VHWF) was created under Michigan law. The purpose of the fund is to provide payment or partial payment of bills for electricity, natural gas, propane, heating oil, or any other type of fuel used to heat the primary residence of a vulnerable customer during the 2011-2012 heating season. Effective with the new law, Detroit Edison and MichCon are to contribute the amounts collected in their base rates, previously remitted for the LIEEF, to the new VHWF. The monthly payments into the VHWF will cease on the earlier of September 30, 2012 or when $48 million has been is accumulated in the fund from payments by major Michigan electric and gas utilities.

MichCon UETM

In March 2011, MichCon filed an application with the MPSC for approval of its UETM for 2010 requesting recovery of approximately $31 million, consisting of $7 million related to 2010 uncollectible expense and $24 million related to the 2008 UETM under-collection. In September 2011, the MPSC approved a settlement agreement approving the 2010 UETM and the implementation of a surcharge beginning October 1, 2011.

MichCon Revenue Decoupling Mechanism (RDM)

In September 2011, MichCon filed an application with the MPSC for approval of its RDM reconciliation for the period July 1, 2010 through June 30, 2011. MichCon's RDM application proposed the recovery of approximately $20 million.

Gas Cost Recovery Proceedings

The GCR process is designed to allow MichCon to recover all of its gas supply costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs, policies and practices for prudence in annual plan and reconciliation filings.

2009-2010 GCR Year - An MPSC order was issued on December 6, 2011 for the GCR reconciliation for the 12-month period ended March 31, 2010 disallowing recovery of $3.3 million related to the pricing of certain gas purchases from an affiliate. The MPSC also authorized MichCon to include in its 2010-2011 GCR reconciliation beginning balance the net overrecovery of approximately $9 million.

2010-2011 Plan Year - In June 2011, MichCon filed its 2010-2011 GCR plan year reconciliation case calculating a net over-recovery of $1 million, including interest. This over-recovery does not reflect the December 6, 2011 MPSC order on the 2009-2010 plan year reconciliation case.

2011-2012 Plan Year - In December 2010, MichCon filed its GCR plan case for the 2011-2012 GCR plan year. MichCon filed for a maximum base GCR factor of $5.89 per Mcf adjustable monthly by a contingency factor.

2012-2013 Plan Year - In December 2011, MichCon filed its GCR plan case for the 2012-2013 GCR plan year. MichCon filed for a maximum base GCR factor of $5.18 per Mcf adjustable monthly by a contingency factor.

Gas Main Renewal and Gas Meter Move Out Programs

The June 3, 2010 MPSC gas rate case order required MichCon to make filings related to gas main renewal and meter move-out programs. In a July 30, 2010 filing, MichCon proposed to implement a 10-year gas main renewal program beginning in 2012 which would require capital expenditures of approximately $17 million per year for renewing gas distribution mains, retiring gas mains, and where appropriate and when related to the gas main renewal or retirement activity, relocate inside meters to outside locations and renew service lines. In a September 30, 2010 filing, MichCon proposed to implement a 10-year gas meter move out program beginning in 2012 which would require capital expenditures of approximately $22 million per year primarily for relocation of inside meters to the outside of residents' houses. In September 2011, the MPSC issued orders approving both programs and requested MichCon to include the recovery of costs associated with these two programs in future MichCon rate cases.

Other

The Company is unable to predict the outcome of the unresolved 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.

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NOTE 12 — 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:

	2011			2010			2009
	(In millions)
Income before income taxes	$	987		$	950		$	782
Income tax expense at 35% statutory rate	$	345		$	333		$	274
Production tax credits	(6		)	(33		)	(12		)
Investment tax credits	(6		)	(6		)	(7		)
Depreciation	(4		)	(4		)	(4		)
Employee Stock Ownership Plan dividends	(4		)	(5		)	(5		)
Medicare part D subsidy	—			—			(6		)
Domestic production activities deduction	(7		)	(7		)	(5		)
Goodwill attributed to the sale of Gas Utility subsidiaries	—			—			4
Settlement of Federal tax audit	—			(12		)	(11		)
State and local income taxes, net of federal benefit	37			44			25
Enactment of Michigan Corporate Income Tax, net of federal expense	(87		)	—			—
Other, net	(1		)	1			(6		)
Income tax expense	$	267		$	311		$	247
Effective income tax rate	27.1		%	32.7		%	31.6		%

Components of income tax expense were as follows:

	2011			2010			2009
	(In millions)
Current income tax expense (benefit)
Federal	$	25		$	(172	)	$	25
State and other income tax	22			26			17
Total current income taxes	47			(146		)	42
Deferred income tax expense (benefit)
Federal	318			415			182
State and other income tax	(98		)	42			23
Total deferred income taxes	220			457			205
Total	$	267		$	311		$	247

Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in the financial statements. Deferred tax assets and liabilities are classified as current or noncurrent according to the classification of the related assets or liabilities. Deferred tax assets and liabilities not related to assets or liabilities are classified according to the expected reversal date of the temporary differences. Consistent with rate making treatment, deferred taxes are offset in the table below for temporary differences which have related regulatory assets and liabilities.

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Deferred tax assets (liabilities) were comprised of the following at December 31:

	2011			2010
	(In millions)
Property, plant and equipment	$	(3,131	)	$	(2,558	)
Securitized regulatory assets	(360		)	(396		)
Alternative minimum tax credit carry-forwards	294			337
Merger basis differences	50			49
Pension and benefits	(39		)	(36		)
Other comprehensive income	99			83
Derivative assets and liabilities	64			29
State net operating loss and credit carry-forwards	30			33
Other	(45		)	(2		)
	(3,038		)	(2,461		)
Less valuation allowance	(27		)	(32		)
	$	(3,065	)	$	(2,493	)
Current deferred income tax assets	$	51		$	139
Long-term deferred income tax liabilities	(3,116		)	(2,632		)
	$	(3,065	)	$	(2,493	)
Deferred income tax assets	$	1,048		$	1,418
Deferred income tax liabilities	(4,113		)	(3,911		)
	$	(3,065	)	$	(2,493	)

Production tax credits earned in prior years but not utilized totaled $294 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 had 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.

The above table excludes deferred tax liabilities associated with unamortized investment tax credits that are shown separately on the Consolidated Statements of Financial Position. Investment tax credits are deferred and amortized to income over the average life of the related property.

The Company has state deferred tax assets related to net operating loss and credit carry-forwards of $30 million and $33 million at December 31, 2011 and 2010, respectively. The state net operating loss and credit carry-forwards expire from 2012 through 2031. The Company has recorded valuation allowances at December 31, 2011 and 2010 of approximately $27 million and $32 million, respectively, with respect to these deferred tax assets. 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.

88

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Uncertain Tax Positions

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	2011			2010			2009
	(In millions)
Balance at January 1	$	28		$	81		$	72
Additions for tax positions of prior years	27			4			15
Reductions for tax positions of prior years	(4		)	(4		)	(5		)
Additions for tax positions related to the current year	1			—			7
Settlements	(3		)	(53		)	(5		)
Lapse of statute of limitations	(1		)	—			(3		)
Balance at December 31	$	48		$	28		$	81

The Company had $4 million and $5 million of unrecognized tax benefits at December 31, 2011 and at December 31, 2010, respectively, that, if recognized, would favorably impact its effective tax rate. During the next twelve months, it is reasonably possible that the Company will settle certain federal and state tax examinations and audits. As a result, the Company believes that it is possible that there will be a decrease in unrecognized tax benefits of up to $31 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 $2 million and $3 million at December 31, 2011 and December 31, 2010, respectively. The Company had no accrued penalties pertaining to income taxes. The Company recognized interest expense related to income taxes of $(2) million, $1 million and $(2) million in 2011, 2010 and 2009, respectively.

In 2010, the Company settled a federal tax audit for the 2007 and 2008 tax years, which resulted in the recognition of $53 million of unrecognized tax benefits. The Company's federal income tax returns for 2009 and subsequent years remain subject to examination by the IRS. The Company's Michigan Business Tax returns for the year 2008 and subsequent years remain subject to examination by the State of Michigan. The Company also files tax returns in numerous state and local jurisdictions with varying statutes of limitation.

Michigan Corporate Income Tax (MCIT)

On May 25, 2011, the Michigan Business Tax (MBT) was repealed and the MCIT was enacted and became effective January 1, 2012. The MCIT subjects corporations with business activity in Michigan to a 6 percent tax rate on an apportioned income tax base and eliminates the modified gross receipts tax and nearly all credits available under the MBT. The MCIT also eliminated the future deductions allowed under MBT that enabled companies to establish a one-time deferred tax asset upon enactment of the MBT to offset deferred tax liabilities that resulted from enactment of the MBT.

As a result of the enactment of the MCIT, the net state deferred tax liability was remeasured to reflect the impact of the MCIT tax rate on cumulative temporary differences expected to reverse after the effective date. The net impact of this remeasurement was a decrease in deferred income tax liabilities of $36 million attributable to our regulated utilities that was offset against the regulatory asset established upon the enactment of the MBT. Due to the elimination of the future tax deductions allowed under the MBT, the one-time MBT deferred tax asset that was established upon the enactment of the MBT has been remeasured to zero. The net impact of this remeasurement is a reduction of the net deferred tax assets of $308 million, with $395 million of this decrease in deferred tax assets attributable to our regulated utilities, partially offset by an $87 million decrease in deferred tax liabilities attributable to our non-utilities. The $395 million decrease in deferred tax assets at our regulated utilities was offset against the regulatory liabilities established upon enactment of the MBT. The $87 million is primarily due to a lower apportionment factor from inclusion of non-utility entities in DTE Energy's unitary Michigan tax return and was recognized as a reduction to income tax expense in 2011.

Consistent with the original establishment of these deferred tax liabilities (assets), no recognition of these non-cash transactions have been reflected in the Consolidated Statement of Cash Flows.

89

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 13 — COMMON STOCK

Common Stock

In March 2010, the Company contributed $100 million of DTE Energy common stock to the DTE Energy Company Affiliates Employee Benefit Plans Master Trust. The common stock was contributed over four business days from March 26, 2010 through March 31, 2010 and was valued using the closing market prices of DTE Energy common stock on each of those days in accordance with fair value measurement and accounting requirements.

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.

Dividends

Certain of the Company’s credit facilities contain a provision requiring the Company to maintain a total funded debt to capitalization ratio, as defined in the agreements, of no more than 0.65 to 1, which has the effect of limiting the amount of dividends the Company can pay in order to maintain compliance with this provision. See Note 17 for a definition of this ratio. The effect of this provision as of December 31, 2011 and December 31, 2010 was to restrict the payment of approximately $128 million and $46 million, respectively, of total retained earnings of approximately $3.75 billion and $3.4 billion, respectively. There are no other effective limitations with respect to the Company’s ability to pay dividends.

90

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 14 — EARNINGS PER SHARE

The Company reports both basic and diluted earnings per share. The calculation of diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period from the exercise of stock options. A reconciliation of both calculations is presented in the following table as of December 31:

	2011		2010		2009
	(In millions, expect per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	711	$	630	$	532
Average number of common shares outstanding	169		168		164
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	392	$	365	$	347
Dividends declared — net restricted shares	1		2		2
Total distributed earnings	$	393	$	367	$	349
Net income less distributed earnings	$	318	$	263	$	183
Distributed (dividends per common share)	$	2.32	$	2.18	$	2.12
Undistributed	1.87		1.57		1.12
Total Basic Earnings per Common Share	$	4.19	$	3.75	$	3.24
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	711	$	630	$	532
Average number of common shares outstanding	169		168		164
Average incremental shares from assumed exercise of options	1		1		—
Common shares for dilutive calculation	170		169		164
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	392	$	365	$	347
Dividends declared — net restricted shares	1		2		2
Total distributed earnings	$	393	$	367	$	349
Net income less distributed earnings	$	318	$	263	$	183
Distributed (dividends per common share)	$	2.32	$	2.18	$	2.12
Undistributed	1.86		1.56		1.12
Total Diluted Earnings per Common Share	$	4.18	$	3.74	$	3.24

Options to purchase approximately 5 million shares and 4 million shares of common stock in 2010 and 2009, respectively, 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.

91

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 15 — 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:

	2011			2010
	(In millions)
Mortgage bonds, notes, and other
DTE Energy Debt, Unsecured
5.5% due 2013 to 2033	$	1,298		$	1,597
Detroit Edison Taxable Debt, Principally Secured
5.3% due 2012 to 2041	3,515			2,915
Detroit Edison Tax-Exempt Revenue Bonds (2)
5.1% due 2012 to 2038	893			1,283
MichCon Taxable Debt, Principally Secured
6.1% due 2012 to 2033	889			889
Other Long-Term Debt, Including Non-Recourse Debt	165			195
	6,760			6,879
Less amount due within one year	(355		)	(765		)
	$	6,405		$	6,114
Securitization bonds
6.5% due 2012 to 2015	$	643		$	793
Less amount due within one year	(164		)	(150		)
	$	479		$	643
Junior Subordinated Debentures
6.5% due 2061	$	280		$	—
Trust preferred-linked securities
7.8% due 2032	$	—		$	186
7.5% due 2044	—			103
	$	—		$	289

_______________________________________

(1) Weighted average interest rates as of December 31, 2011 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.

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DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Debt Issuances

In 2011, the Company issued or remarketed the following long-term debt:

Company	Month Issued	Type	Interest Rate		Maturity	Amount
	(In millions)
Detroit Edison	April	Tax-Exempt Revenue Bonds (1)	2.35	%	2024	$	31
Detroit Edison	May	Mortgage Bonds (2)	3.90	%	2021	250
DTE Energy	May	Senior Notes (3)	Variable (4)		2013	300
Detroit Edison	September	Mortgage Bonds (5)	4.31	%	2023	102
Detroit Edison	September	Mortgage Bonds (5)	4.46	%	2026	77
Detroit Edison	September	Mortgage Bonds (5)	5.67	%	2041	46
Detroit Edison	September	Tax-Exempt Revenue Bonds (6)	2.13	%	2030	82
Detroit Edison	September	Mortgage Bonds (7)	4.50	%	2041	140
DTE Energy	December	Junior Subordinated Debentures (8)	6.50	%	2061	280
						$	1,308

(1) These bonds were remarketed for a three-year term ending April 1, 2014. The final maturity of the issue is October 1, 2024.

(2) Proceeds were used for general corporate purposes.

(3) Proceeds were used to repay a portion of DTE Energy's $600 million7.05% Senior Notes due June 1, 2011 and for general corporate purposes.

(4) The interest rate is reset quarterly at the three-month LIBOR plus 70 basis points.

(5) Proceeds were used to retire callable tax-exempt revenue bonds and for general corporate purposes.

(6) These bonds were remarketed for a five-year term ending September 1, 2016. The final maturity of the issue is September 1, 2030.

(7) Proceeds were used to retire approximately $140 million of callable tax-exempt revenue bonds and for general corporate purposes.

(8) Proceeds were used to redeem Trust Preferred-Linked Securities.

Debt Retirements and Redemptions

In 2011, the following debt was retired, through optional redemption or payment at maturity:

Company	Month Retired	Type	Interest Rate	Maturity	Amount
	(In millions)
Detroit Edison	May	Tax-Exempt Revenue Bonds	6.95%	2011	$	26
DTE Energy	June	Senior Notes	7.05%	2011	600
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.55%	2029	118
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.65%	2029	67
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.65%	2029	40
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.45%	2029	140
DTE Energy	December	Trust Preferred-Linked Securities	7.80%	2032	186
DTE Energy	December	Trust Preferred-Linked Securities	7.50%	2044	103
					$	1,280

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DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

	2012		2013		2014		2015		2016		2017 and Thereafter		Total
	(In millions)
Amount to mature	$	519	$	811	$	892	$	476	$	465	$	4,530	$	7,693

Junior Subordinated Debentures

In December 2011, DTE Energy issued $280 million of 6.50% Junior Subordinated Debentures due 2061 with proceeds used to redeem the Trust Preferred-Linked Securities.

The Company has the right to defer interest payments 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. Any deferred interest payments will bear additional interest at the rate of 6.50% per year.

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.

NOTE 16 — PREFERRED AND PREFERENCE SECURITIES

As of December 31, 2011, the amount of authorized and unissued stock is as follows:

Company	Type of Stock	Par Value		Shares Authorized
DTE Energy	Preferred	$	—	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 17 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

In October 2011, DTE Energy and its wholly owned subsidiaries, Detroit Edison and MichCon, entered into amended and restated five-year unsecured revolving credit agreements with a syndicate of 20 banks that may be used for general corporate borrowings, but are intended to provide liquidity support for each of the companies’ commercial paper programs. No one bank provides more than 8.5% of the commitment in any facility. Borrowings under the facilities are available at prevailing short-term interest rates. Additionally, DTE Energy has other facilities to support letter of credit issuance.

Detroit Edison entered into a one year $40 million letter of credit facility in December 2011. The facility was terminated early in January 2012 following cancellation of the letter of credit that it supported.

The above agreements require the Company to maintain a total funded debt to capitalization ratio of no more than 0.65 to 1. In the agreements, “total funded debt” means all indebtedness of the Company and its consolidated subsidiaries, including capital lease obligations, hedge agreements and guarantees of third parties’ debt, but excluding contingent obligations, nonrecourse and junior subordinated debt and certain equity-linked securities and, except for calculations at the end of the second quarter, certain MichCon short-term debt. “Capitalization” means the sum of (a) total funded debt plus (b) “consolidated net worth,” which is equal to consolidated total stockholders’ equity of the Company and its consolidated subsidiaries (excluding pension effects under certain FASB statements), as determined in accordance with accounting principles generally accepted in the United States of America. At December 31, 2011, the total funded debt to total capitalization ratios for DTE Energy, Detroit Edison and MichCon are 0.50 to 1, 0.52 to 1 and 0.45 to 1, respectively, and are in compliance with this financial covenant. The availability under these combined facilities at December 31, 2011 is shown in the following table:

94

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

	DTE Energy		Detroit Edison		MichCon		Total
	(In millions)
Unsecured letter of credit facility, expiring in December 2012	$	—	$	40	$	—	$	40
Unsecured letter of credit facility, expiring in May 2013	50		—		—		50
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Unsecured revolving credit facility, expiring October 2016	1,100		300		400		1,800
Total credit facilities at December 31, 2011	$	1,275	$	340	$	400	$	2,015
Amounts outstanding at December 31, 2011:
Commercial paper issuances	234		—		185		419
Letters of credit	178		40		—		218
	412		40		185		637
Net availability at December 31, 2011	$	863	$	300	$	215	$	1,378

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $39 million which are used for various corporate purposes.

The weighted average interest rate for short-term borrowings was 0.5% and 0.4% at December 31, 2011 and 2010, respectively.

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 $100 million with its clearing agent. The agreement, as amended, also allows for up to $50 million of additional margin financing provided that the Company posts a letter of credit for the incremental amount. At December 31, 2011, a $15 million letter of credit was in place, raising the capacity under this facility to $115 million. The $15 million letter of credit is included in the table above. The amount outstanding under this agreement was $56 million and $39 million at December 31, 2011 and December 31, 2010, respectively.

NOTE 18 — CAPITAL AND OPERATING LEASES

Lessee — The Company leases various assets under capital and operating leases, including coal railcars, 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, 2011 were:

	Capital Leases		Operating Leases
	(In millions)
2012	$	9	$	37
2013	7		29
2014	9		24
2015	7		20
2016	3		18
Thereafter	—		67
Total minimum lease payments	$	35	$	195
Less imputed interest	5
Present value of net minimum lease payments	30
Less current portion	7
Non-current portion	$	23

Rental expense for operating leases was $71 million in 2011, $54 million in 2010, and $58 million in 2009.

95

Lessor  — The Company leases a portion of its pipeline system to the Vector Pipeline through a capital lease contract that expires in 2020, with renewal options extending for five years. The Company owns a 40% interest in the Vector Pipeline. In addition, the Company has an energy services agreement, a portion of which is accounted for as a capital lease. The agreement expires in 2019, with a three or five year renewal option. The components of the net investment in the capital leases at December 31, 2011, were as follows:

	(In millions)
2012	$	12
2013	12
2014	12
2015	12
2016	12
Thereafter	43
Total minimum future lease receipts	103
Residual value of leased pipeline	40
Less unearned income	(56		)
Net investment in capital lease	87
Less current portion	(4		)
	$	83

NOTE 19 — COMMITMENTS AND CONTINGENCIES

Environmental

Electric Utility

Air - Detroit Edison is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze, mercury, and other air pollution. These rules have led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, mercury and other emissions. To comply with these requirements, Detroit Edison has spent approximately $1.7 billion through 2011. The Company estimates Detroit Edison will make capital expenditures of approximately $255 million in 2012 and up to approximately $1.9 billion of additional capital expenditures through 2021 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants. The Cross State Air Pollution Rule (CSAPR), finalized in July 2011, requires further reductions of sulfur dioxide and nitrogen oxides emissions beginning in 2012. On December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit granted the motions to stay the rule, leaving Detroit Edison temporarily subject to the previously existing Clean Air Interstate Rule (CAIR). The Electric Generating Unit Maximum Achievable Control Technology (EGU MACT) Rule was finalized on December 16, 2011. The EGU MACT requires reductions of mercury and other hazardous air pollutants beginning in 2015. Because these rules were recently finalized and technologies to comply are still being tested, it is not possible to quantify the impact of these rulemakings.

In July 2009, DTE Energy received a Notice of Violation/Finding of Violation (NOV/FOV) from the EPA alleging, among other things, that five Detroit Edison power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and operating permit requirements under the Clean Air Act. An additional NOV/FOV was received in June 2010 related to a recent project and outage at Unit 2 of the Monroe Power Plant.

On August 5, 2010, the United States Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and Detroit Edison, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require Detroit Edison to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require Detroit Edison to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from Detroit Edison's fleet of coal-fired power plants until the new control equipment is operating.

On August 23, 2011, the U.S. District judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy.On October 20, 2011, the EPA caused to be filed a Notice of Appeal. A decision by the Court of Appeals is not expected until late 2012. DTE Energy and Detroit Edison believe that the

96

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of discussions with the EPA regarding the NOV/FOV and the result of the appeals process, the Company could also be required to install additional pollution control equipment at some or all of the power plants in question, implement early retirement of facilities where control equipment is not economical, engage in supplemental environmental programs, and/or pay fines. The Company cannot predict the financial impact or outcome of this matter, or the timing of its resolution.

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 completed studies and expected future studies, 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 in additional capital expenditures over the four to six years subsequent to 2008 to comply with these requirements. However, a January 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation that has resulted 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. In 2008, the Supreme Court agreed to review the remanded cost-benefit analysis provision of the rule and in April 2009 upheld the EPA's use of this provision in determining best technology available for reducing environmental impacts. The EPA published a proposed rule in 2011 that extended the time line to 2020 with an estimated expected increase in costs to $80 million. A final rule is expected in mid-2012. The EPA has also issued an information collection request to begin a review of steam electric effluent guidelines. It is not possible at this time to quantify the impacts of these developing requirements.

Contaminated and Other 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, have been designated as manufactured gas plant (MGP) sites. Detroit Edison conducted remedial investigations at contaminated sites, including three former MGP sites. The 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, including the area surrounding an ash landfill, electrical distribution substations, and 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. At December 31, 2011 and December 31, 2010, the Company had $8 million and $9 million, respectively, accrued for remediation. 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.

Detroit Edison owns and operates a permitted engineered ash storage facility at the Monroe Power Plant to dispose of fly ash from the coal fired power plant. Detroit Edison performed an engineering analysis in 2009 and identified the need for embankment side slope repairs and reconstruction.

The EPA has published proposed rules to regulate coal ash under the authority of the Resources Conservation and Recovery Act (RCRA). The proposed rule published in June 2010 contains two primary regulatory options to regulate coal ash residue. The EPA is currently considering either designating coal ash as a “Hazardous Waste” as defined by RCRA or regulating coal ash as non-hazardous waste under RCRA. Agencies and legislatures have urged the EPA to regulate coal ash as a non-hazardous waste. If the EPA designates coal ash as a hazardous waste, the agency could apply some, or all, of the disposal and reuse standards that have been applied to other existing hazardous wastes to disposal and reuse of coal ash. Some of the regulatory actions currently being contemplated could have a significant impact on our operations and financial position and the rates we charge our customers. It is not possible to quantify the impact of those expected rulemakings at this time.

Gas Utility

Contaminated Sites — 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, 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.

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. As of December 31, 2011 and December 31, 2010, the Company had $36 million, accrued for remediation.

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

97

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

position and cash flows. The Company anticipates the cost amortization methodology approved by the MPSC for MichCon, which allows MichCon to amortize the MGP costs over a ten-year period beginning with the year subsequent to the year the MGP costs were incurred, and the cost deferral and rate recovery mechanism for Citizens Fuel Gas approved by the City of Adrian, will prevent environmental costs from having a material adverse impact on the Company’s 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 Michigan coke battery facility received and responded to information requests from the EPA that resulted in the issuance of a NOV in June of 2007 alleging 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. Furthermore, the Michigan coke battery facility is the subject of an investigation by the MDEQ concerning visible emissions readings that resulted from the Company self reporting to MDEQ questionable activities by an employee of a contractor hired by the Company to perform the visible emissions readings. At this time, the Company cannot predict the impact of this investigation.

In April 2006, the prior owners of the coke battery facility in Pennsylvania that the Company purchased in 2008 received a Notice of Violation/Finding of Violation from the EPA alleging violations of the lowest achievable emission rate requirements associated with visible emissions from the combustion stack, door leaks and charging activities at the coke battery facility. The EPA has also alleged certain violations of the Clean Water Act, but has not issued a notice of violation in connection with these alleged violations. The Company is in the process of negotiating a Consent Order with the EPA to settle these historic air and water issues. The Company expects to enter into the Consent Order during the first quarter of 2012.

The Company received two Notices of Violation from the Pennsylvania Department of Environmental Protection in 2010 alleging violations of the permit for the Pennsylvania coke battery facility in connection with coal pile storm water runoff. The Company has implemented best management practices to address this issue and is currently seeking a permit from the Pennsylvania Department of Environmental Protection to upgrade its wastewater treatment technology to a biological treatment facility. The Company expects to spend less than $1 million on the existing waste water treatment system to comply with existing water discharge requirements and to upgrade its coal pile storm water runoff management program. The Company may spend an additional $13 million over the next few years to meet future regulatory requirements and gain other operational improvements savings.

The Company believes that its non-utility affiliates are substantially in compliance with all environmental requirements, other than as noted above.

Other

In March 2011, the EPA finalized a new set of regulations regarding the identification of non-hazardous secondary materials that are considered solid waste, industrial boiler and process heater maximum achievable control technologies (IBMACT) for major and area sources, and commercial/industrial solid waste incinerator new source performance standard and emission guidelines (CISWI). The effective dates of the major source IBMACT and CISWI regulations were stayed anda re-proposal was issued by the EPA in December 2011. The re-proposed rules may impact our existing operations and may require us, in certain instances, to install new air pollution control devices. The re-proposed regulations will provide a minimum period of three years for compliance with the applicable standards. Based on the final approved regulations, anticipated in the first half of 2012, the Company will assess the financial impact, if any, on current operations for compliance with the applicable new standards.

In February 2008, DTE Energy was named as one of approximately 24 defendant oil, power and coal companies in a lawsuit filed in a United States District Court. DTE Energy was served with process in March 2008. The plaintiffs, the Native Village of Kivalina and City of Kivalina, which are home to approximately 400 people in Alaska, claim that the defendants’ business activities have contributed to global warming and, as a result, higher temperatures are damaging the local economy and leaving the island more vulnerable to storm activity in the fall and winter. As a result, the plaintiffs are seeking damages of up to $400 million for relocation costs associated with moving the village to a safer location, as well as unspecified attorney’s fees and expenses. On October 15, 2009, the U.S. District Court granted defendants’ motions dismissing all of plaintiffs’ federal claims in the case on two independent grounds: (1) the court lacks subject matter jurisdiction to hear the claims because of the political question doctrine; and (2) plaintiffs lack standing to bring their claims. The court also dismissed plaintiffs’ state law claims because the court lacked supplemental jurisdiction over them after it dismissed the federal claims; the dismissal of the state law claims was without prejudice. The plaintiffs have appealed to the U.S. Court of Appeals for the Ninth Circuit.

98

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Nuclear Operations

Property Insurance

Detroit Edison maintains 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 policies.

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.

In 2007, the Terrorism Risk Insurance Extension Act of 2005 (TRIA) was extended through 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 $29 million per event if the loss associated with any one event at any nuclear plant in the United States should exceed the accumulated funds available to NEIL.

Public Liability Insurance

As of January 1, 2012, as required by federal law, Detroit Edison maintains $375 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 $117.5 million could be levied against each licensed nuclear facility, but not more than $17.5 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.

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. The DOE's Yucca Mountain Nuclear Waste Repository program for the acceptance and disposal of spent nuclear fuel was terminated in 2011. 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 spent nuclear fuel storage strategy utilizing a fuel pool. The Company continues to develop its on-site dry cask storage facility and has postponed the initial offload from the spent fuel pool until 2013. The dry cask storage facility is expected to provide sufficient spent fuel storage capability for the life of the plant as defined by the original operating license. Issues relating to long-term waste disposal policy and to the disposition of funds contributed by Detroit Edison ratepayers to the federal waste fund await future governmental action.

Synthetic Fuel Guarantees

The Company discontinued the operations of its synthetic fuel production facilities throughout the United States as

of December 31, 2007. The Company 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, 2011 is approximately $1.2 billion. Payment under these guarantees is considered remote.

99

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Reduced Emissions Fuel Guarantees

The Company has provided certain guarantees and indemnities in conjunction with the sales of interests in its reduced emissions fuel facilities. The guarantees cover potential commercial, environmental, 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, 2011 is approximately $15 million. Payment under these guarantees is considered remote.

Other 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. The Company’s guarantees are not individually material with maximum potential payments totaling $10 million at December 31, 2011.

The Company is periodically required to obtain performance surety bonds in support of obligations to various governmental entities and other companies in connection with its operations. As of December 31, 2011, the Company had approximately $23 million of performance bonds outstanding. In the event that such bonds are called for nonperformance, the Company would be obligated to reimburse the issuer of the performance bond. The Company is released from the performance bonds as the contractual performance is completed and does not believe that a material amount of any currently outstanding performance bonds will be called.

Labor Contracts

There are several bargaining units for the Company’s approximately 5,000 represented employees. The majority of represented employees are under contracts that expire in August 2012 and June and October 2013.

Purchase Commitments

As of December 31, 2011, 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 $5.3 billion from 2012 through 2051 as detailed in the following table:

	(In millions)
2012	$	2,276
2013	1,221
2014	732
2015	237
2016	109
2017 — 2051	740
	$	5,315

The Company also estimates that 2012 capital expenditures will be approximately $1.9 billion. The Company has made certain commitments in connection with expected capital expenditures.

Bankruptcies

The Company purchases and sells electricity, gas, coal, coke and other energy products from and to governmental entities and numerous companies operating in the steel, automotive, energy, retail, financial and other industries. Certain of its 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 records provisions for amounts considered at risk of probable loss. The Company believes its accrued amounts are adequate for probable loss. The final resolution of these matters may have a material effect on its consolidated financial statements.

100

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Other Contingencies

The Company is involved in certain other 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 that 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 Notes 4 and 11 for a discussion of contingencies related to derivatives and regulatory matters.

NOTE 20 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

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 pension costs by contributing amounts consistent with the Pension Protection Act of 2006 provisions and additional amounts when it deems appropriate. The Company contributed $200 million to its pension plans in 2011. At the discretion of management, and depending upon financial market conditions, we anticipate making up to a $240 million contribution to the pension plans in 2012.

Net pension cost includes the following components:

	2011			2010			2009
	(In millions)
Service cost	$	69		$	64		$	52
Interest cost	202			202			203
Expected return on plan assets	(246		)	(258		)	(255		)
Amortization of:
Net actuarial loss	142			100			52
Prior service cost	3			4			6
Special termination benefits	2			—			—
Net pension cost	$	172		$	112		$	58

	2011			2010
	(In millions)
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income
Net actuarial loss	$	619		$	166
Amortization of net actuarial loss	(142		)	(100		)
Amortization of prior service cost	(3		)	(4		)
Total recognized Regulatory assets and Other comprehensive income	$	474		$	62
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	646		$	174
Estimated amounts to be amortized from Regulatory assets and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year
Net actuarial loss	$	171		$	133
Prior service cost	—			3

101

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 Statements of Financial Position at December 31:

	2011			2010
	(In millions)
Accumulated benefit obligation, end of year	$	3,881		$	3,521
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	3,785		$	3,436
Consolidation of VIEs	—			82
Service cost	69			64
Interest cost	202			202
Actuarial loss	355			216
Special termination benefits	2			—
Benefits paid	(218		)	(215		)
Projected benefit obligation, end of year	$	4,195		$	3,785
Change in plan assets
Plan assets at fair value, beginning of year	$	2,913		$	2,549
Consolidation of VIEs	—			64
Actual return on plan assets	(18		)	309
Company contributions	209			206
Benefits paid	(218		)	(215		)
Plan assets at fair value, end of year	$	2,886		$	2,913
Funded status of the plans	$	(1,309	)	$	(872	)
Amount recorded as:
Current liabilities	$	(11	)	$	(6	)
Noncurrent liabilities	(1,298		)	(866		)
	$	(1,309	)	$	(872	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	202		$	195
Prior service (credit)	(3		)	(4		)
	$	199		$	191
Amounts recognized in Regulatory assets (see Note 11)
Net actuarial loss	$	2,201		$	1,730
Prior service cost	7			12
	$	2,208		$	1,742

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

	2011		2010		2009
Projected benefit obligation
Discount rate	5.00	%	5.50	%	5.90	%
Rate of compensation increase	4.20	%	4.00	%	4.00	%
Net pension costs
Discount rate	5.50	%	5.90	%	6.90	%
Rate of compensation increase	4.00	%	4.00	%	4.00	%
Expected long-term rate of return on plan assets	8.50	%	8.75	%	8.75	%

102

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The Company employs a 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. As a result of this process, the Company is lowering its long-term rate of return assumptions for its pension and OPEB plans to 8.25% for 2012. The Company believes this rate is a reasonable assumption for the long-term rate of return on its plan assets for 2012 given its investment strategy.

At December 31, 2011, 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)
2012	$	240
2013	239
2014	244
2015	253
2016	260
2017-2021	1,439
	$	2,675

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, with consideration given to the liquidity needs of the plan. 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. Fixed income securities generally include corporate bonds of companies from diversified industries, mortgage-backed securities, and U.S. Treasuries. Other assets such as private equity and hedge funds are used 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/or 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.

Target allocations for plan assets as of December 31, 2011 are listed below:

U.S. Large Cap Equity Securities	22	%
U.S. Small Cap and Mid Cap Equity Securities	5
Non U.S. Equity Securities	20
Fixed Income Securities	25
Hedge Funds and Similar Investments	20
Private Equity and Other	8
	100	%

103

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Fair Value Measurements at December 31, 2011(a)

	Level 1		Level 2		Level 3		Balance at December 31, 2011
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	33	$	—	$	33
Equity securities
U.S. Large Cap (c)	640		40		—		680
U.S. Small/Mid Cap (d)	159		5		—		164
Non U.S (e)	392		114		—		506
Fixed income securities (f)	88		703		—		791
Hedge Funds and Similar Investments (g)	190		58		296		544
Private Equity and Other (h)	—		—		168		168
Total	$	1,469	$	953	$	464	$	2,886

Fair Value Measurements at December 31, 2010(a)

	Level 1		Level 2		Level 3		Balance at December 31, 2010
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	34	$	—	$	34
Equity securities
U.S. Large Cap (c)	686		38		—		724
U.S. Small/Mid Cap (d)	181		8		—		189
Non U.S (e)	285		222		—		507
Fixed income securities (f)	61		658		—		719
Hedge Funds and Similar Investments (g)	189		73		304		566
Private Equity and Other (h)	—		—		174		174
Total	$	1,402	$	1,033	$	478	$	2,913

_______________________________________

(a) See Note 3 — Fair Value for a description of levels within the fair value hierarchy.

(b) This category predominantly represents certain short-term fixed income securities and money market investments that are managed in separate accounts or commingled funds. Pricing for investments in this category are obtained from quoted prices in actively traded markets or valuations from brokers or pricing services.

(c) This category comprises both actively and not actively managed portfolios that track the S&P 500 low cost equity index funds. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(d) This category represents portfolios of small and medium capitalization domestic equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(e) This category primarily consists of portfolios of non-U.S. developed and emerging market equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(f) This category includes corporate bonds from diversified industries, U.S. Treasuries, and mortgage-backed securities. Pricing for investments in this category is obtained from quoted prices in actively traded markets and quotations from broker or pricing services. Non-exchange traded securities and exchange-traded securities held in commingled funds are classified as Level 2 assets.

104

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

(g) This category utilizes a diversified group of strategies that attempt to capture financial market inefficiencies and includes publicly traded debt and equity, publicly traded mutual funds, commingled and limited partnership funds and non-exchange traded securities. Pricing for Level 1 and level 2 assets in this category is obtained from quoted prices in actively traded markets and quoted prices from broker or pricing services. Non-exchange traded securities held in commingled funds are classified as Level 2 assets. Valuations for some Level 3 assets in this category may be based on limited observable inputs as there may be little, if any, publicly available pricing.

(h) This category includes a diversified group of funds and strategies that primarily invests in private equity partnerships. This category also includes investments in timber and private mezzanine debt. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available pricing. Valuations for assets in this category may be based on discounted cash flow analyses, relevant publicly-traded comparables and comparable transactions.

The pension trust holds debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices in actively traded markets. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued based on underlying securities, using quoted prices in actively traded markets. Non-exchange traded fixed income securities are valued by the trustee based upon quotations available from brokers or pricing services. A primary price source is identified by asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustees challenge an assigned price and determine that another price source is considered to be preferable. DTE Energy has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, DTE Energy selectively corroborates the fair values of securities by comparison of market-based price sources.

Fair Value Measurements Using Significant Unobservable Inputs (Level 3):

	Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1, 2011	$	304		$	174		$	478
Total realized/unrealized gains (losses):
Realized gains (losses)	(4		)	6			2
Unrealized gains (losses)	1			(30		)	(29		)
Purchases, sales and settlements:
Purchases	64			23			87
Sales	(69		)	(5		)	(74		)
Ending Balance at December 31, 2011	$	296		$	168		$	464
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	4		$	(28	)	$	(24	)

	Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1, 2010	$	484		$	160		$	644
Total realized/unrealized gains (losses)	51			23			74
Purchases, sales and settlements	(231		)	(9		)	(240		)
Ending Balance at December 31, 2010	$	304		$	174		$	478
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	29		$	13		$	42

105

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

There were no transfers between Level 3 and Level 2 and there were no significant transfers between Level 2 and Level 1 in the years ended December 31, 2011 and 2010.

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 $35 million, $34 million, and $33 million in each of the years 2011, 2010, and 2009, respectively.

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) and 401(h) trusts exist for represented and non-represented employees. The Company contributed $111 million to its postretirement medical and life insurance benefit plans during 2011.

In January 2012, the Company contributed $140 million to its other postretirement benefit plans. At the discretion of management, the Company may make up to an additional $120 million contribution to its VEBA trusts in 2012.

Net postretirement cost includes the following components:

	2011			2010			2009
	(In millions)
Service cost	$	64		$	61		$	59
Interest cost	121			125			133
Expected return on plan assets	(94		)	(74		)	(55		)
Amortization of:
Net loss	55			54			72
Prior service (credit)	(26		)	(4		)	(6		)
Net transition obligation	2			2			2
Net postretirement cost	$	122		$	164		$	205

	2011			2010
	(In millions)
Other changes in plan assets and APBO recognized in Regulatory assets and Other comprehensive income
Net actuarial loss	$	195		$	93
Amortization of net actuarial loss	(55		)	(54		)
Prior service credit	(4		)	(79		)
Amortization of prior service credit	26			4
Amortization of transition asset	(2		)	(2		)
Total recognized in Regulatory assets and Other comprehensive income	$	160		$	(38	)
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	282		$	126
Estimated amounts to be amortized from Regulatory assets and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year
Net actuarial loss	$	78		$	59
Prior service credit	$	(27	)	$	(26	)
Net transition obligation	$	2		$	2

106

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The following table reconciles the obligations, assets and funded status of the plans including amounts recorded as accrued postretirement cost in the Consolidated Statements of Financial Position at December 31:

	2011			2010
	(In millions)
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation, beginning of year	$	2,305		$	2,151
Consolidation of VIEs	—			21
Service cost	64			61
Interest cost	121			125
Plan amendments	(4		)	(79		)
Actuarial loss	80			127
Medicare Part D subsidy	6			7
Benefits paid	(102		)	(108		)
Accumulated postretirement benefit obligation, end of year	$	2,470		$	2,305
Change in plan assets
Plan assets at fair value, beginning of year	$	1,029		$	864
Actual return on plan assets	(22		)	108
Company contributions	111			160
Benefits paid	(133		)	(103		)
Plan assets at fair value, end of year	$	985		$	1,029
Funded status, end of year	$	(1,485	)	$	(1,276	)
Amount recorded as:
Current liabilities	$	(1	)	$	(1	)
Noncurrent liabilities	$	(1,484	)	$	(1,275	)
	$	(1,485	)	$	(1,276	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	47		$	46
Prior service credit	(20		)	(28		)
Net transition asset	(1		)	(2		)
	$	26		$	16
Amounts recognized in Regulatory assets (See Note 11)
Net actuarial loss	$	835		$	692
Prior service cost	(60		)	(74		)
Net transition obligation	3			6
	$	778		$	624

107

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

	2011		2010		2009
Projected benefit obligation
Discount rate	5.00	%	5.50	%	5.90	%
Net benefit costs
Discount rate	5.50	%	5.90	%	6.90	%
Expected long-term rate of return on plan assets	8.75	%	8.75	%	8.75	%
Health care trend rate pre- and post- 65	7.00	%	7.00	%	7.00	%
Ultimate health care trend rate	5.00	%	5.00	%	5.00	%
Year in which ultimate reached	2019		2016		2016

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 $35 million and increased the accumulated benefit obligation by $306 million at December 31, 2011. 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 $23 million and would have decreased the accumulated benefit obligation by $297 million at December 31, 2011.

At December 31, 2011, 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)
2012	$	109
2013	116
2014	124
2015	132
2016	142
2017 — 2021	839
	$	1,462

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 pension plans.

Target allocations for plan assets as of December 31, 2011 are listed below:

U.S. Large Cap Equity Securities	22	%
Non U.S. Equity Securities	20
Fixed Income Securities	25
Hedge Funds and Similar Investments	20
Private Equity and Other	13
	100	%

108

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Fair Value Measurements at December 31, 2011(a)

	Level 1		Level 2		Level 3		Balance at December 31, 2011
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	13	$	—	$	13
Equity securities:
U.S. Large Cap (c)	175		15		—		190
U.S. Small/Mid Cap (d)	70		6		—		76
Non U.S (e)	176		14		—		190
Fixed income securities (f)	24		236		—		260
Hedge Funds and Similar Investments (g)	80		21		95		196
Private Equity and Other (h)	—		—		60		60
Total	$	525	$	305	$	155	$	985

Fair Value Measurements at December 31, 2010(a)

	Level 1		Level 2		Level 3		Balance at December 31, 2010
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	8	$	—	$	8
Equity securities
U.S. Large Cap (c)	126		62		—		188
U.S. Small/Mid Cap (d)	60		58		—		118
Non U.S (e)	79		122		—		201
Fixed income securities (f)	4		252		—		256
Hedge Funds and Similar Investments (g)	76		48		79		203
Private Equity and Other (h)	—		—		55		55
Total	$	345	$	550	$	134	$	1,029

_______________________________________

(a) See Note 3 — Fair Value for a description of levels within the fair value hierarchy.

(b) This category predominantly represents certain short-term fixed income securities and money market investments that are managed in separate accounts or commingled funds. Pricing for investments in this category are obtained from quoted prices in actively traded markets or valuations from brokers or pricing services.

(c) This category comprises both actively and not actively managed portfolios that track the S&P 500 low cost equity index funds. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(d) This category represents portfolios of small and medium capitalization domestic equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(e) This category primarily consists of portfolios of non-U.S. developed and emerging market equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(f) This category includes corporate bonds from diversified industries, U.S. Treasuries, and mortgage backed securities. Pricing for investments in this category is obtained from quoted prices in actively traded markets and quotations from broker or pricing services. Non-exchange traded securities and exchange-traded securities held in commingled funds are classified as Level 2 assets.

109

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

(g) This category utilizes a diversified group of strategies that attempt to capture financial market inefficiencies and includes publicly traded debt and equity, publicly traded mutual funds, commingled and limited partnership funds and non-exchange traded securities. Pricing for Level 1 and level 2 assets in this category is obtained from quoted prices in actively traded markets and quoted prices from broker or pricing services. Non-exchange traded securities held in commingled funds are classified as Level 2 assets. Valuations for some Level 3 assets in this category may be based on limited observable inputs as there may be little, if any, publicly available pricing.

(h) This category includes a diversified group of funds and strategies that primarily invests in private equity partnerships. This category also includes investments in timber and private mezzanine debt. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available pricing. Valuations for assets in this category may be based on discounted cash flow analyses, relevant publicly-traded comparables and comparable transactions.

The VEBA trusts hold debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices in actively traded markets. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued based on underlying securities, using quoted prices in actively traded markets. Non-exchange traded fixed income securities are valued by the trustee based upon quotations available from brokers or pricing services. A primary price source is identified by asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustees challenge an assigned price and determine that another price source is considered to be preferable. DTE Energy has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, DTE Energy selectively corroborates the fair values of securities by comparison of market-based price sources.

Fair Value Measurements Using Significant Unobservable Inputs (Level 3):

	Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1, 2011	$	79		$	55		$	134
Total realized/unrealized gains (losses):
Realized gains (losses)	(1		)	2			1
Unrealized gains (losses)	2			(22		)	(20		)
Purchases, sales and settlements:
Purchases	68			48			116
Sales	(53		)	(23		)	(76		)
Ending Balance at December 31, 2011	$	95		$	60		$	155
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	5		$	(16	)	$	(11	)

	Hedge Funds and Similar Investments			Private Equity and Other		Total
	(In millions)
Beginning Balance at January 1, 2010	$	92		$	46	$	138
Total realized/unrealized gains	10			8		18
Purchases, sales and settlements	(23		)	1		(22		)
Ending Balance at December 31, 2010	$	79		$	55	$	134
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	6		$	7	$	13

There were no transfers between Level 3 and Level 2 and there were no significant transfers between Level 2 and Level 1 in the years ended December 31, 2011 and 2010.

110

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Healthcare Legislation

In March 2010, the Patient Protection and Affordable Care Act of 2010 and the Health Care and Education Reconciliation Act of 2010 were enacted into law (collectively, the “Act”). The Act is a comprehensive health care reform bill. A provision of the Act repeals the current rule permitting deduction of the portion of the drug coverage expense that is offset by the Medicare Part D subsidy, effective for taxable years beginning after December 31, 2012.

DTE Energy’s retiree healthcare plan includes the provision of postretirement prescription drug coverage (“coverage”) which is included in the calculation of the recorded other postemployment benefit (OPEB) obligation. Because the Company’s coverage meets certain criteria, DTE Energy is eligible to receive the Medicare Part D subsidy. With the enactment of the Act, the subsidy will continue to not be subject to tax, but an equal amount of prescription drug coverage expenditures will not be deductible. Income tax accounting rules require the impact of a change in tax law be recognized in continuing operations in the Consolidated Statements of Operations in the period that the tax law change is enacted.

This change in tax law required a remeasurement of the Deferred tax asset related to the OPEB obligation and the Deferred tax liability related to the OPEB Regulatory Asset in 2010. The net impact of the remeasurement was $22 million, $18 million and $3 million for DTE Energy, Detroit Edison and MichCon, respectively. The Detroit Edison and MichCon amounts have been deferred as Regulatory Assets as the traditional rate setting process allows for the recovery of income tax costs.

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 $6 million in 2011, $7 million in 2010 and $20 million in 2009. At December 31, 2011, the gross amount of federal subsidies expected to be received in 2012 is estimated to be $6 million.

Grantor Trust

MichCon maintains a Grantor Trust to fund other postretirement benefit obligations 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, approximately $13 million at December 31, 2011, with unrealized gains and losses recorded to earnings.

NOTE 21 — STOCK-BASED COMPENSATION

The Company’s stock incentive program permits the grant of incentive stock options, non-qualifying stock options, stock awards, performance shares and performance units to employees and members of its Board of Directors. Key provisions of the stock incentive program are:

• 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.

The Company records compensation expense at fair value over the vesting period for all awards it grants.

Stock-based compensation for the reporting periods is as follows:

	2011		2010		2009
	(In millions)
Stock-based compensation expense	$	66	$	52	$	56
Tax benefit	25		20		22
Stock-based compensation cost capitalized in property, plant and equipment	4		3		3

111

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 vest ratably over a three-year period.

Stock option activity was as follows:

					(In millions)
	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value
Options outstanding at January 1, 2011	4,827,457		$	41.09
Granted	—		$	—
Exercised	(2,040,229	)	$	40.83
Forfeited or expired	(22,558	)	$	43.44
Options outstanding at December 31, 2011	2,764,670		$	41.25	$	29
Options exercisable at December 31, 2011	2,098,184		$	42.42	$	19

As of December 31, 2011, the weighted average remaining contractual life for the exercisable shares is 4.25 years. As of December 31, 2011, 666,486 options were non-vested. During 2011, 687,061 options vested.

The weighted average grant date fair value of options granted during 2010, and 2009 was $5.62 and $4.41, respectively. The intrinsic value of options exercised for the years ended December 31, 2011, 2010 and 2009 was $20 million, $9 million, and $3 million, respectively. Total option expense recognized during 2011, 2010 and 2009 was $2 million, $4 million and $3 million, respectively.

The number, weighted average exercise price and weighted average remaining contractual life of options outstanding were as follows:

						Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)
					Number of Options
Range of Exercise Prices
$	27.00	—	$	38.00	417,633	$	27.80	7.16
$	38.01	—	$	42.00	723,662	$	41.04	3.11
$	42.01	—	$	45.00	1,272,117	$	44.04	5.64
$	45.01	—	$	50.00	351,258	$	47.60	4.81
					2,764,670	$	41.25	5.10

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
	2010		2009
Risk-free interest rate	2.91	%	2.04	%
Dividend yield	5.08	%	4.98	%
Expected volatility	22.96	%	27.88	%
Expected life	6	years	6	years

The Company includes both historical and implied share-price volatility in option volatility. Implied volatility is derived from exchange traded options on DTE Energy common stock. The Company’s expected life estimate is based on historical data.

112

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Stock Awards

Stock awards granted under the plan are restricted for varying periods, 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.

Stock award activity for the periods ended December 31 was:

	2011		2010		2009
Fair value of awards vested (in millions)	$	13	$	19	$	18
Restricted common shares awarded	381,840		238,405		523,660
Weighted average market price of shares awarded	$	47.98	$	44.08	$	28.73
Compensation cost charged against income (in millions)	$	12	$	12	$	18

The following table summarizes the Company’s stock awards activity for the period ended December 31, 2011:

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at January 1, 2011	757,414		$	37.32
Grants	381,840		$	47.98
Forfeitures	(66,675	)	$	40.92
Vested and issued	(346,355	)	$	38.25
Balance at December 31, 2011	726,224		$	42.25

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 closing stock price market value. The settlement of the award is based on the closing price at the settlement date.

The Company recorded compensation expense as follows:

	2011		2010		2009
	(In millions)
Compensation expense	$	53	$	36	$	35
Cash settlements (1)	$	3	$	3	$	1
Stock settlements (1)	$	25	$	23	$	8

_______________________________________

(1) Sum of cash and stock settlements approximates the intrinsic value of the liability.

During the vesting period, the recipient of a performance share award has no shareholder rights. However, for performance shares granted before 2010, recipients will be paid an amount equal to the dividend equivalent on such shares. Performance shares granted in 2010 or later will not be entitled to dividend equivalent payments before the performance shares granted are earned and vested. During the period beginning on the date the post-2009 performance shares are awarded and ending on the certification date of the performance objectives, the number of performance shares awarded will be increased, assuming full dividend reinvestment at the fair market value on the dividend payment date. The cumulative number of performance shares will be adjusted to determine the final payment bases on the performance objectives achieved. Performance share awards are nontransferable and are subject to risk of forfeiture.

113

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The following table summarizes the Company’s performance share activity for the period ended December 31, 2011:

	Performance Shares
Balance at January 1, 2011	1,527,253
Grants	621,114
Forfeitures	(71,946	)
Payouts	(467,688	)
Balance at December 31, 2011	1,608,733

Unrecognized Compensation Costs

As of December 31, 2011, there was $50 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 1.36 years.

	Unrecognized Compensation Cost		Weighted Average to be Recognized
	(In millions)		(In years)
Options	$	1	0.76
Stock awards	15		1.12
Performance shares	34		1.48
	$	50	1.36

NOTE 22 — SUPPLEMENTAL CASH FLOW INFORMATION

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

	2011			2010			2009
	(In millions)
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	71		$	79		$	167
Inventories	(129		)	(133		)	28
Recoverable pension and postretirement costs	(620		)	(32		)	(19		)
Accrued/prepaid pensions	432			67			11
Accounts payable	(23		)	12			(162		)
Income taxes payable/receivable	249			(245		)	43
Derivative assets and liabilities	(94		)	(48		)	(81		)
Postretirement obligation	209			(24		)	(147		)
Other assets	9			(52		)	58
Other liabilities	(10		)	83			171
	$	94		$	(293	)	$	69

114

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

	2011			2010		2009
	(In millions)
Cash paid (received) for:
Interest (net of interest capitalized)	$	485		$	551	$	550
Income taxes	$	(205	)	$	93	$	18
Noncash financing activities: Common stock issued for employee benefit plans	$	1		$	156	$	47

NOTE 23 — SEGMENT AND RELATED INFORMATION

The Company sets strategic goals, allocates resources and evaluates performance based on the following structure:

Electric Utility segment consists principally of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million residential, commercial and industrial customers in southeastern Michigan.

Gas Utility segment consists of MichCon and Citizens.  MichCon is engaged in the purchase, storage, transportation, distribution and sale of natural gas to approximately 1.2 million residential, commercial and industrial customers throughout Michigan and the sale of storage and transportation capacity. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.

Gas Storage and Pipelines consists of natural gas pipeline, gathering and storage businesses.

Unconventional Gas Production is engaged in unconventional gas and oil project development and production.

Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers; provide coal transportation and marketing; and sell electricity from biomass-fired energy projects.

Energy Trading consists of energy marketing and trading operations.

Corporate and Other, includes various holding company activities, holds certain non-utility debt and energy-related investments.

The federal 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 if applicable. The MBT provision of the utility subsidiaries is determined on an individual company basis and recognizes the tax benefit of various tax credits and net operating losses if applicable. See Note 12 for a discussion of the MCIT, which replaced the MBT effective January 1, 2012. The subsidiaries record federal and state income taxes payable to or receivable from DTE Energy based on the federal and state tax provisions of each company.

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:

	2011			2010			2009
	(In millions)
Electric Utility	$	33		$	30		$	28
Gas Utility	2			—			2
Gas Storage and Pipelines	8			4			5
Power and Industrial Projects	238			161			11
Energy Trading	70			89			93
Corporate and Other	(50		)	(65		)	(74		)
	$	301		$	219		$	65

115

Financial data of the business segments follows:

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income Attributable to DTE Energy Company			Total Assets		Goodwill		Capital Expenditures
	(In millions)
2011
Electric Utility	$	5,154		$	818	$	(1	)	$	289		$	265		$	434		$	17,370	$	1,208	$	1,203
Gas Utility	1,505			89		(7		)	64			60			110			3,933		745		179
Gas Storage and Pipelines	91			6		(5		)	7			35			57			421		22		16
Unconventional Gas Production	39			18		—			7			(3		)	(6		)	319		2		29
Power and Industrial Projects	1,129			60		(8		)	32			11			38			1,210		26		56
Energy Trading	1,276			3		—			9			34			52			552		17		1
Corporate and Other	4			1		(47		)	144			(134		)	26			2,204		—		—
Reconciliation and Eliminations	(301		)	—		58			(58		)	(1		)	—			—		—		—
Total	$	8,897		$	995	$	(10	)	$	494		$	267		$	711		$	26,009	$	2,020	$	1,484

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income Attributable to DTE Energy Company			Total Assets		Goodwill		Capital Expenditures
	(In millions)
2010
Electric Utility	$	4,993		$	849	$	(1	)	$	313		$	270		$	441		$	16,375	$	1,206	$	864
Gas Utility	1,648			92		(9		)	66			67			127			3,854		759		147
Gas Storage and Pipelines	83			5		(1		)	6			32			51			391		9		5
Unconventional Gas Production	32			15		—			6			(6		)	(11		)	308		2		27
Power and Industrial Projects	1,144			60		(3		)	33			3			85			1,236		27		53
Energy Trading	875			5		—			13			5			6			483		17		1
Corporate and Other	1			1		(47		)	160			(60		)	(69		)	2,249		—		—
Reconciliation and Eliminations	(219		)	—		49			(48		)	—			—			—		—		—
Total	$	8,557		$	1,027	$	(12	)	$	549		$	311		$	630		$	24,896	$	2,020	$	1,097

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income Attributable to DTE Energy Company			Total Assets		Goodwill		Capital Expenditures
	(In millions)
2009
Electric Utility	$	4,714		$	844	$	(1	)	$	324		$	228		$	376		$	15,879	$	1,206	$	794
Gas Utility	1,788			107		(8		)	68			39			80			3,832		759		166
Gas Storage and Pipelines	82			5		(1		)	10			33			49			367		9		2
Unconventional Gas Production	31			16		—			6			(4		)	(9		)	309		2		26
Power and Industrial Projects	661			40		(3		)	30			(7		)	31			1,118		31		45
Energy Trading	804			5		(1		)	10			37			75			552		17		2
Corporate & Other	—			3		(55		)	147			(79		)	(70		)	2,138		—		—
Reconciliation and Eliminations	(66		)	—		50			(50		)	—			—			—		—		—
Total	$	8,014		$	1,020	$	(19	)	$	545		$	247		$	532		$	24,195	$	2,024	$	1,035

116

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 24 — 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.

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
	(In millions, except per share amounts)
2011
Operating Revenues	$	2,431	$	2,028	$	2,265	$	2,173	$	8,897
Operating Income	$	390	$	288	$	399	$	346	$	1,423
Net Income Attributable to DTE Energy Company (1)	$	176	$	202	$	183	$	150	$	711
Basic Earnings per Share	$	1.04	$	1.19	$	1.08	$	.88	$	4.19
Diluted Earnings per Share	$	1.04	$	1.19	$	1.07	$	.88	$	4.18

2010
Operating Revenues	$	2,453	$	1,792	$	2,139	$	2,173	$	8,557
Operating Income	$	472	$	256	$	386	$	350	$	1,464
Net Income Attributable to DTE Energy Company	$	229	$	86	$	163	$	152	$	630
Basic Earnings per Share	$	1.38	$	.51	$	.97	$	.90	$	3.75
Diluted Earnings per Share	$	1.38	$	.51	$	.96	$	.90	$	3.74

(1) Includes an income tax benefit of $87 million relating to the enactment of the MCIT in the second quarter of 2011.

117

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

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 2012 Annual Meeting of Shareholders to be held May 3, 2012. 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.

Part IV

Item 15. Exhibits and Financial Statement Schedules

	(i) Exhibits filed herewith:
12-49	Computation of Ratio of Earnings to Fixed Charges.
21-7	Subsidiaries of the Company.
23-25	Consent of PricewaterhouseCoopers LLP.
31-71	Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report.
31-72	Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Database
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

	(ii) Exhibits incorporated herein by reference:
3(a)	Amended and Restated Articles of Incorporation of DTE Energy Company, dated December 13, 1995 and as amended from time to time (Exhibit 3-1 to Form 8-K dated May 6, 2010).

118

3(b)	Amended Bylaws of DTE Energy Company, as amended through May 5, 2011 (Exhibit 3-11 to Form 10-Q for the quarter ended September 30, 2011).
4(a)	Amended and Restated Indenture, dated as of April 9, 2001, between DTE Energy Company and The Bank of New York, as trustee (Exhibit 4.1 to Registration Statement on Form S-3 (File No. 333-58834)).
	Supplemental Indenture, dated as of April 1, 2003, between DTE Energy Company and The Bank of New York, as trustee, creating 2003 Series A 63/8% Senior Notes due 2033 (Exhibit 4(o) to Form 10-Q for the quarter ended March 31, 2003). (2003 Series A 63/8% Senior Notes due 2033).
	Supplemental Indenture, dated as of May 15, 2006, between DTE Energy Company and The 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).
	Supplemental Indenture, dated as of May 1, 2009, between DTE Energy Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-1 to Form 8-K dated May 13, 2009). (2009 Series A 7.625% Senior Notes due 2014).
	Supplemental Indenture dated as of May 15, 2011, between DTE Energy Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-269 to Form 10-Q for the quarter ended June 30, 2011). (2011 Series C Floating Rate Notes due 2013).
	Supplemental Indenture, dated as of December 1, 2011, between DTE Energy Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-274 to Form 8-K dated December 7, 2011). (2011 Series I 6.50% Junior Subordinated Debentures due 2061).
4(b)	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(c)	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(d)	Trust Agreement of DTE Energy Trust III (Exhibit 4-21 to Registration Statement on Form S-3(File No. 333-99955).
4(e)	Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-1 to Detroit Edison's Registration Statement on Form A-2 (File No. 2-1630)) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below:
	Supplemental Indenture, dated as of December 1, 1940, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-14 to Detroit Edison's Registration Statement on Form A-2 (File No. 2-4609)). (amendment)
	Supplemental Indenture, dated as of September 1, 1947, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-20 to Detroit Edison's Registration Statement on Form S-1 (File No. 2-7136)). (amendment)
	Supplemental Indenture, dated as of March 1, 1950, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-22 to Detroit Edison's Registration Statement on Form S-1 (File No. 2-8290)). (amendment)
	Supplemental Indenture, dated as of November 15, 1951, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-23 to Detroit Edison's Registration Statement on Form S-1 (File No. 2-9226)). (amendment)
	Supplemental Indenture, dated as of August 15, 1957, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 3-B-30 to Detroit Edison's Form 8-K dated September 11, 1957). (amendment)
	Supplemental Indenture, dated as of December 1, 1966, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 2-B-32 to Detroit Edison's Registration Statement on Form S-9 (File No. 2-25664)). (amendment)

119

Supplemental Indenture, dated as of February 15, 1990, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-212 to Detroit Edison's Form 10-K for the year ended December 31, 2000). (1990 Series B, C, E and F)

Supplemental Indenture, dated as of May 1, 1991, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-178 to Detroit Edison's Form 10-K for the year ended December 31, 1996). (1991 Series BP and CP)

Supplemental Indenture, dated as of May 15, 1991, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-179 to Detroit Edison's Form 10-K for the year ended December 31, 1996). (1991 Series DP)

Supplemental Indenture, dated as of February 29, 1992, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-187 to Detroit Edison's Form 10-Q for the quarter ended March 31, 1998). (1992 Series AP)

Supplemental Indenture, dated as of April 26, 1993, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-215 to Detroit Edison's Form 10-K for the year ended December 31, 2000). (amendment)

Supplemental Indenture, dated as of August 1, 2000, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-210 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2000). (2000 Series BP)

Supplemental Indenture, dated as of September 17, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Detroit Edison's Registration Statement on Form S-3 (File No. 333-100000)). (amendment and successor trustee)

Supplemental Indenture, dated as of October 15, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-230 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2002). (2002 Series A and B)

Supplemental Indenture, dated as of December 1, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-232 to Detroit Edison's Form 10-K for the year ended December 31, 2002). (2002 Series C and D)

Supplemental Indenture, dated as of August 1, 2003, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-235 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2003). (2003 Series A)

Supplemental Indenture, dated as of March 15, 2004, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-238 to Detroit Edison's Form 10-Q for the quarter ended March 31, 2004). (2004 Series A and B)

Supplemental Indenture, dated as of July 1, 2004, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-240 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2004). (2004 Series D)

Supplemental Indenture, dated as of April 1, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between Detroit Edison and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.3 to Detroit Edison's Registration Statement on Form S-4(File No. 333-123926)). (2005 Series AR and BR)

Supplemental Indenture, dated as of September 15, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.2 to Detroit Edison's Form 8-K dated September 29, 2005). (2005 Series C)

120

Supplemental Indenture, dated as of September 30, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between Detroit Edison and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-248 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2005). (2005 Series E)

Supplemental Indenture, dated as of May 15, 2006, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-250 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2006). (2006 Series A)

Supplemental Indenture, dated as of May 1, 2008 to Mortgage and Deed of Trust, dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-253 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2008). (2008 Series ET).

Supplemental Indenture, dated as of June 1, 2008 to Mortgage and Deed of Trust, dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-255 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2008). (2008 Series G)

Supplemental Indenture, dated as of July 1, 2008 to Mortgage and Deed of Trust, dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-257 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2008). (2008 Series KT)

Supplemental Indenture, dated as of October 1, 2008 to Mortgage and Deed of Trust, dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company N.A. as successor trustee (Exhibit 4-259 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2008). (2008 Series J)

Supplemental Indenture, dated as of December 1, 2008 to Mortgage and Deed of Trust, dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company N.A., as successor trustee (Exhibit 4-261 to Detroit Edison's Form 10-K for the year ended December 31, 2008). (2008 Series LT)

Supplemental Indenture, dated as of March 15, 2009 to Mortgage and Deed of Trust, dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company N.A., as successor trustee (Exhibit 4-263 to Detroit Edison's Form 10-Q for the quarter ended March 31, 2009). (2009 Series BT)

Supplemental Indenture, dated as of November 1, 2009 to Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company N.A., as successor trustee (Exhibit 4-267 to Detroit Edison's Form 10-K for the year ended December 31, 2009). (2009 Series CT)

Supplemental Indenture, dated as of August 1, 2010, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-269 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2010). (2010 Series B)

Supplemental Indenture, dated as of September 1, 2010, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-271 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2010). (2010 Series A)

Supplemental Indenture, dated as of December 1, 2010, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-273 to Detroit Edison's Form 10-K for the year ended December 31, 2010). (2010 Series CT)

Supplemental Indenture, dated as of March 1, 2011, to the Mortgage and Deed of Trust, dated as of October 1, 1924, by and between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-274 to Detroit Edison's Form 10-Q for the quarter ended March 31, 2011). (2011 Series AT) 

Supplemental Indenture, dated as of May 15, 2011, to the Mortgage and Deed of Trust, dated as of October 1, 1924, by and between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-275 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2011). (2011 Series B)

Supplemental Indenture, dated as of August 1, 2011, to the Mortgage and Deed of Trust, dated as of October 1, 1924, by and between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-276 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2011). (2011 Series GT)

121

	Supplemental Indenture, dated as of August 15, 2011, to the Mortgage and Deed of Trust, dated as of October 1, 1924, by and between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-277 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2011). (2011 Series D, 2011 Series E, 2011 Series F)
	Supplemental Indenture, dated as of September 1, 2011, to the Mortgage and Deed of Trust, dated as of October 1, 1924, by and between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-278 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2011). (2011 Series H)
4(f)	Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-152 to Detroit Edison's Registration Statement (File No. 33-50325)) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below:
	Tenth Supplemental Indenture, dated as of October 23, 2002, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-231 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2002). (5.20% Senior Notes due 2012 and 6.35% Senior Notes due 2032)
	Eleventh Supplemental Indenture, dated as of December 1, 2002, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-233 to Detroit Edison's Form 10-Q for the quarter ended March 31, 2003). (5.45% Senior Notes due 2032 and 5.25% Senior Notes due 2032)
	Twelfth Supplemental Indenture, dated as of August 1, 2003, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-236 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2003). (51/2% Senior Notes due 2030)
	Thirteenth Supplemental Indenture, dated as of April 1, 2004, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-237 to Detroit Edison's Form 10-Q for the quarter ended March 31, 2004). (4.875% Senior Notes Due 2029 and 4.65% Senior Notes due 2028)
	Fourteenth Supplemental Indenture, dated as of July 15, 2004, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-239 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2004). (2004 Series D 5.40% Senior Notes due 2014)
	Sixteenth Supplemental Indenture, dated as of April 1, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Detroit Edison's Registration Statement on Form S-4 (File No. 333-123926)). (2005 Series AR 4.80% Senior Notes due 2015 and 2005 Series BR 5.45% Senior Notes due 2035)
	Eighteenth Supplemental Indenture, dated as of September 15, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Detroit Edison's Form 8-K dated September 29, 2005). (2005 Series C 5.19% Senior Notes due October 1, 2023)
	Nineteenth Supplemental Indenture, dated as of September 30, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-247 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2005). (2005 Series E 5.70% Senior Notes due 2037)
	Twentieth Supplemental Indenture, dated as of May 15, 2006, to the Collateral Trust Indenture dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-249 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2006). (2006 Series A Senior Notes due 2036)
	Twenty-second Supplemental Indenture, dated as of December 1, 2007, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Detroit Edison's Form 8-K dated December 18, 2007). (2007 Series A Senior Notes due 2038)
	Twenty-fourth Supplemental Indenture, dated as of May 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-254 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2008). (2008 Series ET Variable Rate Senior Notes due 2029)

122

	Amendment dated June 1, 2009 to the Twenty-fourth Supplemental Indenture, dated as of May 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (2008 Series ET Variable Rate Senior Notes due 2029) (Exhibit 4-265 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2009)
	Twenty-fifth Supplemental Indenture, dated as of June 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-256 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2008). (2008 Series G 5.60% Senior Notes due 2018)
	Twenty-sixth Supplemental Indenture, dated as of July 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-258 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2008). (2008 Series KT Variable Rate Senior Notes due 2020)
	Amendment dated June 1, 2009 to the Twenty-sixth Supplemental Indenture, dated as of July 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-266 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2009) (2008 Series KT Variable Rate Senior Notes due 2020)
	Twenty-seventh Supplemental Indenture, dated as of October 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-260 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2008). (2008 Series J 6.40% Senior Notes due 2013)
	Twenty-eighth Supplemental Indenture, dated as of December 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-262 to Detroit Edison's Form 10-K for the year ended December 31, 2008). (2008 Series LT 6.75% Senior Notes due 2038)
	Twenty-ninth Supplemental Indenture, dated as of March 15, 2009, to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-264 to Detroit Edison's Form 10-Q for the quarter ended March 31, 2009). (2009 Series BT 6.00% Senior Notes due 2036)
	Thirtieth Supplemental Indenture, dated as of November 1, 2009, to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-268 to Detroit Edison's Form 10-K for the year ended December 31, 2009). (2009 Series CT Variable Rate Notes due 2024)
	Thirty-First Supplemental Indenture, dated as of August 1, 2010 to the Collateral Trust Indenture, dated as of June 1, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-270 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2010). (2010 Series B 3.45% Senior Notes due 2020)
	Thirty-Second Supplemental Indenture, dated as of September 1, 2010, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-272 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2010). (2010 Series A 4.89% Senior Notes due 2020)
4(g)	Trust Agreement of Detroit Edison Trust I (Exhibit 4.9 to Registration Statement on Form S-3(File No. 333-100000)).
4(h)	Trust Agreement of Detroit Edison Trust II (Exhibit 4.10 to Registration Statement on Form S-3(File No. 333-100000)).
4(i)	Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., as trustee, related to Senior Debt Securities (Exhibit 4-1 to Michigan Consolidated Gas Company Registration Statement on Form S-3 (File No. 333-63370)) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below:
	Fourth Supplemental Indenture dated as of February 15, 2003, to the Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-3 to Michigan Consolidated Gas Company Form 10-Q for the quarter ended March 31, 2003). (5.70% Senior Notes, 2003 Series A due 2033)
	Fifth Supplemental Indenture dated as of October 1, 2004, to the Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-6 to Michigan Consolidated Gas Company Form 10-Q for the quarter ended September 31, 2004). (5.00% Senior Notes, 2004 Series E due 2019)

123

	Sixth Supplemental Indenture dated as of April 1, 2008, to the Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-241 to Form 10-Q for the quarter ended March 31, 2008). (5.26% Senior Notes, 2008 Series A due 2013, 6.04% Senior Notes, 2008 Series B due 2018 and 6.44% Senior Notes, 2008 Series C due 2023).
	Seventh Supplemental Indenture, dated as of June 1, 2008 to Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-243 to Form 10-Q for the quarter ended June 30, 2008). (6.78% Senior Notes, 2008 Series F due 2028)
	Eighth Supplemental Indenture, dated as of August 1, 2008 to Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-251 to Form 10-Q for the quarter ended September 30, 2008). (5.94% Senior Notes, 2008 Series H due 2015 and 6.36% Senior Notes, 2008 Series I due 2020)
4(j)	Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 (Exhibit 7-D to Michigan Consolidated Gas Company Registration Statement No. 2-5252) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below:
	Thirty-second Supplemental Indenture dated as of January 5, 1993 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-1 to Michigan Consolidated Gas Company Form 10-K for the year ended December 31, 1992). (First Mortgage Bonds Designated Secured Term Notes, Series B)
	Thirty-third Supplemental Indenture dated as of May 1, 1995 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-2 to Michigan Consolidated Gas Company Registration Statement on Form S-3(File No. 33-59093)). (First Mortgage Bonds Designated Secured Medium Term Notes, Series B)
	Thirty-fifth Supplemental Indenture dated as of June 18, 1998 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee, creating an issue of first mortgage bonds designated as collateral bonds (Exhibit 4-2 to Michigan Consolidated Gas Company Form 8-K dated June 18, 1998).
	Thirty-seventh Supplemental Indenture dated as of February 15, 2003 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-4 to Michigan Consolidated Gas Company Form 10-Q for the quarter ended March 31, 2003). (5.70% collateral bonds due 2033)
	Thirty-eighth Supplemental Indenture dated as of October 1, 2004 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-5 to Michigan Consolidated Gas Company Form 10-Q for the quarter ended September 31, 2004). (2004 Series E collateral bonds)
	Thirty-ninth Supplemental Indenture, dated as of April 1, 2008 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-240 to Form 10-Q for the quarter ended March 31, 2008). (2008 Series A, B and C Collateral Bonds)
	Fortieth Supplemental Indenture, dated as of June 1, 2008 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-242 to Form 10-Q for the quarter ended June 30, 2008). (2008 Series F Collateral Bonds)
	Forty-first Supplemental Indenture, dated as of August 1, 2008 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-250 to Form 10-Q for the quarter ended September 30, 2008). (2008 Series H and I Collateral Bonds)
10(a)	Form of Indemnification Agreement between DTE Energy Company and each of Gerard M. Anderson, Anthony F. Earley, Jr., Steven E. Kurmas, David E. Meador, Gerardo Norcia, Bruce D. Peterson, and non-employee Directors (Exhibit 10-1 to Form 8-K dated December 6, 2007).
10(b)	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(c)	Confidentiality and Non-Competition Agreement between DTE Energy Company and Anthony F. Earley, Jr. dated as of August 8, 2011 (Exhibit 10.1 to Form 8-K for the year ended August 8, 2011).
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).

124

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)	DTE Energy Company Annual Incentive Plan (Exhibit 10-44 to Form 10-Q for the quarter ended March 31, 2001).
10(h)	Amended and Restated DTE Energy Company 2006 Long-Term Incentive Plan (as Amended and Restated effective as of May 6, 2010) (Annex A to DTE Energy's Definitive Proxy Statement dated March 29, 2010).
10(i)	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(j)	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(k)	Description of Executive Life Insurance Plan (Exhibit 10-47 to Form 10-Q for the quarter ended June 30, 2002).
10(l)	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(m)	Form of Director Restricted Stock Agreement (Exhibit 10.1 to Form 8-K dated June 23, 2005).
10(n)	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(o)	DTE Energy Company Executive Supplemental Retirement Plan as Amended and Restated, effective as of January 1, 2005 (Exhibit 10.75 to Form 10-K for the year ended December 31, 2008).
	First Amendment to the DTE Energy Company Executive Supplemental Retirement Plan (Amended and Restated Effective January 1, 2005) dated as of December 2, 2009 (Exhibit 10.1 to Form 8-K dated December 8, 2009).
10(p)	DTE Energy Company Supplemental Retirement Plan as Amended and Restated, effective as of January 1, 2005 (Exhibit 10.76 to Form 10-K for the year ended December 31, 2008).
10(q)	DTE Energy Company Supplemental Savings Plan as Amended and Restated, effective as of January 1, 2005 (Exhibit 10.77 to Form 10-K for the year ended December 31, 2008).
10(r)	DTE Energy Company Executive Deferred Compensation Plan as Amended and Restated, effective as of January 1, 2005 (Exhibit 10.78 to Form 10-K for the year ended December 31, 2008).
10(s)	DTE Energy Company Plan for Deferring the Payment of Directors' Fees as Amended and Restated, effective as of January 1, 2005 (Exhibit 10.79 to Form 10-K for the year ended December 31, 2008).
10(t)	DTE Energy Company Deferred Stock Compensation Plan for Non-Employee Directors as Amended and Restated, effective January 1, 2005 (Exhibit 10.80 to Form 10-K for the year ended December 31, 2008).
10(u)	Form of Amended and Restated DTE Energy Five-Year Credit Agreement, dated as of August 20, 2010 and Amended and Restated as of October 21, 2011, by and among DTE Energy Company, the lenders party thereto, Citibank, N.A., as Administrative Agent, and Barclays Capital, The Bank of Nova Scotia and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.1 to Form 8-K dated October 21, 2011).
10(v)	Form of Amended and Restated MichCon Five-Year Credit Agreement, dated as of August 20, 2010 and Amended and Restated as of October 21, 2011, by and amongMichCon, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Barclays Capital, Citibank, N.A. and Bank of America, N.A., as Co-Syndication Agents (Exhibit 10.2 to Form 8-K dated October 21, 2011).
10(w)	Form of Amended and Restated Detroit Edison Five-Year Credit Agreement, dated as of August 20, 2010 and Amended and Restated as of October 21, 2011, by and among Detroit Edison, the lenders party thereto, Barclays Bank PLC, as Administrative Agent, and Citibank, N.A., JPMorgan Chase Bank, N.A., and The Royal Bank of Scotland plc, as Co-Syndication Agents (Exhibit 10.1 to DTE Energy Company's and Detroit Edison's Form 8-K dated October 21, 2011).
99(a)	Amendment and Restatement of Master Trust Agreement for the DTE Energy Company Master Plan Trust between DTE Energy Corporate Services, LLC and DTE Energy Investment Committee and JP Morgan Chase Bank, N.A., dated as of October 15, 2010.
	(iii) Exhibits furnished herewith:
32-71	Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report.
32-72	Chief Financial Officer Section 906 Form 10-K Certification of Periodic Report.

125

DTE Energy Company

Schedule II — Valuation and Qualifying Accounts

	Year Ending December 31,
	2011			2010			2009
	(In millions)
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statements of Financial Position)
Balance at Beginning of Period	$	196		$	262		$	265
Additions:
Charged to costs and expenses	94			113			155
Charged to other accounts (1)	18			20			17
Deductions (2)	(146		)	(199		)	(175		)
Balance at End of Period	$	162		$	196		$	262

_______________________________________

(1) Collection of accounts previously written off.

(2) Uncollectible accounts written off.

126

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)
By	/s/  GERARD M. ANDERSON
	Gerard M. Anderson Chairman of the Board, President and Chief Executive Officer

Date: February 16, 2012

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/  GERARD M. ANDERSON	By	/s/  CHARLES G. MCCLURE
	Gerard M. Anderson Chairman of the Board, President and Chief Executive Officer and Director		Charles G. McClure, Director
By	/s/  PETER B. OLEKSIAK	By	/s/  GAIL J. MCGOVERN
	Peter B. Oleksiak Vice President, Controller and Chief Accounting Officer		Gail J. McGovern, Director
By	/s/  LILLIAN BAUDER	By	/s/  EUGENE A. MILLER
	Lillian Bauder, Director		Eugene A. Miller, Director
By	/s/  DAVID A. BRANDON	By	/s/  MARK A. MURRAY
	David A. Brandon, Director		Mark A. Murray, Director
By	/s/  W. FRANK FOUNTAIN, JR.	By	/s/  CHARLES W. PRYOR, JR.
	W. Frank Fountain, Jr., Director		Charles W. Pryor, Jr., Director
By	/s/  FRANK M. HENNESSEY	By	/s/  JOSUE ROBLES, JR.
	Frank M. Hennessey, Director		Josue Robles, Jr., Director
By	/s/  JOHN E. LOBBIA	By	/s/  RUTH G. SHAW
	John E. Lobbia, Director		Ruth G. Shaw, Director
By	/s/  DAVID E. MEADOR	By	/s/  JAMES H. VANDENBERGHE
	David E. Meador Executive Vice President and Chief Financial Officer		James H. Vandenberghe, Director

Date: February 16, 2012

127

EX-12.49

Exhibit 12-49

DTE ENERGY COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
	Twelve Months Ended December 31
(Millions of Dollars)	2011	2010	2009	2008		2007
Earnings:
Pretax earnings	981	944	782	819		1,155
Adjustments	6	1	4	(3	)	(4	)
Fixed Charges	504	567	572	540		562
Net earnings	1,491	1,512	1,358	1,356		1,713
Fixed Charges:
Interest expense	490	543	545	503		533
Adjustments	14	24	27	37		29
Fixed Charges	504	567	572	540		562
Ratio of earnings to fixed charges	2.96	2.67	2.37	2.51		3.05

EX-21.7

Exhibit 21-7

SUBSIDIARIES OF DTE ENERGY COMPANY

DTE Energy Company’s principal subsidiaries as of December 31, 2011 are listed below. All other subsidiaries, if considered in the aggregate as a single subsidiary, would not constitute a significant subsidiary.

Subsidiary	State of Incorporation
1. The Detroit Edison Company	Michigan
2. DTE Energy Resources, Inc.	Michigan
3. DTE Enterprises, Inc.	Michigan
4. MichCon Holdings, Inc.	Michigan
5. Michigan Consolidated Gas Company	Michigan

EX-23.25

Exhibit 23-25

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S‑3 (Nos. 333-161489, 333-161489-01 and 333-157769) and Form S‑8 (Nos. 333-157768, 333-133645, 333-109623, 333-61992 and 333-47247) of DTE Energy Company of our report dated February 16, 2012 relating to the financial statements, financial statement schedule and the effectiveness of internal control over financial reporting, which appears in this Form 10‑K.

/s/ PricewaterhouseCoopers LLP

Detroit, Michigan

February 16, 2012

EX-31.71

Exhibit 31-71

FORM 10-K CERTIFICATION

I, Gerard M. Anderson, certify that:

1. I have reviewed this Annual Report on Form 10-K of DTE Energy Company;

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

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

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

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

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

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

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

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

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

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

/S/ GERARD M. ANDERSON	Date:	February 16, 2012
Gerard M. Anderson Chairman of the Board, President and Chief Executive Officer of DTE Energy Company

EX-31.72

Exhibit 31-72

FORM 10-K CERTIFICATION

I, David E. Meador, certify that:

1. I have reviewed this Annual Report on Form 10-K of DTE Energy Company;

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

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

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

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

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

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

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

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

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

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

/S/ DAVID E. MEADOR	Date:	February 16, 2012
David E. Meador Executive Vice President and Chief Financial Officer of DTE Energy Company

EX-32.71

Exhibit 32-71

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of DTE Energy Company (the “Company”) for the year ended December 31, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Gerard M. Anderson, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge and belief:

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

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

Date:	February 16, 2012	/S/ GERARD M. ANDERSON
		Gerard M. Anderson Chairman of the Board, President and Chief Executive Officer of DTE Energy Company

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.72

Exhibit 32-72

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of DTE Energy Company (the “Company”) for the year ended December 31, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David E. Meador, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge and belief:

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

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

Date:	February 16, 2012	/S/ DAVID E. MEADOR
		David E. Meador Executive Vice President and Chief Financial Officer of DTE Energy Company

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

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Goodwill (Tables)

12 Months Ended

Dec. 31, 2011

Goodwill [Abstract]

Schedule of Goodwill [Table Text Block]

	2011		2010
	(In millions)
Balance as of January 1	$	2,020	$	2,024
Goodwill attributable to sale of subsidiary in Power and Industrial Projects segment	—		(4		)
Balance at December 31	$	2,020	$	2,020

XML

Retirement Benefits and Trusteed Assets (Details 6) (Pension Plans, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 2,886	$ 2,913	$ 2,549
Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,469	1,402
Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	953	1,033
Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	464	478
Short-term investments [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	33	34
Short-term investments [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Short-term investments [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	33	34
Short-term investments [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Us Large Cap Equity Securities [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	680	724
Us Large Cap Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	640	686
Us Large Cap Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	40	38
Us Large Cap Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
US Small Cap and Mid Cap Equity Securities [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	164	189
US Small Cap and Mid Cap Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	159	181
US Small Cap and Mid Cap Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	5	8
US Small Cap and Mid Cap Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Non US Equity Securities [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	506	507
Non US Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	392	285
Non US Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	114	222
Non US Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fixed income securities [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	791	719
Fixed income securities [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	88	61
Fixed income securities [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	703	658
Fixed income securities [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Hedge Funds and Similar Investments [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	544	566
Hedge Funds and Similar Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	190	189
Hedge Funds and Similar Investments [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	58	73
Hedge Funds and Similar Investments [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	296	304
Private Equity and Other [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	168	174
Private Equity and Other [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Private Equity and Other [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Private Equity and Other [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 168	$ 174

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2011

Segment Reporting [Abstract]

Inter segment billing for goods and services [Table Text Block]

	2011			2010			2009
	(In millions)
Electric Utility	$	33		$	30		$	28
Gas Utility	2			—			2
Gas Storage and Pipelines	8			4			5
Power and Industrial Projects	238			161			11
Energy Trading	70			89			93
Corporate and Other	(50		)	(65		)	(74		)
	$	301		$	219		$	65

Schedule of Segment Reporting Information, by Segment [Table Text Block]

Financial data of the business segments follows:

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income Attributable to DTE Energy Company			Total Assets		Goodwill		Capital Expenditures
	(In millions)
2011
Electric Utility	$	5,154		$	818	$	(1	)	$	289		$	265		$	434		$	17,370	$	1,208	$	1,203
Gas Utility	1,505			89		(7		)	64			60			110			3,933		745		179
Gas Storage and Pipelines	91			6		(5		)	7			35			57			421		22		16
Unconventional Gas Production	39			18		—			7			(3		)	(6		)	319		2		29
Power and Industrial Projects	1,129			60		(8		)	32			11			38			1,210		26		56
Energy Trading	1,276			3		—			9			34			52			552		17		1
Corporate and Other	4			1		(47		)	144			(134		)	26			2,204		—		—
Reconciliation and Eliminations	(301		)	—		58			(58		)	(1		)	—			—		—		—
Total	$	8,897		$	995	$	(10	)	$	494		$	267		$	711		$	26,009	$	2,020	$	1,484

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income Attributable to DTE Energy Company			Total Assets		Goodwill		Capital Expenditures
	(In millions)
2010
Electric Utility	$	4,993		$	849	$	(1	)	$	313		$	270		$	441		$	16,375	$	1,206	$	864
Gas Utility	1,648			92		(9		)	66			67			127			3,854		759		147
Gas Storage and Pipelines	83			5		(1		)	6			32			51			391		9		5
Unconventional Gas Production	32			15		—			6			(6		)	(11		)	308		2		27
Power and Industrial Projects	1,144			60		(3		)	33			3			85			1,236		27		53
Energy Trading	875			5		—			13			5			6			483		17		1
Corporate and Other	1			1		(47		)	160			(60		)	(69		)	2,249		—		—
Reconciliation and Eliminations	(219		)	—		49			(48		)	—			—			—		—		—
Total	$	8,557		$	1,027	$	(12	)	$	549		$	311		$	630		$	24,896	$	2,020	$	1,097

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income Attributable to DTE Energy Company			Total Assets		Goodwill		Capital Expenditures
	(In millions)
2009
Electric Utility	$	4,714		$	844	$	(1	)	$	324		$	228		$	376		$	15,879	$	1,206	$	794
Gas Utility	1,788			107		(8		)	68			39			80			3,832		759		166
Gas Storage and Pipelines	82			5		(1		)	10			33			49			367		9		2
Unconventional Gas Production	31			16		—			6			(4		)	(9		)	309		2		26
Power and Industrial Projects	661			40		(3		)	30			(7		)	31			1,118		31		45
Energy Trading	804			5		(1		)	10			37			75			552		17		2
Corporate & Other	—			3		(55		)	147			(79		)	(70		)	2,138		—		—
Reconciliation and Eliminations	(66		)	—		50			(50		)	—			—			—		—		—
Total	$	8,014		$	1,020	$	(19	)	$	545		$	247		$	532		$	24,195	$	2,024	$	1,035

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Short-Term Credit Arrangements and Borrowings (Tables)

12 Months Ended

Dec. 31, 2011

Short-Term Credit Arrangements and Borrowings [Abstract]

Schedule of Short-term Debt [Table Text Block]

	DTE Energy		Detroit Edison		MichCon		Total
	(In millions)
Unsecured letter of credit facility, expiring in December 2012	$	—	$	40	$	—	$	40
Unsecured letter of credit facility, expiring in May 2013	50		—		—		50
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Unsecured revolving credit facility, expiring October 2016	1,100		300		400		1,800
Total credit facilities at December 31, 2011	$	1,275	$	340	$	400	$	2,015
Amounts outstanding at December 31, 2011:
Commercial paper issuances	234		—		185		419
Letters of credit	178		40		—		218
	412		40		185		637
Net availability at December 31, 2011	$	863	$	300	$	215	$	1,378

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Retirement Benefits and Trusteed Assets Retirement Benefits and Trusteed Assets (Details 15) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	$ 59	$ 24
Realized gains (losses)	87	69
Unrealized gains (losses)		6
Purchases	3
Purchases, issuances and settlements		(87)
Ending Balance	44	59
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	75	(9)
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	134	138
Realized gains (losses)	1
Unrealized gains (losses)	(20)
Purchases	116
Sales	(76)
Total realized/unrealized gains (losses)		18
Purchases, issuances and settlements		(22)
Ending Balance	155	134
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	(11)	13
Other Postretirement Benefit Plans, Defined Benefit [Member] | Hedge Funds and Similar Investments [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	79	92
Realized gains (losses)	(1)
Unrealized gains (losses)	2
Purchases	68
Sales	(53)
Total realized/unrealized gains (losses)		10
Purchases, issuances and settlements		(23)
Ending Balance	95	79
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	5	6
Other Postretirement Benefit Plans, Defined Benefit [Member] | Private Equity and Other [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	55	46
Realized gains (losses)	2
Unrealized gains (losses)	(22)
Purchases	48
Sales	(23)
Total realized/unrealized gains (losses)		8
Purchases, issuances and settlements		1
Ending Balance	60	55
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	(16)	7
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	478	644
Realized gains (losses)	2
Unrealized gains (losses)	(29)
Purchases	87
Sales	(74)
Total realized/unrealized gains (losses)		74
Purchases, issuances and settlements		(240)
Ending Balance	464	478
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	(24)	42
Pension Plans, Defined Benefit [Member] | Hedge Funds and Similar Investments [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	304	484
Realized gains (losses)	(4)
Unrealized gains (losses)	1
Purchases	64
Sales	(69)
Total realized/unrealized gains (losses)		51
Purchases, issuances and settlements		(231)
Ending Balance	296	304
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	4	29
Pension Plans, Defined Benefit [Member] | Private Equity and Other [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	174	160
Realized gains (losses)	6
Unrealized gains (losses)	(30)
Purchases	23
Sales	(5)
Total realized/unrealized gains (losses)		23
Purchases, issuances and settlements		(9)
Ending Balance	168	174
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	$ (28)	$ 13

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Financial and Other Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	$ 2,805	$ 2,848
Derivative Liability Fair Value Gross Liability	(2,811)	(2,936)
Derivative Assets, Current	222	131
Derivative Assets, Noncurrent	74	77
Derivative Liabilities, Current	158	142
Derivative Liabilities, Noncurrent	89	110
Estimate of Fair Value, Fair Value Disclosure [Member]
Derivatives designated as hedging instruments:
Derivative Assets, Current	2,272	2,011
Derivative Assets, Noncurrent	533	837
Derivative Liabilities, Current	(2,282)	(2,041)
Derivative Liabilities, Noncurrent	(529)	(895)
Derivative Asset [Member]
Derivatives designated as hedging instruments:
Derivative Assets, Current	2,272	2,011
Derivative Assets, Noncurrent	533	837
Derivative Liabilities [Member]
Derivatives designated as hedging instruments:
Derivative Liabilities, Current	(2,282)	(2,041)
Derivative Liabilities, Noncurrent	(529)	(895)
Counterparty Netting [Member]
Derivatives designated as hedging instruments:
Derivative Assets, Current	(2,050)	(1,871)
Derivative Assets, Noncurrent	(440)	(760)
Derivative Liabilities, Current	2,050	1,871
Derivative Liabilities, Noncurrent	440	760
Collateral Adjustment [Member]
Derivatives designated as hedging instruments:
Derivative Assets, Current	0	(9)
Derivative Assets, Noncurrent	(19)	0
Derivative Liabilities, Current	74	28
Derivative Liabilities, Noncurrent	0	25
Derivative [Member]
Derivatives designated as hedging instruments:
Derivative Assets, Current	222	131
Derivative Assets, Noncurrent	74	77
Derivative Liabilities, Current	(158)	(142)
Derivative Liabilities, Noncurrent	(89)	(110)
Designated as Hedging Instrument [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset		0
Derivative Liability Fair Value Gross Liability		(1)
Designated as Hedging Instrument [Member] | Interest rate contracts [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	0
Derivative Liability Fair Value Gross Liability	(1)
Not Designated as Hedging Instrument [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	2,805	2,848
Derivative Liability Fair Value Gross Liability	(2,810)	(2,935)
Not Designated as Hedging Instrument [Member] | Foreign currency exchange contracts [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	3	20
Derivative Liability Fair Value Gross Liability	(5)	(30)
Not Designated as Hedging Instrument [Member] | Natural Gas [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	2,024	1,986
Derivative Liability Fair Value Gross Liability	(2,080)	(2,118)
Not Designated as Hedging Instrument [Member] | Electricity [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	747	766
Derivative Liability Fair Value Gross Liability	(705)	(716)
Not Designated as Hedging Instrument [Member] | Other [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	31	76
Derivative Liability Fair Value Gross Liability	$ (20)	$ (71)

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Stock-Based Compensation (Details 1) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options outstanding at January 1, 2011	4,827,457
Granted	0
Exercised	(2,040,229)
Forfeitured and expired	(22,558)
Options outstanding at December 31, 2011	2,764,670
Options exercisable at December 31, 2011	2,098,184
Weighted Average Exercise Price Per Share - Options outstanding at January 1, 2011	$ 41.09
Weighted Average Exercise Price Per Share - Granted	$ 0
Weighted Average Exercise Price Per Share - Exercised	$ 40.83
Weighted Average Exercise Price Per Share - Forfeitured or expired	$ 43.44
Weighted Average Exercise Price Per Share - Options outstanding at December 31, 2011	$ 41.25
Weighted Average Exercise Price Per Share - Options exercisable at December 31, 2011	$ 42.42
Aggregate Intrinsic Value - Options outstanding at December 31, 2011	$ 29
Aggregate Intrinsic Value - Options exercisable at December 31, 2011	$ 19

XML

Supplementary Quarterly Financial Information (Unaudited ) (Tables)

12 Months Ended

Dec. 31, 2011

Supplementary Quarterly Financial Information (Unaudited) [Abstract]

Schedule of Quarterly Financial Information [Table Text Block]

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
	(In millions, except per share amounts)
2011
Operating Revenues	$	2,431	$	2,028	$	2,265	$	2,173	$	8,897
Operating Income	$	390	$	288	$	399	$	346	$	1,423
Net Income Attributable to DTE Energy Company (1)	$	176	$	202	$	183	$	150	$	711
Basic Earnings per Share	$	1.04	$	1.19	$	1.08	$	.88	$	4.19
Diluted Earnings per Share	$	1.04	$	1.19	$	1.07	$	.88	$	4.18

2010
Operating Revenues	$	2,453	$	1,792	$	2,139	$	2,173	$	8,557
Operating Income	$	472	$	256	$	386	$	350	$	1,464
Net Income Attributable to DTE Energy Company	$	229	$	86	$	163	$	152	$	630
Basic Earnings per Share	$	1.38	$	.51	$	.97	$	.90	$	3.75
Diluted Earnings per Share	$	1.38	$	.51	$	.96	$	.90	$	3.74

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Jointly Owned Utility Plant (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 facilities
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant Number of Plants	2
Belle River Unit 1 [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership interest	63.00%
Belle River [Member]
Jointly Owned Utility Plant Interests [Line Items]
Total plant capacity	1,270
Ownership interest	81.00%
Investment (in millions)	1,645
Accumulated depreciation (in millions)	943
Joint Owners Percentage of the Total Capacity Energy and Related Responsibilities	19.00%
Ludington [Member]
Jointly Owned Utility Plant Interests [Line Items]
Total plant capacity	1,872
Ownership interest	49.00%
Investment (in millions)	199
Accumulated depreciation (in millions)	158
Joint Owners Percentage of the Total Capacity Energy and Related Responsibilities	51.00%
Belle River Unit 2 [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership interest	75.00%

XML

Commitments and Contingencies (Details Textuals) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2011 employees	Dec. 31, 2011 weeks kWh years people employees	Dec. 31, 2010
Loss Contingencies [Line Items]
Environmental Capital Expenditures Through Current Year		$ 1,700,000,000
Environmental Capital Expenditures in Current Year		255,000,000
Environmental Capital Expenditures In Future Years	1,900,000,000
Possible Additional Capital Exepnditures for EPA Regulations		80,000,000	55,000,000
Minimum Amount of Years to Incur Additional Capital Expenditures		4
Maximum Amount of Years to Incur Additional Capital Expenditures		6
Period Gas Utility Can Amortize MGP Costs		10
Possible Environmental Capital Expenditures to Comply with Requirements		1,000,000
Capital Expenditures Over the Next Few Years		13,000,000
Number of Defendant Oil Power and Coal Companies In Domestic District Court on Basis of Which Company Named		24
Number of People In Country Claiming Business Activities Contributing to Global Warming Higher Temperatures and Storm Activity		400
Costs associated with relocating village and unspecified attorney's fees and expenses	400,000,000	400,000,000
Waiting Period of Policy		12
Insurance Coverage for Extra ExpenseWhen to Necessitate Power Plant when Unavailable		490,000,000
Period of Coverage of Policy for Extra Expenses		3
Primary Coverage		500,000,000
Coverage for Stabilization Decontamination Debris Removal Repair and Replacement of Property and Decommissioning		2,250,000,000
Combined Coverage Limit for Total Property Damage		2,750,000,000
NEIL Policies Against Terroism Loss		3,200,000,000
Amount per Event Loss Associated with Nuclear Power Plants		29,000,000
Maintenance of Public Liability Insurance for Nuclear Power Plants		375,000,000
Aggregate Limit of Liabilities Arises From Terroist Act Outside Scope of Trials Subject to One Industry		300,000,000
Deferred Premium Charged Leviied Against Each Licensed Nuclear Facility		117,500,000
Limit Deferred Premium Charges Per Year		17,500,000
Company Obligated to Pay DOE Fee of Fermi 2 Electricity Generated and Sold		1
Guarantee Obligations Maximum Exposure One	10,000,000	10,000,000
Performance Bonds Outstanding	23,000,000	23,000,000
Number of Represented Employees	5,000	5,000
Long-term Purchase Commitment, Amount		5,300,000,000
estimated future capital expenditures for current year	1,900,000,000	1,900,000,000
Electric Utility [Member]
Loss Contingencies [Line Items]
Number of Former MGP Sites		3
Accrued for remediation related to the sites	8,000,000	8,000,000	9,000,000
Gas Utility [Member]
Loss Contingencies [Line Items]
Number of Former MGP Sites		15
Accrued for remediation related to the sites	36,000,000	36,000,000	36,000,000
Synthetic Fuel [Member]
Loss Contingencies [Line Items]
Days Obligations will Survive After Expiration of All Applicable Statutes of Limiations	90	90
Guarantor Obligations, Maximum Exposure, Undiscounted	1,200,000,000	1,200,000,000
Emissions [Member]
Loss Contingencies [Line Items]
Days Obligations will Survive After Expiration of All Applicable Statutes of Limiations	90	90
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 0	$ 0

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2011

Long-term Debt, Unclassified [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]

	2011			2010
	(In millions)
Mortgage bonds, notes, and other
DTE Energy Debt, Unsecured
5.5% due 2013 to 2033	$	1,298		$	1,597
Detroit Edison Taxable Debt, Principally Secured
5.3% due 2012 to 2041	3,515			2,915
Detroit Edison Tax-Exempt Revenue Bonds (2)
5.1% due 2012 to 2038	893			1,283
MichCon Taxable Debt, Principally Secured
6.1% due 2012 to 2033	889			889
Other Long-Term Debt, Including Non-Recourse Debt	165			195
	6,760			6,879
Less amount due within one year	(355		)	(765		)
	$	6,405		$	6,114
Securitization bonds
6.5% due 2012 to 2015	$	643		$	793
Less amount due within one year	(164		)	(150		)
	$	479		$	643
Junior Subordinated Debentures
6.5% due 2061	$	280		$	—
Trust preferred-linked securities
7.8% due 2032	$	—		$	186
7.5% due 2044	—			103
	$	—		$	289

Schedule of Issued Debt [Table Text Block]

Company	Month Issued	Type	Interest Rate		Maturity	Amount
	(In millions)
Detroit Edison	April	Tax-Exempt Revenue Bonds (1)	2.35	%	2024	$	31
Detroit Edison	May	Mortgage Bonds (2)	3.90	%	2021	250
DTE Energy	May	Senior Notes (3)	Variable (4)		2013	300
Detroit Edison	September	Mortgage Bonds (5)	4.31	%	2023	102
Detroit Edison	September	Mortgage Bonds (5)	4.46	%	2026	77
Detroit Edison	September	Mortgage Bonds (5)	5.67	%	2041	46
Detroit Edison	September	Tax-Exempt Revenue Bonds (6)	2.13	%	2030	82
Detroit Edison	September	Mortgage Bonds (7)	4.50	%	2041	140
DTE Energy	December	Junior Subordinated Debentures (8)	6.50	%	2061	280
						$	1,308

Schedule of Extinguishment of Debt [Table Text Block]

Company	Month Retired	Type	Interest Rate	Maturity	Amount
	(In millions)
Detroit Edison	May	Tax-Exempt Revenue Bonds	6.95%	2011	$	26
DTE Energy	June	Senior Notes	7.05%	2011	600
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.55%	2029	118
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.65%	2029	67
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.65%	2029	40
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.45%	2029	140
DTE Energy	December	Trust Preferred-Linked Securities	7.80%	2032	186
DTE Energy	December	Trust Preferred-Linked Securities	7.50%	2044	103
					$	1,280

Schedule of Maturities of Long-term Debt [Table Text Block]

	2012		2013		2014		2015		2016		2017 and Thereafter		Total
	(In millions)
Amount to mature	$	519	$	811	$	892	$	476	$	465	$	4,530	$	7,693

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Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2011

Valuation and Qualifying Accounts [Abstract]

Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]

Valuation and Qualifying Accounts

	Year Ending December 31,
	2011			2010			2009
	(In millions)
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statements of Financial Position)
Balance at Beginning of Period	$	196		$	262		$	265
Additions:
Charged to costs and expenses	94			113			155
Charged to other accounts (1)	18			20			17
Deductions (2)	(146		)	(199		)	(175		)
Balance at End of Period	$	162		$	196		$	262

_______________________________________

(1) Collection of accounts previously written off.

(2) Uncollectible accounts written off.

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Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2011	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010
Asset Retirement Obligations [Line Items]
Asset retirement obligations at January 1, 2011	$ 1,514	$ 1,514	$ 1,514
Accretion			93
Liabilities incurred			10
Liabilities settled			(23)
Revision in estimated cash flows	19	20	(1)	22
Asset retirement obligations at December 31, 2011			1,593	1,514
Less amount included in current liabilities			(2)
Asset retirement obligations, net			$ 1,591	$ 1,498

XML

Retirement Benefits and Trusteed Assets (Details 12) (Other Postretirement Benefit Plans, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2011
Other Postretirement Benefit Plans, Defined Benefit [Member]
Benefits Expected to be Paid Over the Next Five Years and Thereafter [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in 2012	$ 109
Defined Benefit Plan, Expected Future Benefit Payments in 2013	116
Defined Benefit Plan, Expected Future Benefit Payments in 2014	124
Defined Benefit Plan, Expected Future Benefit Payments in 2015	132
Defined Benefit Plan, Expected Future Benefit Payments in 2016	142
Defined Benefit Plan, Expected Future Benefit Payments in 2017-2021	839
Total Expected Future Benefit Payments	$ 1,462

XML

Stock-Based Compensation (Details 4) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Stock Award Activity [Line Items]
Restricted common shares awarded	621,114
Compensation cost charged against income (in millions)	$ 66	$ 52	$ 56
Restricted Stock [Member]
Stock Award Activity [Line Items]
Fair value of awards vested (in millions)	13	19	18
Restricted common shares awarded	381,840	238,405	523,660
Weighted average market price of shares awarded	$ 47.98	$ 44.08	$ 28.73
Compensation cost charged against income (in millions)	$ 12	$ 12	$ 18

XML

Supplemental Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$ 71	$ 79	$ 167
Inventories	(129)	(133)	28
Recoverable pension and postretirement costs	(620)	(32)	(19)
Accrued/prepaid pension costs	432	67	11
Accounts payable	(23)	12	(162)
Income taxes payable/receivable	249	(245)	43
Derivative assets and liabilities	(94)	(48)	(81)
Postretirement obligation	209	(24)	(147)
Other assets	9	(52)	58
Other liabilities	(10)	83	171
Total Changes in Assets and Liabilities, Exclusive of Changes Shown Separately	$ 94	$ (293)	$ 69

XML

Financial and Other Derivative Instruments (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Derivative [Line Items]
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	$ 1
Value of Transactions Company Would Have Been Exposed to if Credit Rating Below Investment Grade	315
FTR [Member]
Derivative [Line Items]
Derivative Instruments Recoverable Through PSCR Mechanism	3	6
Emissions [Member]
Derivative [Line Items]
Derivative Instruments Recoverable Through PSCR Mechanism		$ 1

XML

Income Taxes (Details Textuals) (USD $)	3 Months Ended	12 Months Ended
	Jun. 30, 2011 percent	Dec. 31, 2011 months	Dec. 31, 2010	Dec. 31, 2009	Jun. 30, 2010
Federal and State Income Tax [Line Items]
Production Tax Credits Earned In Prior Years But Not Utilized Carried Forward Indefinitely As Alternative Minimum Tax Credits		$ 294,000,000
Deferred Tax Assets State Net Operating Loss and Credit Carry Forwards 1		30,000,000	33,000,000
Valuation Allowance, Amount		27,000,000	32,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate		4,000,000	5,000,000
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit		31,000,000
Time Period of Unrecognized Tax Benefits that Would Impact Effective Tax Rate		12
Unrecognized Tax Benefits, Interest on Income Taxes Accrued		2,000,000	3,000,000
Unrecognized Tax Benefits, Income Tax Penalties Accrued		0
Unrecognized Tax Benefits, Interest on Income Taxes Expense		(2,000,000)	1,000,000	(2,000,000)
Unrecognized Tax Benefits, Increases Resulting from Prior Period Tax Positions			53,000,000
Michigan Corporate Income Tax	6.00%
Deferred Tax Liabilities Attributable to Regulated Utilities					36,000,000
Reduction of Net Deferred Tax Assets	0
Reduction of Net Deferred Tax Assets1	308,000,000
Decrease in Deferred Tax Liabilities Attributaable to Regulated Utilities	395,000,000
Income Tax Expense (Benefit)	87,000,000	267,000,000	311,000,000	247,000,000
Consistnet with Orginal Treatment of Deferred Tax Liabilities No Cash Flow Impact	$ 0

XML

Organization and Basis of Presentation (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Assets [Abstract]
Cash and cash equivalents	$ 68	$ 65	$ 52	$ 86
Restricted cash	147	120
Accounts receivable	1,317	1,351
Other current assets	196	197
Property, plant and equipment	13,746	12,992
Securitized regulatory assets	577	729
Other assets	199	206
Total Assets	26,009	24,896
Liabilities [Abstract]
Current portion long-term debt, including, capital leases	526	925
Other current liabilities	549	597
Mortgage bonds, notes and other	6,405	6,114
Securitization bonds	479	643
Capital lease obligations	23	43
Other long term liabilities	331	358
Variable Interest Entity Securitization [Member]
Assets [Abstract]
Cash and cash equivalents	0	0
Restricted cash	107	104
Accounts receivable	34	42
Inventories	0	0
Other current assets	0	0
Property, plant and equipment	0	0
Securitized regulatory assets	577	729
Other assets	10	13
Total Assets	728	888
Liabilities [Abstract]
Accounts payable and accrued current liabilities	14	17
Current portion long-term debt, including, capital leases	164	150
Other current liabilities	55	62
Mortgage bonds, notes and other	0	0
Securitization bonds	479	643
Capital lease obligations	0	0
Other long term liabilities	7	6
Total Liabilities	719	878
Variable Interest Entity, Primary Beneficiary [Member]
Assets [Abstract]
Cash and cash equivalents	25	4
Restricted cash	7	8
Accounts receivable	17	8
Inventories	183	99
Other current assets	1	1
Property, plant and equipment	73	54
Securitized regulatory assets	0	0
Other assets	6	9
Total Assets	312	183
Liabilities [Abstract]
Accounts payable and accrued current liabilities	24	27
Current portion long-term debt, including, capital leases	7	7
Other current liabilities	0	6
Mortgage bonds, notes and other	30	35
Securitization bonds	0	0
Capital lease obligations	14	23
Other long term liabilities	2	7
Total Liabilities	77	105
Consolidated Variable Interest Entity [Member]
Assets [Abstract]
Cash and cash equivalents	25	4
Restricted cash	114	112
Accounts receivable	51	50
Inventories	183	99
Other current assets	1	1
Property, plant and equipment	73	54
Securitized regulatory assets	577	729
Other assets	16	22
Total Assets	1,040	1,071
Liabilities [Abstract]
Accounts payable and accrued current liabilities	38	44
Current portion long-term debt, including, capital leases	171	157
Other current liabilities	55	68
Mortgage bonds, notes and other	30	35
Securitization bonds	479	643
Capital lease obligations	14	23
Other long term liabilities	9	13
Total Liabilities	796	983
Variable Interest Entity Restricted [Member]
Assets [Abstract]
Cash and cash equivalents	0	0
Restricted cash	114	112
Accounts receivable	36	44
Inventories	0	0
Other current assets	0	0
Property, plant and equipment	23	38
Securitized regulatory assets	577	729
Other assets	16	21
Total Assets	766	944
Liabilities [Abstract]
Accounts payable and accrued current liabilities	14	18
Current portion long-term debt, including, capital leases	171	157
Other current liabilities	55	66
Mortgage bonds, notes and other	30	35
Securitization bonds	479	643
Capital lease obligations	14	23
Other long term liabilities	8	12
Total Liabilities	$ 771	$ 954

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Retirement Benefits and Trusteed Assets (Details 3) (Pension Plans, Defined Benefit [Member])	12 Months Ended
	Dec. 31, 2011 percent	Dec. 31, 2010 percent	Dec. 31, 2009 percent
Pension Plans, Defined Benefit [Member]
Assumptions Used to Determin Projected Benefit Obligations and Net Pension Costs [Line Items]
Discount rate	5.00%	5.50%	5.90%
Rate of compensation increase	4.20%	4.00%	4.00%
Discount Rate	5.50%	5.90%	6.90%
Rate of compensation increase	4.00%	4.00%	4.00%
Expected long-term rate of return on plan assets	8.50%	8.75%	8.75%

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Supplemental Cash Flow Information (Details 1) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Other Significant Noncash Transactions [Line Items]
Interest (net of interest capitalized)	$ 485	$ 551	$ 550
Income taxes	(205)	93	18
Noncash financing activities: Common Stock issued for employee benefit plans	$ 1	$ 156	$ 47

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Property, Plant and Equipment (Details 1)	12 Months Ended
	Dec. 31, 2011
Electric Utility [Member]
Public Utility Property, Plant and Equipment [Line Items]
Generation Electric	46
Distribution	43
Gas Utility [Member]
Public Utility Property, Plant and Equipment [Line Items]
Distribution	62
Transmission Gas	61

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Income Taxes (Details 1) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income Tax Expense [Line Items]
Current Federal Tax Expense (Benefit)	$ 25	$ (172)	$ 25
Current State and Local Tax Expense (Benefit)	22	26	17
Current Income Tax Expense (Benefit)	47	(146)	42
Deferred Federal Income Tax Expense (Benefit)	318	415	182
Deferred State and Local Income Tax Expense (Benefit)	(98)	42	23
Deferred Income Tax Expense (Benefit)	220	457	205
Income Tax Expense (Benefit), Intraperiod Tax Allocation	$ 267	$ 311	$ 247

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Disposals and Discontinued Operations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Productive Assets	$ 23
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal	5
Goodwill, Written off Related to Sale of Business Unit	4
Gross Proceeds From Sale of Gathering and Processing Assets		45
Goodwill of Gathering and Processing Assets		$ 13

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Income Taxes (Details 2) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Deferred Tax Liability Not Recognized [Line Items]
Deferred Tax Liabilities, Property, Plant and Equipment	$ (3,131)	$ (2,558)
Deferred Tax Liabilities, Regulatory Assets	(360)	(396)
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	294	337
Deferred Tax Assets Merger Basis Differences	50	49
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits	(39)	(36)
Deferred Tax Assets, Other Comprehensive Loss	99	83
Deferred Tax Assets Liabilities Derivative	64	29
Deferred Tax Assets State Net Operating Loss and Credit Carry Forwards	30	33
Deferred Tax Assets, Other	(45)	(2)
Deferred Tax Assets Liabilities Gross	(3,038)	(2,461)
Deferred Tax Assets, Valuation Allowance	(27)	(32)
Deferred Tax Assets (Liabilities), Net	(3,065)	(2,493)
Deferred Tax Assets, Net, Current	51	139
Deferred Tax Liabilities, Noncurrent	(3,116)	(2,632)
Deferred Tax Assets, Net	1,048	1,418
Deferred Tax Liabilities	$ (4,113)	$ (3,911)

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Property, Plant and Equipment (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 years percent	Dec. 31, 2010	Dec. 31, 2009
Public Utility Property, Plant and Equipment [Line Items]
AFUDC capitalized	$ 10	$ 10
Property, Plant and Equipment, Useful Life, Minimum	3
Property, Plant and Equipment, Useful Life, Maximum	55
Finite-Lived Intangible Assets, Useful Life, Minimum	3
Finite-Lived Intangible Assets, Useful Life, Maximum	20
Capitalized Computer Software, Amortization	65	65	66
Capitalized Computer Software, Gross	623	602
Capitalized Computer Software, Accumulated Amortization	300	252
Capitalized Computer Software Future Amortization Expense	64
Capital Leased Assets, Gross	57	153
Capital Leases, Lessee Balance Sheet, Assets by Major Class, Accumulated Depreciation	$ 34	$ 114
Electric Utility [Member]
Public Utility Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	3.30%	3.30%	3.30%
Gas Utility [Member]
Public Utility Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.30%	2.50%	3.10%

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Financial and Other Derivative Instruments (Details 1) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 159	$ 123
Foreign currency exchange contracts [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(2)	(14)
Natural Gas [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	58	61
Natural Gas [Member] | Fuel, purchased power and gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(21)	(8)
Electricity [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	115	80
Other [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	9	9
Other [Member] | Operating and maintenance [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 0	$ (5)

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Short-Term Credit Arrangements and Borrowings

12 Months Ended

Dec. 31, 2011

Short-Term Credit Arrangements and Borrowings [Abstract]

SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

In October 2011, DTE Energy and its wholly owned subsidiaries, Detroit Edison and MichCon, entered into amended and restated five-year unsecured revolving credit agreements with a syndicate of 20 banks that may be used for general corporate borrowings, but are intended to provide liquidity support for each of the companies’ commercial paper programs. No one bank provides more than 8.5% of the commitment in any facility. Borrowings under the facilities are available at prevailing short-term interest rates. Additionally, DTE Energy has other facilities to support letter of credit issuance.

Detroit Edison entered into a one year $40 million letter of credit facility in December 2011. The facility was terminated early in January 2012 following cancellation of the letter of credit that it supported.

The above agreements require the Company to maintain a total funded debt to capitalization ratio of no more than 0.65 to 1. In the agreements, “total funded debt” means all indebtedness of the Company and its consolidated subsidiaries, including capital lease obligations, hedge agreements and guarantees of third parties’ debt, but excluding contingent obligations, nonrecourse and junior subordinated debt and certain equity-linked securities and, except for calculations at the end of the second quarter, certain MichCon short-term debt. “Capitalization” means the sum of (a) total funded debt plus (b) “consolidated net worth,” which is equal to consolidated total stockholders’ equity of the Company and its consolidated subsidiaries (excluding pension effects under certain FASB statements), as determined in accordance with accounting principles generally accepted in the United States of America. At December 31, 2011, the total funded debt to total capitalization ratios for DTE Energy, Detroit Edison and MichCon are 0.50 to 1, 0.52 to 1 and 0.45 to 1, respectively, and are in compliance with this financial covenant. The availability under these combined facilities at December 31, 2011 is shown in the following table:

	DTE Energy		Detroit Edison		MichCon		Total
	(In millions)
Unsecured letter of credit facility, expiring in December 2012	$	—	$	40	$	—	$	40
Unsecured letter of credit facility, expiring in May 2013	50		—		—		50
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Unsecured revolving credit facility, expiring October 2016	1,100		300		400		1,800
Total credit facilities at December 31, 2011	$	1,275	$	340	$	400	$	2,015
Amounts outstanding at December 31, 2011:
Commercial paper issuances	234		—		185		419
Letters of credit	178		40		—		218
	412		40		185		637
Net availability at December 31, 2011	$	863	$	300	$	215	$	1,378

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $39 million which are used for various corporate purposes.

The weighted average interest rate for short-term borrowings was 0.5% and 0.4% at December 31, 2011 and 2010, respectively.

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 $100 million with its clearing agent. The agreement, as amended, also allows for up to $50 million of additional margin financing provided that the Company posts a letter of credit for the incremental amount. At December 31, 2011, a $15 million letter of credit was in place, raising the capacity under this facility to $115 million. The $15 million letter of credit is included in the table above. The amount outstanding under this agreement was $56 million and $39 million at December 31, 2011 and December 31, 2010, respectively.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies [Abstract]

Long-term Purchase Commitment [Table Text Block]

	(In millions)
2012	$	2,276
2013	1,221
2014	732
2015	237
2016	109
2017 — 2051	740
	$	5,315

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

A reconciliation of the asset retirement obligations for 2011 follows:

	(In millions)
Asset retirement obligations at January 1, 2011	$	1,514
Accretion	93
Liabilities incurred	10
Liabilities settled	(23		)
Revision in estimated cash flows	(1		)
Asset retirement obligations at December 31, 2011	1,593
Less amount included in current liabilities	(2		)
	$	1,591

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Property, Plant and Equipment (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Electric Utility [Abstract]
Property Plant and Equipment Accumulated Depreciation Nonutility and Other	$ (688)	$ (525)
Gas Utility [Abstract]
Storage	406	395
Other	902	991
Storage	(127)	(108)
Other	(413)	(512)
Non-utility and other	1,884	1,660
Total	22,541	21,574
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	8,795	8,582
Net Property, Plant and Equipment	13,746	12,992
Electric Generation, Transmission and Distribution Equipment [Member]
Electric Utility [Abstract]
Generation	9,785	9,268
Distribution	7,003	6,800
Generation	(3,946)	(3,850)
Distribution	(2,580)	(2,568)
Total Electric Utility	(6,526)	(6,418)
Public Utilities, Property, Plant and Equipment, Plant in Service	16,788	16,068
Gas, Transmission and Distribution Equipment [Member]
Electric Utility [Abstract]
Distribution	2,561	2,460
Distribution	(1,041)	(1,019)
Total Electric Utility	(1,581)	(1,639)
Public Utilities, Property, Plant and Equipment, Plant in Service	$ 3,869	$ 3,846

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Long-Term Debt (Details Textuals)	12 Months Ended
	Dec. 31, 2011 years months percent
Debt Instrument [Line Items]
interest rate is reset every three months	3
Debt insrument on Variable Rate	70
Time Period Bonds were Remarketed for	5
Deferred Interest Penalty Percentage	6.50%

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Fair Value (Tables)

12 Months Ended

Dec. 31, 2011

Fair Value Disclosures [Abstract]

Assets and liabilities measured and recorded at fair value on a recurring basis

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2011:

	Level 1			Level 2			Level 3			Netting Adjustments (2)			Net Balance at December 31, 2011
	(In millions)
Assets:
Nuclear decommissioning trusts	$	577		$	360		$	—		$	—		$	937
Other investments (1)	57			54			—			—			111
Derivative assets:
Foreign currency exchange contracts	—			3			—			(3		)	—
Commodity Contracts:
Natural Gas	1,926			78			20			(1,991		)	33
Electricity	—			523			224			(490		)	257
Other	23			2			6			(25		)	6
Total derivative assets	1,949			606			250			(2,509		)	296
Total	$	2,583		$	1,020		$	250		$	(2,509	)	$	1,344
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(5	)	$	—		$	3		$	(2	)
Interest rate contracts	—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(1,940		)	(126		)	(14		)	1,976			(104		)
Electricity	—			(513		)	(192		)	565			(140		)
Other	(19		)	(1		)	—			20			—
Total derivative liabilities	(1,959		)	(646		)	(206		)	2,564			(247		)
Total	$	(1,959	)	$	(646	)	$	(206	)	$	2,564		$	(247	)
Net Assets as of December 31, 2011	$	624		$	374		$	44		$	55		$	1,097
Assets:
Current	$	1,571		$	520		$	181		$	(2,050	)	$	222
Noncurrent (3)	1,012			500			69			(459		)	1,122
Total Assets	$	2,583		$	1,020		$	250		$	(2,509	)	$	1,344
Liabilities:
Current	$	(1,603	)	$	(527	)	$	(152	)	$	2,124		$	(158	)
Noncurrent	(356		)	(119		)	(54		)	440			(89		)
Total Liabilities	$	(1,959	)	$	(646	)	$	(206	)	$	2,564		$	(247	)
Net Assets as of December 31, 2011	$	624		$	374		$	44		$	55		$	1,097

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2010:

	Level 1			Level 2			Level 3			Netting Adjustments (2)			Net Balance at December 31, 2010
	(In millions)
Assets:
Nuclear decommissioning trusts	$	599		$	340		$	—		$	—		$	939
Other investments (1)	56			55			—			—			111
Derivative assets:
Foreign currency exchange contracts	—			20			—			(20		)	—
Commodity Contracts:
Natural Gas	1,846			128			12			(1,960		)	26
Electricity	—			649			117			(589		)	177
Other	68			4			4			(71		)	5
Total derivative assets	1,914			801			133			(2,640		)	208
Total	$	2,569		$	1,196		$	133		$	(2,640	)	$	1,258
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(30	)	$	—		$	20		$	(10	)
Interest rate contracts	—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(1,844		)	(263		)	(11		)	1,955			(163		)
Electricity	—			(653		)	(63		)	643			(73		)
Other	(63		)	(8		)	—			66			(5		)
Total derivative liabilities	(1,907		)	(955		)	(74		)	2,684			(252		)
Total	$	(1,907	)	$	(955	)	$	(74	)	$	2,684		$	(252	)
Net Assets as of December 31, 2010	$	662		$	241		$	59		$	44		$	1,006
Assets:
Current	$	1,299		$	663		$	49		$	(1,880	)	$	131
Noncurrent (3)	1,270			533			84			(760		)	1,127
Total Assets	$	2,569		$	1,196		$	133		$	(2,640	)	$	1,258
Liabilities:
Current	$	(1,290	)	$	(730	)	$	(21	)	$	1,899		$	(142	)
Noncurrent	(617		)	(225		)	(53		)	785			(110		)
Total Liabilities	$	(1,907	)	$	(955	)	$	(74	)	$	2,684		$	(252	)
Net Assets as of December 31, 2010	$	662		$	241		$	59		$	44		$	1,006

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2011 and 2010:

	Year Ended December 31, 2011
	Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets as of January 1, 2011	$	1		$	54		$	4		$	59
Transfers into Level 3	—			4			—			4
Transfers out of Level 3	1			(25		)	—			(24		)
Total gains:
Included in earnings	7			77			3			87
Recorded in regulatory assets/liabilities	—			—			2			2
Purchases, issuances and settlements:
Purchases	—			3			—			3
Settlements	(3		)	(81		)	(3		)	(87		)
Net Assets as of December 31, 2011	$	6		$	32		$	6		$	44
The amount of total gains included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at December 31, 2011	$	8		$	65		$	2		$	75

	Year Ended December 31, 2010
	Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets as of January 1, 2010	$	2		$	19		$	3		$	24
Changes in fair value included in earnings	4			64			1			69
Changes in fair value recorded in regulatory assets/liabilities	—			—			6			6
Purchases, issuances and settlements	(8		)	(73		)	(6		)	(87		)
Transfers in/out of Level 3	3			44			—			47
Net Assets as of December 31, 2010	$	1		$	54		$	4		$	59
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at December 31, 2010	$	(4	)	$	(6	)	$	1		$	(9	)

Fair Value of Long Term Debt [Table Text Block]

	December 31, 2011						December 31, 2010
	Fair Value			Carrying Value			Fair Value			Carrying Value
Long-Term Debt	$	8.8	billion	$	7.7	billion	$	8.5	billion	$	8.0	billion

Fair Value of Nuclear Decommissioning Trust Fund Assets Text Block [Table]

	December 31 2011		December 31 2010
	(In millions)
Fermi 2	$	915	$	910
Fermi 1	3		3
Low level radioactive waste	19		26
Total	$	937	$	939

Schedule of Realized Gain (Loss) [Table Text Block]

	Year Ended December 31
	2011			2010			2009
	(In millions)
Realized gains	$	46		$	192		$	37
Realized losses	$	(38	)	$	(83	)	$	(55	)
Proceeds from sales of securities	$	80		$	377		$	295

Fair Value and Unrealized Gains for Nuclear Decommissioning Trust Fund Table [Table] [Table Text Block]

	Fair Value		Unrealized Gains
	(In millions)
As of December 31, 2011
Equity securities	$	533	$	80
Debt securities	385		22
Cash and cash equivalents	19		—
	$	937	$	102
As of December 31, 2010
Equity securities	$	572	$	77
Debt securities	361		11
Cash and cash equivalents	6		—
	$	939	$	88

Available-for-sale debt and equity securities

	December 31, 2011				December 31, 2010
(In millions)	Fair Value		Carrying value		Fair Value		Carrying Value
Cash equivalents	$	140	$	140	$	133	$	133
Equity securities	$	5	$	5	$	6	$	6

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Stock-Based Compensation (Tables)

3 Months Ended

12 Months Ended

Dec. 31, 2011

Dec. 31, 2011

STOCK-BASED COMPENSATION [Abstract]

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Table Text Block]

Stock-based compensation for the reporting periods is as follows:

	2011		2010		2009
	(In millions)
Stock-based compensation expense	$	66	$	52	$	56
Tax benefit	25		20		22
Stock-based compensation cost capitalized in property, plant and equipment	4		3		3

Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]

Stock option activity was as follows:

					(In millions)
	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value
Options outstanding at January 1, 2011	4,827,457		$	41.09
Granted	—		$	—
Exercised	(2,040,229	)	$	40.83
Forfeited or expired	(22,558	)	$	43.44
Options outstanding at December 31, 2011	2,764,670		$	41.25	$	29
Options exercisable at December 31, 2011	2,098,184		$	42.42	$	19

Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, by Exercise Price Range [Table Text Block]

The number, weighted average exercise price and weighted average remaining contractual life of options outstanding were as follows:

						Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)
					Number of Options
Range of Exercise Prices
$	27.00	—	$	38.00	417,633	$	27.80	7.16
$	38.01	—	$	42.00	723,662	$	41.04	3.11
$	42.01	—	$	45.00	1,272,117	$	44.04	5.64
$	45.01	—	$	50.00	351,258	$	47.60	4.81
					2,764,670	$	41.25	5.10

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]

	December 31
	2010		2009
Risk-free interest rate	2.91	%	2.04	%
Dividend yield	5.08	%	4.98	%
Expected volatility	22.96	%	27.88	%
Expected life	6	years	6	years

Schedule of Share-based Compensation, Restricted Stock Units Award Activity [Table Text Block]

Stock award activity for the periods ended December 31 was:

	2011		2010		2009
Fair value of awards vested (in millions)	$	13	$	19	$	18
Restricted common shares awarded	381,840		238,405		523,660
Weighted average market price of shares awarded	$	47.98	$	44.08	$	28.73
Compensation cost charged against income (in millions)	$	12	$	12	$	18

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block]

The following table summarizes the Company’s stock awards activity for the period ended December 31, 2011:

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at January 1, 2011	757,414		$	37.32
Grants	381,840		$	47.98
Forfeitures	(66,675	)	$	40.92
Vested and issued	(346,355	)	$	38.25
Balance at December 31, 2011	726,224		$	42.25

Share Based Compensation Expense [Table Text Block]

The Company recorded compensation expense as follows:

	2011		2010		2009
	(In millions)
Compensation expense	$	53	$	36	$	35
Cash settlements (1)	$	3	$	3	$	1
Stock settlements (1)	$	25	$	23	$	8

Summary of Performance Share Activity [Table Text Block]

The following table summarizes the Company’s performance share activity for the period ended December 31, 2011:

	Performance Shares
Balance at January 1, 2011	1,527,253
Grants	621,114
Forfeitures	(71,946	)
Payouts	(467,688	)
Balance at December 31, 2011	1,608,733

Schedule of Unrecognized Compensation Cost, Nonvested Awards [Table Text Block]

	Unrecognized Compensation Cost		Weighted Average to be Recognized
	(In millions)		(In years)
Options	$	1	0.76
Stock awards	15		1.12
Performance shares	34		1.48
	$	50	1.36

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Fair Value (Details 5) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Option, Quantitative Disclosures [Line Items]
Nuclear decommissioning trusts	$ 937	$ 939
Unrealized Gains	102	88
Equity securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Equity securities	533	572
Unrealized Gains	80	77
Debt securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Debt securities	385	361
Unrealized Gains	22	11
Cash and cash equivalents [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Cash and cash equivalents	19	6
Unrealized Gains	$ 0	$ 0

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Retirement Benefits and Trusteed Assets (Details 5) (Pension Plans, Defined Benefit [Member])	12 Months Ended
	Dec. 31, 2011 percent
Pension Plan Target Allocations of Plan Assets [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Debt Securities	25.00%
Defined Benefit Plan Target Allocation Percentage of Assets Hedged Funds and Similar Investments	20.00%
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	8.00%
Defined Benefit Plan Target Allocation Percentage of Assets Total	100.00%
Us Large Cap Equity Securities [Member]
Pension Plan Target Allocations of Plan Assets [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities	22.00%
US Small Cap and Mid Cap Equity Securities [Member]
Pension Plan Target Allocations of Plan Assets [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities	5.00%
Non US Equity Securities [Member]
Pension Plan Target Allocations of Plan Assets [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities	20.00%

XML

Significant Accounting Policies (Details 1) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Finite-Lived Intangible Assets [Line Items]
Emission Allowance	$ 9	$ 9
Renewable Energy Credits	27	17
Contract Intangible Assets	65	63
Intangible Assets, Gross	101	89
Less: Accumulated Amortization	28	22
Intangible Assets, Net	$ 73	$ 67

XML

Preferred and Preferenced Securities (Tables)

12 Months Ended

Dec. 31, 2011

Preferred and Preference Securities [Abstract]

Preferred and Preferenced Securities [Table Text Block]

As of December 31, 2011, the amount of authorized and unissued stock is as follows:

Company	Type of Stock	Par Value		Shares Authorized
DTE Energy	Preferred	$	—	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

XML

Organization and Basis of Presentation

12 Months Ended

Dec. 31, 2011

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

ORGANIZATION AND BASIS OF PRESENTATION

Corporate Structure

DTE Energy owns the following businesses:

• Detroit Edison, an electric utility engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan;

• MichCon, a natural gas utility engaged in the purchase, storage, transportation, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan and the sale of storage and transportation capacity; and

• Other businesses involved in 1) natural gas pipelines, gathering and storage; 2) unconventional gas and oil 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. Certain activities of Detroit Edison and MichCon, as well as various other aspects of businesses under DTE Energy are regulated by the FERC. In addition, the Company is regulated by other federal and state regulatory agencies including the NRC, the EPA and the MDEQ.

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

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.

Certain prior year balances were reclassified to match the current year’s financial statement presentation.

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.

Effective January 1, 2010, the Company adopted the provisions of ASU 2009-17, Amendments to FASB Interpretation 46(R). ASU 2009-17 changed the methodology for determining the primary beneficiary of a VIE from a quantitative risk and rewards-based model to a qualitative determination. There is no grandfathering of previous consolidation conclusions. As a result, the Company re-evaluated all prior VIE and primary beneficiary determinations. The requirements of ASU 2009-17 were adopted on a prospective basis.

The Company evaluates whether an entity is a VIE whenever reconsideration events occur. The Company consolidates VIEs for which it is the primary beneficiary. If the Company is not the primary beneficiary and an ownership interest is held, the VIE is accounted for under the equity method of accounting. When assessing the determination of the primary beneficiary, the Company considers all relevant facts and circumstances, including: the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb the expected losses and/or the right to receive the expected returns of the VIE. The Company performs ongoing reassessments of all VIEs to determine if the primary beneficiary status has changed.

Legal entities within the Company’s Power and Industrial Projects segment enter into long-term contractual arrangements with customers to supply energy-related products or services. The entities are generally designed to pass-through the commodity risk associated with these contracts to the customers, with the Company retaining operational and customer default risk. These entities generally are VIEs. In addition, the Company has interests in certain VIEs that we share control of all significant activities for those entities with our partners, and therefore are accounted for under the equity method.

The Company has variable interests in VIEs through certain of its long-term purchase contracts. As of December 31, 2011, the carrying amount of assets and liabilities in the Consolidated Statement of Financial Position that relate to its variable interests under long-term purchase contracts are predominately related to working capital accounts and generally represent the amounts owed by the Company for the deliveries associated with the current billing cycle under the contracts. The Company has not provided any form of financial support associated with these long-term contracts. There is no significant potential exposure to loss as a result of its variable interests through these long-term purchase contracts.

In 2001, Detroit Edison financed a regulatory asset related to Fermi 2 and certain other regulatory assets through the sale of rate reduction bonds by a wholly-owned special purpose entity, Securitization. Detroit Edison performs servicing activities including billing and collecting surcharge revenue for Securitization. This entity is a VIE, and is consolidated by the Company.

DTE Energy had interests in various unconsolidated trusts that were formed for the purpose of issuing preferred securities and lending the gross proceeds to the Company. DTE Energy reviewed these interests and determined they were VIEs, but the Company was not the primary beneficiary as it did not have variable interests in the trusts and therefore, the trusts were not consolidated by the Company. See Note 15.

The maximum risk exposure for consolidated VIEs is reflected on the Company’s Consolidated Statements of Financial Position. For non-consolidated VIEs, the maximum risk exposure is generally limited to its investment and amounts which it has guaranteed.

The following table summarizes the major balance sheet items for consolidated VIEs as of December 31, 2011and December 31, 2010. Amounts at December 31, 2011 for consolidated VIEs that are either (1) assets that can be used only to settle obligations of the VIE or (2) liabilities for which creditors do not have recourse to the general credit of the primary beneficiary are segregated in the restricted amounts column. VIEs, in which the Company holds a majority voting interest and is the primary beneficiary, that meet the definition of a business and whose assets can be used for purposes other than the settlement of the VIE’s obligations have been excluded from the table below.

	December 31, 2011
	Securitization		Other		Total		Restricted Amounts
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	25	$	25	$	—
Restricted cash	107		7		114		114
Accounts receivable	34		17		51		36
Inventories	—		183		183		—
Other current assets	—		1		1		—
Property, plant and equipment	—		73		73		23
Securitized regulatory assets	577		—		577		577
Other assets	10		6		16		16
	$	728	$	312	$	1,040	$	766
LIABILITIES
Accounts payable and accrued current liabilities	$	14	$	24	$	38	$	14
Current portion long-term debt, including capital leases	164		7		171		171
Other current liabilities	55		—		55		55
Mortgage bonds, notes and other	—		30		30		30
Securitization bonds	479		—		479		479
Capital lease obligations	—		14		14		14
Other long term liabilities	7		2		9		8
	$	719	$	77	$	796	$	771

	December 31, 2010
	Securitization		Other		Total		Restricted Amounts
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	4	$	4	$	—
Restricted cash	104		8		112		112
Accounts receivable	42		8		50		44
Inventories	—		99		99		—
Other current assets	—		1		1		—
Property, plant and equipment	—		54		54		38
Securitized regulatory assets	729		—		729		729
Other assets	13		9		22		21
	$	888	$	183	$	1,071	$	944
LIABILITIES
Accounts payable and accrued current liabilities	$	17	$	27	$	44	$	18
Current portion long-term debt, including capital leases	150		7		157		157
Other current liabilities	62		6		68		66
Mortgage bonds, notes and other	—		35		35		35
Securitization bonds	643		—		643		643
Capital lease obligations	—		23		23		23
Other long term liabilities	6		7		13		12
	$	878	$	105	$	983	$	954

Amounts for non-consolidated VIEs as of December 31, 2011 and December 31, 2010 are as follows:

	December 31, 2011		December 31, 2010
	(In millions)
Other investments	$	117	$	98
Notes receivable	7		6
Trust preferred — linked securities	—		289

XML

Valuation and Qualifying Accounts (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period	$ 196	$ 262	$ 265
Charged to cost and expenses	94	113	155
Charged to other accounts (1)	18	20	17
Deductions (2)	(146)	(199)	(175)
Balance at End of Period	$ 162	$ 196	$ 262

XML

Retirement Benefits and Trusteed Assets (Details 10) (USD $) In Millions, unless otherwise specified	1 Months Ended	12 Months Ended
	Jan. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Change in Accumulated PostRetirement Benefit Obligation [Line Items]
Consolidation of VIEs		$ 0	$ 19	$ 0
Regulatory Assets		4,853	4,158
Other Postretirement Benefit Plans, Defined Benefit [Member]
Change in Accumulated PostRetirement Benefit Obligation [Line Items]
Benefit obligation, beginning of year	2,470	2,305	2,151
Consolidation of VIEs		0	21
Service cost		64	61	59
Interest cost		121	125	133
Plan amendments		(4)	(79)
Actuarial loss		80	127
Medicare Part D subsidy		6	7
Benefits paid		(102)	(108)
Benefit obligation, end of year		2,470	2,305	2,151
Defined Benefit Plan, Fair Value of Plan Assets		985	1,029	864
Actual return on plan assets		(22)	108
Company contributions	140	111	160
Benefits paid		(133)	(103)
Funded status of the plans		(1,485)	(1,276)
Current liabilities		(1)	(1)
Noncurrent liabilities		(1,484)	(1,275)
Pension and Other Postretirement Defined Benefit Plans, Liabilities		(1,485)	(1,276)
Net actuarial loss		47	46
Prior serice cost (credit)		(20)	(28)
Net transition obligation		(1)	(2)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax		26	16
Net actuarial loss		835	692
Prior service cost		(60)	(74)
Net transition obligation		3	6
Regulatory Assets		$ 778	$ 624

XML

Fair Value (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Assets [Abstract]
Nuclear decommissioning trusts	$ 937	$ 939
Other investments	111	111
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	2,805	2,848
Derivative Assets	1,344	1,258
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(2,811)	(2,936)
Derivative Liabilities	(247)	(252)
Derivative Assets (Liabilities), at Fair Value, Net	1,097	1,006
Derivative Assets, Current	222	131
Derivative Assets, Noncurrent	74	77
Derivative Liabilities, Current	158	142
Derivative Liabilities, Noncurrent	89	110
Current Asset [Member]
Liabilities [Abstract]
Derivative Assets, Current	222	131
Non Current Asset [Member]
Liabilities [Abstract]
Derivative Assets, Noncurrent	1,122	1,127
Current Liability [Member]
Liabilities [Abstract]
Derivative Liabilities, Current	(158)	(142)
Noncurrent Liability [Member]
Liabilities [Abstract]
Derivative Liabilities, Noncurrent	(89)	(110)
Foreign currency exchange contracts [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(2)	(10)
Interest rate contracts [Member]
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(1)	(1)
Natural Gas [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	33	26
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(104)	(163)
Electricity [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	257	177
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(140)	(73)
Other [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	6	5
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	(5)
Total derivative assets [Member]
Derivative assets Abstract [Abstract]
Derivative Assets	296	208
Total derivative liabilities [Member]
Liabilities [Abstract]
Derivative Liabilities	(247)	(252)
Fair Value, Inputs, Level 1 [Member]
Assets [Abstract]
Nuclear decommissioning trusts	577	599
Other investments	57	56
Derivative assets Abstract [Abstract]
Derivative Assets	2,583	2,569
Liabilities [Abstract]
Derivative Liabilities	(1,959)	(1,907)
Derivative Assets (Liabilities), at Fair Value, Net	624	662
Derivative Assets, Current	1,571	1,299
Derivative Assets, Noncurrent	1,012	1,270
Derivative Liabilities, Current	(1,603)	(1,290)
Derivative Liabilities, Noncurrent	(356)	(617)
Fair Value, Inputs, Level 1 [Member] | Foreign currency exchange contracts [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Interest rate contracts [Member]
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Natural Gas [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	1,926	1,846
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(1,940)	(1,844)
Fair Value, Inputs, Level 1 [Member] | Electricity [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Other [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	23	68
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(19)	(63)
Fair Value, Inputs, Level 1 [Member] | Total derivative assets [Member]
Derivative assets Abstract [Abstract]
Derivative Assets	1,949	1,914
Fair Value, Inputs, Level 1 [Member] | Total derivative liabilities [Member]
Liabilities [Abstract]
Derivative Liabilities	(1,959)	(1,907)
Fair Value, Inputs, Level 2 [Member]
Assets [Abstract]
Nuclear decommissioning trusts	360	340
Other investments	54	55
Derivative assets Abstract [Abstract]
Derivative Assets	1,020	1,196
Liabilities [Abstract]
Derivative Liabilities	(646)	(955)
Derivative Assets (Liabilities), at Fair Value, Net	374	241
Derivative Assets, Current	520	663
Derivative Assets, Noncurrent	500	533
Derivative Liabilities, Current	(527)	(730)
Derivative Liabilities, Noncurrent	(119)	(225)
Fair Value, Inputs, Level 2 [Member] | Foreign currency exchange contracts [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	3	20
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(5)	(30)
Fair Value, Inputs, Level 2 [Member] | Interest rate contracts [Member]
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(1)	(1)
Fair Value, Inputs, Level 2 [Member] | Natural Gas [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	78	128
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(126)	(263)
Fair Value, Inputs, Level 2 [Member] | Electricity [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	523	649
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(513)	(653)
Fair Value, Inputs, Level 2 [Member] | Other [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	2	4
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(1)	(8)
Fair Value, Inputs, Level 2 [Member] | Total derivative assets [Member]
Derivative assets Abstract [Abstract]
Derivative Assets	606	801
Fair Value, Inputs, Level 2 [Member] | Total derivative liabilities [Member]
Liabilities [Abstract]
Derivative Liabilities	(646)	(955)
Fair Value, Inputs, Level 3 [Member]
Assets [Abstract]
Nuclear decommissioning trusts	0	0
Other investments	0	0
Derivative assets Abstract [Abstract]
Derivative Assets	250	133
Liabilities [Abstract]
Derivative Liabilities	(206)	(74)
Derivative Assets (Liabilities), at Fair Value, Net	44	59
Derivative Assets, Current	181	49
Derivative Assets, Noncurrent	69	84
Derivative Liabilities, Current	(152)	(21)
Derivative Liabilities, Noncurrent	(54)	(53)
Fair Value, Inputs, Level 3 [Member] | Foreign currency exchange contracts [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Interest rate contracts [Member]
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Natural Gas [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	20	12
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(14)	(11)
Fair Value, Inputs, Level 3 [Member] | Electricity [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	224	117
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(192)	(63)
Fair Value, Inputs, Level 3 [Member] | Other [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	6	4
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Total derivative assets [Member]
Derivative assets Abstract [Abstract]
Derivative Assets	250	133
Fair Value, Inputs, Level 3 [Member] | Total derivative liabilities [Member]
Liabilities [Abstract]
Derivative Liabilities	(206)	(74)
Netting Adjustments [Member]
Assets [Abstract]
Nuclear decommissioning trusts	0	0
Other investments	0	0
Derivative assets Abstract [Abstract]
Derivative Assets	(2,509)	(2,640)
Liabilities [Abstract]
Derivative Liabilities	2,564	2,684
Derivative Assets (Liabilities), at Fair Value, Net	55	44
Derivative Assets, Current	(2,050)	(1,880)
Derivative Assets, Noncurrent	(459)	(760)
Derivative Liabilities, Current	2,124	1,899
Derivative Liabilities, Noncurrent	440	785
Netting Adjustments [Member] | Foreign currency exchange contracts [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	(3)	(20)
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	3	20
Netting Adjustments [Member] | Interest rate contracts [Member]
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Netting Adjustments [Member] | Natural Gas [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	(1,991)	(1,960)
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	1,976	1,955
Netting Adjustments [Member] | Electricity [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	(490)	(589)
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	565	643
Netting Adjustments [Member] | Other [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	(25)	(71)
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	20	66
Netting Adjustments [Member] | Total derivative assets [Member]
Derivative assets Abstract [Abstract]
Derivative Assets	(2,509)	(2,640)
Netting Adjustments [Member] | Total derivative liabilities [Member]
Liabilities [Abstract]
Derivative Liabilities	$ 2,564	$ 2,684

XML

Stock Based-Compensation (Details 5) (USD $)	12 Months Ended
	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at January 1, 2011	757,414
Grants	381,840
Forfeitures	(66,675)
Vested and Issued	(346,355)
Balance at December 31, 2011	726,224
Weighted Average Grant Date Fair Value Per Share - Balance at January 1, 2011	$ 37.32
Weighted Average Grant Date Fair Value Per Share - Grants	$ 47.98
Weighted Average Grant Date Fair Value Per Share - Foreitures	$ 40.92
Weighted Average Grant Date Fair Value Per Share - Vested and issued	$ 38.25
Weighted Average Grant Date Fair Value Per Share - Balance at December 31, 2011	$ 42.25

XML

Segment Information (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	$ 301	$ 219	$ 65
Electric Utility [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	33	30	28
Gas Utility [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	2	0	2
Gas Storage and Pipelines [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	8	4	5
Power and Industrial Projects [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	238	161	11
Energy Trading [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	70	89	93
Corporate and Other [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	$ (50)	$ (65)	$ (74)

XML

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2011

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets and Liabilities [Table Text Block]

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

	2011			2010
	(In millions)
Assets
Recoverable pension and postretirement costs:
Pension	$	2,208		$	1,742
Postretirement costs	778			624
Asset retirement obligation	420			336
Recoverable Michigan income taxes	324			383
Recoverable income taxes related to securitized regulatory assets	316			400
Choice incentive mechanism	166			105
Accrued PSCR/GCR revenue	147			52
Cost to achieve Performance Excellence Process	116			137
Other recoverable income taxes	81			85
Unamortized loss on reacquired debt	64			65
Recoverable restoration expense	58			19
Deferred environmental costs	49			41
Recoverable uncollectible expense	42			90
Enterprise Business Systems costs	18			21
Recoverable revenue decoupling	18			5
Other	48			53
	4,853			4,158
Less amount included in current assets	(314		)	(100		)
	$	4,539		$	4,058
Securitized regulatory assets	$	577		$	729

	2011			2010
	(In millions)
Liabilities
Asset removal costs	$	419		$	479
Refundable Michigan income taxes	—			418
Renewable energy	192			125
Refundable revenue decoupling	127			47
Negative pension offset	120			129
Refundable income taxes	66			77
Energy Optimization	34			27
Refundable uncollectible expense	31			—
Accrued PSCR/GCR refund	26			8
Low Income Energy Efficiency Fund	26			—
Fermi 2 refueling outage	23			3
Refundable self implemented rates	1			52
Refundable costs under PA 141	—			33
Refundable restoration expense	—			15
Other	8			9
	1,073			1,422
Less amount included in current liabilities	(54		)	(94		)
	$	1,019		$	1,328

XML

Stock-Based Compensation

12 Months Ended

Dec. 31, 2011

Share-based Compensation [Abstract]

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION

The Company’s stock incentive program permits the grant of incentive stock options, non-qualifying stock options, stock awards, performance shares and performance units to employees and members of its Board of Directors. Key provisions of the stock incentive program are:

• 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.

The Company records compensation expense at fair value over the vesting period for all awards it grants.

Stock-based compensation for the reporting periods is as follows:

	2011		2010		2009
	(In millions)
Stock-based compensation expense	$	66	$	52	$	56
Tax benefit	25		20		22
Stock-based compensation cost capitalized in property, plant and equipment	4		3		3

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 vest ratably over a three-year period.

Stock option activity was as follows:

					(In millions)
	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value
Options outstanding at January 1, 2011	4,827,457		$	41.09
Granted	—		$	—
Exercised	(2,040,229	)	$	40.83
Forfeited or expired	(22,558	)	$	43.44
Options outstanding at December 31, 2011	2,764,670		$	41.25	$	29
Options exercisable at December 31, 2011	2,098,184		$	42.42	$	19

As of December 31, 2011, the weighted average remaining contractual life for the exercisable shares is 4.25 years. As of December 31, 2011, 666,486 options were non-vested. During 2011, 687,061 options vested.

The weighted average grant date fair value of options granted during 2010, and 2009 was $5.62 and $4.41, respectively. The intrinsic value of options exercised for the years ended December 31, 2011, 2010 and 2009 was $20 million, $9 million, and $3 million, respectively. Total option expense recognized during 2011, 2010 and 2009 was $2 million, $4 million and $3 million, respectively.

The number, weighted average exercise price and weighted average remaining contractual life of options outstanding were as follows:

						Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)
					Number of Options
Range of Exercise Prices
$	27.00	—	$	38.00	417,633	$	27.80	7.16
$	38.01	—	$	42.00	723,662	$	41.04	3.11
$	42.01	—	$	45.00	1,272,117	$	44.04	5.64
$	45.01	—	$	50.00	351,258	$	47.60	4.81
					2,764,670	$	41.25	5.10

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
	2010		2009
Risk-free interest rate	2.91	%	2.04	%
Dividend yield	5.08	%	4.98	%
Expected volatility	22.96	%	27.88	%
Expected life	6	years	6	years

The Company includes both historical and implied share-price volatility in option volatility. Implied volatility is derived from exchange traded options on DTE Energy common stock. The Company’s expected life estimate is based on historical data.

Stock Awards

Stock awards granted under the plan are restricted for varying periods, 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.

Stock award activity for the periods ended December 31 was:

	2011		2010		2009
Fair value of awards vested (in millions)	$	13	$	19	$	18
Restricted common shares awarded	381,840		238,405		523,660
Weighted average market price of shares awarded	$	47.98	$	44.08	$	28.73
Compensation cost charged against income (in millions)	$	12	$	12	$	18

The following table summarizes the Company’s stock awards activity for the period ended December 31, 2011:

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at January 1, 2011	757,414		$	37.32
Grants	381,840		$	47.98
Forfeitures	(66,675	)	$	40.92
Vested and issued	(346,355	)	$	38.25
Balance at December 31, 2011	726,224		$	42.25

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 closing stock price market value. The settlement of the award is based on the closing price at the settlement date.

The Company recorded compensation expense as follows:

	2011		2010		2009
	(In millions)
Compensation expense	$	53	$	36	$	35
Cash settlements (1)	$	3	$	3	$	1
Stock settlements (1)	$	25	$	23	$	8

_______________________________________

(1) Sum of cash and stock settlements approximates the intrinsic value of the liability.

During the vesting period, the recipient of a performance share award has no shareholder rights. However, for performance shares granted before 2010, recipients will be paid an amount equal to the dividend equivalent on such shares. Performance shares granted in 2010 or later will not be entitled to dividend equivalent payments before the performance shares granted are earned and vested. During the period beginning on the date the post-2009 performance shares are awarded and ending on the certification date of the performance objectives, the number of performance shares awarded will be increased, assuming full dividend reinvestment at the fair market value on the dividend payment date. The cumulative number of performance shares will be adjusted to determine the final payment bases on the performance objectives achieved. Performance share awards are nontransferable and are subject to risk of forfeiture.

The following table summarizes the Company’s performance share activity for the period ended December 31, 2011:

	Performance Shares
Balance at January 1, 2011	1,527,253
Grants	621,114
Forfeitures	(71,946	)
Payouts	(467,688	)
Balance at December 31, 2011	1,608,733

Unrecognized Compensation Costs

As of December 31, 2011, there was $50 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 1.36 years.

	Unrecognized Compensation Cost		Weighted Average to be Recognized
	(In millions)		(In years)
Options	$	1	0.76
Stock awards	15		1.12
Performance shares	34		1.48
	$	50	1.36

XML

Retirement Benefits and Trusteed Assets

12 Months Ended

Dec. 31, 2011

Pension and Other Postretirement Benefit Expense [Abstract]

RETIREMENT BENEFITS AND TRUSTEED ASSETS

RETIREMENT BENEFITS AND TRUSTEED ASSETS

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 pension costs by contributing amounts consistent with the Pension Protection Act of 2006 provisions and additional amounts when it deems appropriate. The Company contributed $200 million to its pension plans in 2011. At the discretion of management, and depending upon financial market conditions, we anticipate making up to a $240 million contribution to the pension plans in 2012.

Net pension cost includes the following components:

	2011			2010			2009
	(In millions)
Service cost	$	69		$	64		$	52
Interest cost	202			202			203
Expected return on plan assets	(246		)	(258		)	(255		)
Amortization of:
Net actuarial loss	142			100			52
Prior service cost	3			4			6
Special termination benefits	2			—			—
Net pension cost	$	172		$	112		$	58

	2011			2010
	(In millions)
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income
Net actuarial loss	$	619		$	166
Amortization of net actuarial loss	(142		)	(100		)
Amortization of prior service cost	(3		)	(4		)
Total recognized Regulatory assets and Other comprehensive income	$	474		$	62
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	646		$	174
Estimated amounts to be amortized from Regulatory assets and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year
Net actuarial loss	$	171		$	133
Prior service cost	—			3

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 Statements of Financial Position at December 31:

	2011			2010
	(In millions)
Accumulated benefit obligation, end of year	$	3,881		$	3,521
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	3,785		$	3,436
Consolidation of VIEs	—			82
Service cost	69			64
Interest cost	202			202
Actuarial loss	355			216
Special termination benefits	2			—
Benefits paid	(218		)	(215		)
Projected benefit obligation, end of year	$	4,195		$	3,785
Change in plan assets
Plan assets at fair value, beginning of year	$	2,913		$	2,549
Consolidation of VIEs	—			64
Actual return on plan assets	(18		)	309
Company contributions	209			206
Benefits paid	(218		)	(215		)
Plan assets at fair value, end of year	$	2,886		$	2,913
Funded status of the plans	$	(1,309	)	$	(872	)
Amount recorded as:
Current liabilities	$	(11	)	$	(6	)
Noncurrent liabilities	(1,298		)	(866		)
	$	(1,309	)	$	(872	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	202		$	195
Prior service (credit)	(3		)	(4		)
	$	199		$	191
Amounts recognized in Regulatory assets (see Note 11)
Net actuarial loss	$	2,201		$	1,730
Prior service cost	7			12
	$	2,208		$	1,742

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

	2011		2010		2009
Projected benefit obligation
Discount rate	5.00	%	5.50	%	5.90	%
Rate of compensation increase	4.20	%	4.00	%	4.00	%
Net pension costs
Discount rate	5.50	%	5.90	%	6.90	%
Rate of compensation increase	4.00	%	4.00	%	4.00	%
Expected long-term rate of return on plan assets	8.50	%	8.75	%	8.75	%

The Company employs a 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. As a result of this process, the Company is lowering its long-term rate of return assumptions for its pension and OPEB plans to 8.25% for 2012. The Company believes this rate is a reasonable assumption for the long-term rate of return on its plan assets for 2012 given its investment strategy.

At December 31, 2011, 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)
2012	$	240
2013	239
2014	244
2015	253
2016	260
2017-2021	1,439
	$	2,675

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, with consideration given to the liquidity needs of the plan. 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. Fixed income securities generally include corporate bonds of companies from diversified industries, mortgage-backed securities, and U.S. Treasuries. Other assets such as private equity and hedge funds are used 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/or 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.

Target allocations for plan assets as of December 31, 2011 are listed below:

U.S. Large Cap Equity Securities	22	%
U.S. Small Cap and Mid Cap Equity Securities	5
Non U.S. Equity Securities	20
Fixed Income Securities	25
Hedge Funds and Similar Investments	20
Private Equity and Other	8
	100	%

Fair Value Measurements at December 31, 2011(a)

	Level 1		Level 2		Level 3		Balance at December 31, 2011
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	33	$	—	$	33
Equity securities
U.S. Large Cap (c)	640		40		—		680
U.S. Small/Mid Cap (d)	159		5		—		164
Non U.S (e)	392		114		—		506
Fixed income securities (f)	88		703		—		791
Hedge Funds and Similar Investments (g)	190		58		296		544
Private Equity and Other (h)	—		—		168		168
Total	$	1,469	$	953	$	464	$	2,886

Fair Value Measurements at December 31, 2010(a)

	Level 1		Level 2		Level 3		Balance at December 31, 2010
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	34	$	—	$	34
Equity securities
U.S. Large Cap (c)	686		38		—		724
U.S. Small/Mid Cap (d)	181		8		—		189
Non U.S (e)	285		222		—		507
Fixed income securities (f)	61		658		—		719
Hedge Funds and Similar Investments (g)	189		73		304		566
Private Equity and Other (h)	—		—		174		174
Total	$	1,402	$	1,033	$	478	$	2,913

_______________________________________

(a) See Note 3 — Fair Value for a description of levels within the fair value hierarchy.

(b) This category predominantly represents certain short-term fixed income securities and money market investments that are managed in separate accounts or commingled funds. Pricing for investments in this category are obtained from quoted prices in actively traded markets or valuations from brokers or pricing services.

(c) This category comprises both actively and not actively managed portfolios that track the S&P 500 low cost equity index funds. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(d) This category represents portfolios of small and medium capitalization domestic equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(e) This category primarily consists of portfolios of non-U.S. developed and emerging market equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(f) This category includes corporate bonds from diversified industries, U.S. Treasuries, and mortgage-backed securities. Pricing for investments in this category is obtained from quoted prices in actively traded markets and quotations from broker or pricing services. Non-exchange traded securities and exchange-traded securities held in commingled funds are classified as Level 2 assets.

(g) This category utilizes a diversified group of strategies that attempt to capture financial market inefficiencies and includes publicly traded debt and equity, publicly traded mutual funds, commingled and limited partnership funds and non-exchange traded securities. Pricing for Level 1 and level 2 assets in this category is obtained from quoted prices in actively traded markets and quoted prices from broker or pricing services. Non-exchange traded securities held in commingled funds are classified as Level 2 assets. Valuations for some Level 3 assets in this category may be based on limited observable inputs as there may be little, if any, publicly available pricing.

(h) This category includes a diversified group of funds and strategies that primarily invests in private equity partnerships. This category also includes investments in timber and private mezzanine debt. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available pricing. Valuations for assets in this category may be based on discounted cash flow analyses, relevant publicly-traded comparables and comparable transactions.

The pension trust holds debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices in actively traded markets. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued based on underlying securities, using quoted prices in actively traded markets. Non-exchange traded fixed income securities are valued by the trustee based upon quotations available from brokers or pricing services. A primary price source is identified by asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustees challenge an assigned price and determine that another price source is considered to be preferable. DTE Energy has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, DTE Energy selectively corroborates the fair values of securities by comparison of market-based price sources.

Fair Value Measurements Using Significant Unobservable Inputs (Level 3):

	Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1, 2011	$	304		$	174		$	478
Total realized/unrealized gains (losses):
Realized gains (losses)	(4		)	6			2
Unrealized gains (losses)	1			(30		)	(29		)
Purchases, sales and settlements:
Purchases	64			23			87
Sales	(69		)	(5		)	(74		)
Ending Balance at December 31, 2011	$	296		$	168		$	464
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	4		$	(28	)	$	(24	)

	Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1, 2010	$	484		$	160		$	644
Total realized/unrealized gains (losses)	51			23			74
Purchases, sales and settlements	(231		)	(9		)	(240		)
Ending Balance at December 31, 2010	$	304		$	174		$	478
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	29		$	13		$	42

There were no transfers between Level 3 and Level 2 and there were no significant transfers between Level 2 and Level 1 in the years ended December 31, 2011 and 2010.

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 $35 million, $34 million, and $33 million in each of the years 2011, 2010, and 2009, respectively.

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) and 401(h) trusts exist for represented and non-represented employees. The Company contributed $111 million to its postretirement medical and life insurance benefit plans during 2011.

In January 2012, the Company contributed $140 million to its other postretirement benefit plans. At the discretion of management, the Company may make up to an additional $120 million contribution to its VEBA trusts in 2012.

Net postretirement cost includes the following components:

	2011			2010			2009
	(In millions)
Service cost	$	64		$	61		$	59
Interest cost	121			125			133
Expected return on plan assets	(94		)	(74		)	(55		)
Amortization of:
Net loss	55			54			72
Prior service (credit)	(26		)	(4		)	(6		)
Net transition obligation	2			2			2
Net postretirement cost	$	122		$	164		$	205

	2011			2010
	(In millions)
Other changes in plan assets and APBO recognized in Regulatory assets and Other comprehensive income
Net actuarial loss	$	195		$	93
Amortization of net actuarial loss	(55		)	(54		)
Prior service credit	(4		)	(79		)
Amortization of prior service credit	26			4
Amortization of transition asset	(2		)	(2		)
Total recognized in Regulatory assets and Other comprehensive income	$	160		$	(38	)
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	282		$	126
Estimated amounts to be amortized from Regulatory assets and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year
Net actuarial loss	$	78		$	59
Prior service credit	$	(27	)	$	(26	)
Net transition obligation	$	2		$	2

The following table reconciles the obligations, assets and funded status of the plans including amounts recorded as accrued postretirement cost in the Consolidated Statements of Financial Position at December 31:

	2011			2010
	(In millions)
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation, beginning of year	$	2,305		$	2,151
Consolidation of VIEs	—			21
Service cost	64			61
Interest cost	121			125
Plan amendments	(4		)	(79		)
Actuarial loss	80			127
Medicare Part D subsidy	6			7
Benefits paid	(102		)	(108		)
Accumulated postretirement benefit obligation, end of year	$	2,470		$	2,305
Change in plan assets
Plan assets at fair value, beginning of year	$	1,029		$	864
Actual return on plan assets	(22		)	108
Company contributions	111			160
Benefits paid	(133		)	(103		)
Plan assets at fair value, end of year	$	985		$	1,029
Funded status, end of year	$	(1,485	)	$	(1,276	)
Amount recorded as:
Current liabilities	$	(1	)	$	(1	)
Noncurrent liabilities	$	(1,484	)	$	(1,275	)
	$	(1,485	)	$	(1,276	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	47		$	46
Prior service credit	(20		)	(28		)
Net transition asset	(1		)	(2		)
	$	26		$	16
Amounts recognized in Regulatory assets (See Note 11)
Net actuarial loss	$	835		$	692
Prior service cost	(60		)	(74		)
Net transition obligation	3			6
	$	778		$	624

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

	2011		2010		2009
Projected benefit obligation
Discount rate	5.00	%	5.50	%	5.90	%
Net benefit costs
Discount rate	5.50	%	5.90	%	6.90	%
Expected long-term rate of return on plan assets	8.75	%	8.75	%	8.75	%
Health care trend rate pre- and post- 65	7.00	%	7.00	%	7.00	%
Ultimate health care trend rate	5.00	%	5.00	%	5.00	%
Year in which ultimate reached	2019		2016		2016

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 $35 million and increased the accumulated benefit obligation by $306 million at December 31, 2011. 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 $23 million and would have decreased the accumulated benefit obligation by $297 million at December 31, 2011.

At December 31, 2011, 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)
2012	$	109
2013	116
2014	124
2015	132
2016	142
2017 — 2021	839
	$	1,462

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 pension plans.

Target allocations for plan assets as of December 31, 2011 are listed below:

U.S. Large Cap Equity Securities	22	%
Non U.S. Equity Securities	20
Fixed Income Securities	25
Hedge Funds and Similar Investments	20
Private Equity and Other	13
	100	%

Fair Value Measurements at December 31, 2011(a)

	Level 1		Level 2		Level 3		Balance at December 31, 2011
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	13	$	—	$	13
Equity securities:
U.S. Large Cap (c)	175		15		—		190
U.S. Small/Mid Cap (d)	70		6		—		76
Non U.S (e)	176		14		—		190
Fixed income securities (f)	24		236		—		260
Hedge Funds and Similar Investments (g)	80		21		95		196
Private Equity and Other (h)	—		—		60		60
Total	$	525	$	305	$	155	$	985

Fair Value Measurements at December 31, 2010(a)

	Level 1		Level 2		Level 3		Balance at December 31, 2010
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	8	$	—	$	8
Equity securities
U.S. Large Cap (c)	126		62		—		188
U.S. Small/Mid Cap (d)	60		58		—		118
Non U.S (e)	79		122		—		201
Fixed income securities (f)	4		252		—		256
Hedge Funds and Similar Investments (g)	76		48		79		203
Private Equity and Other (h)	—		—		55		55
Total	$	345	$	550	$	134	$	1,029

_______________________________________

(a) See Note 3 — Fair Value for a description of levels within the fair value hierarchy.

(b) This category predominantly represents certain short-term fixed income securities and money market investments that are managed in separate accounts or commingled funds. Pricing for investments in this category are obtained from quoted prices in actively traded markets or valuations from brokers or pricing services.

(c) This category comprises both actively and not actively managed portfolios that track the S&P 500 low cost equity index funds. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(d) This category represents portfolios of small and medium capitalization domestic equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(e) This category primarily consists of portfolios of non-U.S. developed and emerging market equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(f) This category includes corporate bonds from diversified industries, U.S. Treasuries, and mortgage backed securities. Pricing for investments in this category is obtained from quoted prices in actively traded markets and quotations from broker or pricing services. Non-exchange traded securities and exchange-traded securities held in commingled funds are classified as Level 2 assets.

(g) This category utilizes a diversified group of strategies that attempt to capture financial market inefficiencies and includes publicly traded debt and equity, publicly traded mutual funds, commingled and limited partnership funds and non-exchange traded securities. Pricing for Level 1 and level 2 assets in this category is obtained from quoted prices in actively traded markets and quoted prices from broker or pricing services. Non-exchange traded securities held in commingled funds are classified as Level 2 assets. Valuations for some Level 3 assets in this category may be based on limited observable inputs as there may be little, if any, publicly available pricing.

(h) This category includes a diversified group of funds and strategies that primarily invests in private equity partnerships. This category also includes investments in timber and private mezzanine debt. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available pricing. Valuations for assets in this category may be based on discounted cash flow analyses, relevant publicly-traded comparables and comparable transactions.

The VEBA trusts hold debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices in actively traded markets. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued based on underlying securities, using quoted prices in actively traded markets. Non-exchange traded fixed income securities are valued by the trustee based upon quotations available from brokers or pricing services. A primary price source is identified by asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustees challenge an assigned price and determine that another price source is considered to be preferable. DTE Energy has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, DTE Energy selectively corroborates the fair values of securities by comparison of market-based price sources.

Fair Value Measurements Using Significant Unobservable Inputs (Level 3):

	Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1, 2011	$	79		$	55		$	134
Total realized/unrealized gains (losses):
Realized gains (losses)	(1		)	2			1
Unrealized gains (losses)	2			(22		)	(20		)
Purchases, sales and settlements:
Purchases	68			48			116
Sales	(53		)	(23		)	(76		)
Ending Balance at December 31, 2011	$	95		$	60		$	155
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	5		$	(16	)	$	(11	)

	Hedge Funds and Similar Investments			Private Equity and Other		Total
	(In millions)
Beginning Balance at January 1, 2010	$	92		$	46	$	138
Total realized/unrealized gains	10			8		18
Purchases, sales and settlements	(23		)	1		(22		)
Ending Balance at December 31, 2010	$	79		$	55	$	134
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	6		$	7	$	13

There were no transfers between Level 3 and Level 2 and there were no significant transfers between Level 2 and Level 1 in the years ended December 31, 2011 and 2010.

Healthcare Legislation

In March 2010, the Patient Protection and Affordable Care Act of 2010 and the Health Care and Education Reconciliation Act of 2010 were enacted into law (collectively, the “Act”). The Act is a comprehensive health care reform bill. A provision of the Act repeals the current rule permitting deduction of the portion of the drug coverage expense that is offset by the Medicare Part D subsidy, effective for taxable years beginning after December 31, 2012.

DTE Energy’s retiree healthcare plan includes the provision of postretirement prescription drug coverage (“coverage”) which is included in the calculation of the recorded other postemployment benefit (OPEB) obligation. Because the Company’s coverage meets certain criteria, DTE Energy is eligible to receive the Medicare Part D subsidy. With the enactment of the Act, the subsidy will continue to not be subject to tax, but an equal amount of prescription drug coverage expenditures will not be deductible. Income tax accounting rules require the impact of a change in tax law be recognized in continuing operations in the Consolidated Statements of Operations in the period that the tax law change is enacted.

This change in tax law required a remeasurement of the Deferred tax asset related to the OPEB obligation and the Deferred tax liability related to the OPEB Regulatory Asset in 2010. The net impact of the remeasurement was $22 million, $18 million and $3 million for DTE Energy, Detroit Edison and MichCon, respectively. The Detroit Edison and MichCon amounts have been deferred as Regulatory Assets as the traditional rate setting process allows for the recovery of income tax costs.

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 $6 million in 2011, $7 million in 2010 and $20 million in 2009. At December 31, 2011, the gross amount of federal subsidies expected to be received in 2012 is estimated to be $6 million.

Grantor Trust

MichCon maintains a Grantor Trust to fund other postretirement benefit obligations 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, approximately $13 million at December 31, 2011, with unrealized gains and losses recorded to earnings.

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Short-Term Credit Arrangements and Borrowings (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 years ratio banks percent	Dec. 31, 2010 percent
Short-term Debt [Line Items]
Revolving Credit Facilities with a Syndicate Number of Banks	20
Maximum Percentage of Commitment to Bank in any Facility	8.50%
Renewal of Credit Facility Time Period	5
Maximum Total Funded Debt to Total Capitalization Ratio	65.00%
Maximum Total Funded Debt to Total Capitilization Ration Denominator	100.00%
Letters of Credit Outstanding, Amount	$ 39
Short-term Debt, Weighted Average Interest Rate	0.50%	0.40%
Borrowing Capacity Under Financing Agreement With iss Clearing Agent	100
Maximum Additional Margin Financing	50
Line of Credit Facility, Increase, Additional Borrowings	15
Line of Credit Facility Current Borrowing	115
Other Short-term Borrowings	$ 56	$ 39
DTE Energy [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio	50.00%
Total Funded Debt to Total Capitalization Ratio Denominator	100.00%
Detroit Edison [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio	52.00%
Total Funded Debt to Total Capitalization Ratio Denominator	100.00%
MichCon [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio	45.00%
Total Funded Debt to Total Capitalization Ratio Denominator	100.00%

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Organization and Basis of Presentation (Details Textuals)	Dec. 31, 2011 customers
Legal Entities [Line Items]
Number of Electric Utility Customers	2,100,000
Number of Gas Utility Customers	1,200,000

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

	2011			2010			2009
	(In millions)
Income before income taxes	$	987		$	950		$	782
Income tax expense at 35% statutory rate	$	345		$	333		$	274
Production tax credits	(6		)	(33		)	(12		)
Investment tax credits	(6		)	(6		)	(7		)
Depreciation	(4		)	(4		)	(4		)
Employee Stock Ownership Plan dividends	(4		)	(5		)	(5		)
Medicare part D subsidy	—			—			(6		)
Domestic production activities deduction	(7		)	(7		)	(5		)
Goodwill attributed to the sale of Gas Utility subsidiaries	—			—			4
Settlement of Federal tax audit	—			(12		)	(11		)
State and local income taxes, net of federal benefit	37			44			25
Enactment of Michigan Corporate Income Tax, net of federal expense	(87		)	—			—
Other, net	(1		)	1			(6		)
Income tax expense	$	267		$	311		$	247
Effective income tax rate	27.1		%	32.7		%	31.6		%

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

Components of income tax expense were as follows:

	2011			2010			2009
	(In millions)
Current income tax expense (benefit)
Federal	$	25		$	(172	)	$	25
State and other income tax	22			26			17
Total current income taxes	47			(146		)	42
Deferred income tax expense (benefit)
Federal	318			415			182
State and other income tax	(98		)	42			23
Total deferred income taxes	220			457			205
Total	$	267		$	311		$	247

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

Deferred tax assets (liabilities) were comprised of the following at December 31:

	2011			2010
	(In millions)
Property, plant and equipment	$	(3,131	)	$	(2,558	)
Securitized regulatory assets	(360		)	(396		)
Alternative minimum tax credit carry-forwards	294			337
Merger basis differences	50			49
Pension and benefits	(39		)	(36		)
Other comprehensive income	99			83
Derivative assets and liabilities	64			29
State net operating loss and credit carry-forwards	30			33
Other	(45		)	(2		)
	(3,038		)	(2,461		)
Less valuation allowance	(27		)	(32		)
	$	(3,065	)	$	(2,493	)
Current deferred income tax assets	$	51		$	139
Long-term deferred income tax liabilities	(3,116		)	(2,632		)
	$	(3,065	)	$	(2,493	)
Deferred income tax assets	$	1,048		$	1,418
Deferred income tax liabilities	(4,113		)	(3,911		)
	$	(3,065	)	$	(2,493	)

Unrecognized Tax Benefits [Table Text Block]

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	2011			2010			2009
	(In millions)
Balance at January 1	$	28		$	81		$	72
Additions for tax positions of prior years	27			4			15
Reductions for tax positions of prior years	(4		)	(4		)	(5		)
Additions for tax positions related to the current year	1			—			7
Settlements	(3		)	(53		)	(5		)
Lapse of statute of limitations	(1		)	—			(3		)
Balance at December 31	$	48		$	28		$	81

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2011

Supplemental Cash Flow Information [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

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

	2011			2010			2009
	(In millions)
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	71		$	79		$	167
Inventories	(129		)	(133		)	28
Recoverable pension and postretirement costs	(620		)	(32		)	(19		)
Accrued/prepaid pensions	432			67			11
Accounts payable	(23		)	12			(162		)
Income taxes payable/receivable	249			(245		)	43
Derivative assets and liabilities	(94		)	(48		)	(81		)
Postretirement obligation	209			(24		)	(147		)
Other assets	9			(52		)	58
Other liabilities	(10		)	83			171
	$	94		$	(293	)	$	69

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

	2011			2010		2009
	(In millions)
Cash paid (received) for:
Interest (net of interest capitalized)	$	485		$	551	$	550
Income taxes	$	(205	)	$	93	$	18
Noncash financing activities: Common stock issued for employee benefit plans	$	1		$	156	$	47

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Segment Information

12 Months Ended

Dec. 31, 2011

Segment Reporting [Abstract]

SEGMENT INFORMATION

SEGMENT AND RELATED INFORMATION

The Company sets strategic goals, allocates resources and evaluates performance based on the following structure:

Electric Utility segment consists principally of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million residential, commercial and industrial customers in southeastern Michigan.

Gas Utility segment consists of MichCon and Citizens.  MichCon is engaged in the purchase, storage, transportation, distribution and sale of natural gas to approximately 1.2 million residential, commercial and industrial customers throughout Michigan and the sale of storage and transportation capacity. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.

Gas Storage and Pipelines consists of natural gas pipeline, gathering and storage businesses.

Unconventional Gas Production is engaged in unconventional gas and oil project development and production.

Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers; provide coal transportation and marketing; and sell electricity from biomass-fired energy projects.

Energy Trading consists of energy marketing and trading operations.

Corporate and Other, includes various holding company activities, holds certain non-utility debt and energy-related investments.

The federal 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 if applicable. The MBT provision of the utility subsidiaries is determined on an individual company basis and recognizes the tax benefit of various tax credits and net operating losses if applicable. See Note 12 for a discussion of the MCIT, which replaced the MBT effective January 1, 2012. The subsidiaries record federal and state income taxes payable to or receivable from DTE Energy based on the federal and state tax provisions of each company.

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:

	2011			2010			2009
	(In millions)
Electric Utility	$	33		$	30		$	28
Gas Utility	2			—			2
Gas Storage and Pipelines	8			4			5
Power and Industrial Projects	238			161			11
Energy Trading	70			89			93
Corporate and Other	(50		)	(65		)	(74		)
	$	301		$	219		$	65

Financial data of the business segments follows:

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income Attributable to DTE Energy Company			Total Assets		Goodwill		Capital Expenditures
	(In millions)
2011
Electric Utility	$	5,154		$	818	$	(1	)	$	289		$	265		$	434		$	17,370	$	1,208	$	1,203
Gas Utility	1,505			89		(7		)	64			60			110			3,933		745		179
Gas Storage and Pipelines	91			6		(5		)	7			35			57			421		22		16
Unconventional Gas Production	39			18		—			7			(3		)	(6		)	319		2		29
Power and Industrial Projects	1,129			60		(8		)	32			11			38			1,210		26		56
Energy Trading	1,276			3		—			9			34			52			552		17		1
Corporate and Other	4			1		(47		)	144			(134		)	26			2,204		—		—
Reconciliation and Eliminations	(301		)	—		58			(58		)	(1		)	—			—		—		—
Total	$	8,897		$	995	$	(10	)	$	494		$	267		$	711		$	26,009	$	2,020	$	1,484

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income Attributable to DTE Energy Company			Total Assets		Goodwill		Capital Expenditures
	(In millions)
2010
Electric Utility	$	4,993		$	849	$	(1	)	$	313		$	270		$	441		$	16,375	$	1,206	$	864
Gas Utility	1,648			92		(9		)	66			67			127			3,854		759		147
Gas Storage and Pipelines	83			5		(1		)	6			32			51			391		9		5
Unconventional Gas Production	32			15		—			6			(6		)	(11		)	308		2		27
Power and Industrial Projects	1,144			60		(3		)	33			3			85			1,236		27		53
Energy Trading	875			5		—			13			5			6			483		17		1
Corporate and Other	1			1		(47		)	160			(60		)	(69		)	2,249		—		—
Reconciliation and Eliminations	(219		)	—		49			(48		)	—			—			—		—		—
Total	$	8,557		$	1,027	$	(12	)	$	549		$	311		$	630		$	24,896	$	2,020	$	1,097

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income Attributable to DTE Energy Company			Total Assets		Goodwill		Capital Expenditures
	(In millions)
2009
Electric Utility	$	4,714		$	844	$	(1	)	$	324		$	228		$	376		$	15,879	$	1,206	$	794
Gas Utility	1,788			107		(8		)	68			39			80			3,832		759		166
Gas Storage and Pipelines	82			5		(1		)	10			33			49			367		9		2
Unconventional Gas Production	31			16		—			6			(4		)	(9		)	309		2		26
Power and Industrial Projects	661			40		(3		)	30			(7		)	31			1,118		31		45
Energy Trading	804			5		(1		)	10			37			75			552		17		2
Corporate & Other	—			3		(55		)	147			(79		)	(70		)	2,138		—		—
Reconciliation and Eliminations	(66		)	—		50			(50		)	—			—			—		—		—
Total	$	8,014		$	1,020	$	(19	)	$	545		$	247		$	532		$	24,195	$	2,024	$	1,035

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Consolidated Statements of Comprehensive Income (Parentheticals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	$ (5)	$ 3	$ 4
Amounts reclassified to benefit obligations related to consolidation of Variable Interest Entities Tax	0	5	0
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	0	1	2
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Tax	0	1	(1)
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax	0	(6)	3
Other Comprehensive Income (Loss), Reclassification Adjustment for Sale of Securities Included in Net Income, Tax	0	0	2
Amounts reclassified to benefit obligations related to consolidation of Variable Interest Entities Tax1	0	(5)	0
Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Tax	$ 0	$ 0	$ 1

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Supplementary Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2011

Supplementary Quarterly Financial Information (Unaudited) [Abstract]

Quarterly Financial Information [Text Block]

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.

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
	(In millions, except per share amounts)
2011
Operating Revenues	$	2,431	$	2,028	$	2,265	$	2,173	$	8,897
Operating Income	$	390	$	288	$	399	$	346	$	1,423
Net Income Attributable to DTE Energy Company (1)	$	176	$	202	$	183	$	150	$	711
Basic Earnings per Share	$	1.04	$	1.19	$	1.08	$	.88	$	4.19
Diluted Earnings per Share	$	1.04	$	1.19	$	1.07	$	.88	$	4.18

2010
Operating Revenues	$	2,453	$	1,792	$	2,139	$	2,173	$	8,557
Operating Income	$	472	$	256	$	386	$	350	$	1,464
Net Income Attributable to DTE Energy Company	$	229	$	86	$	163	$	152	$	630
Basic Earnings per Share	$	1.38	$	.51	$	.97	$	.90	$	3.75
Diluted Earnings per Share	$	1.38	$	.51	$	.96	$	.90	$	3.74

(1) Includes an income tax benefit of $87 million relating to the enactment of the MCIT in the second quarter of 2011.

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Regulatory Matters (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Regulatory Asset and Liability [Line Items]
Regulatory Assets	$ 4,853	$ 4,158
Regulatory Assets, Current	(314)	(100)
Regulatory Assets, Noncurrent	4,539	4,058
Securitized Regulatory Assets, Noncurrent	577	729
Regulatory Liabilities	1,073	1,422
Regulatory Liability, Current	(54)	(94)
Regulatory Liability, Noncurrent	1,019	1,328
Asset Removal Costs [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	419	479
Deferred Income Taxes [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	0	418
Renewable Energy [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	192	125
Refundable Revenue Decoupling [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	127	47
Pension Cost [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	120	129
Refundable Income Taxes [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	66	77
Energy Optimization [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	34	27
Refundable Uncollectible Expense [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	31	0
Accrued PSCR GCR Refund [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	26	8
Low Income Energy Efficiency Fund [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	26	0
Refueling Outage [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	23	3
Revenue Subject to Refund [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	1	52
Refundable Costs Under PA 141 [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	0	33
Refundable Restoration Expense [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	0	15
Other Liabilities [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	8	9
Pension [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	2,208	1,742
Postretirment costs [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	778	624
Asset retirement obligation [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	420	336
Recoverable Michigan income taxes [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	324	383
Recoverable income taxes related to securitized regulatory assets [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	316	400
Choice incentive mechanism [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	166	105
Accrued PSCR/GCR revenue [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	147	52
Cost to Achieve Performance Excellence Process [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	116	137
Other recoverabe income taxes [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	81	85
Unamortized loss on reacquired debt [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	64	65
Recoverable restoration expense [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	58	19
Deferred environmental costs [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	49	41
Recoverable uncollectible expense [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	42	90
Enterprise Business Systems Costs [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	18	21
Recoverable revenue decoupling [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	18	5
Other [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	$ 48	$ 53

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Retirement Benefits and Trusteed Assets (Details 8) (Other Postretirement Benefit Plans, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Other Postretirement Benefit Plans, Defined Benefit [Member]
Other Postretirement Costs [Line Items]
Service cost	$ 64	$ 61	$ 59
Interest cost	121	125	133
Expected return on plan assets	(94)	(74)	(55)
Net loss	55	54	72
Prior service cost	(26)	(4)	(6)
Net transition obligation	2	2	2
Net postretirement cost	$ 122	$ 164	$ 205

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2011

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Table Text Block]

	2011			2010
	(In millions)
Property, Plant and Equipment
Electric Utility
Generation	$	9,785		$	9,268
Distribution	7,003			6,800
Total Electric Utility	16,788			16,068
Gas Utility
Distribution	2,561			2,460
Storage	406			395
Other	902			991
Total Gas Utility	3,869			3,846
Non-utility and other	1,884			1,660
Total	22,541			21,574
Less Accumulated Depreciation, Depletion and Amortization
Electric Utility
Generation	(3,946		)	(3,850		)
Distribution	(2,580		)	(2,568		)
Total Electric Utility	(6,526		)	(6,418		)
Gas Utility
Distribution	(1,041		)	(1,019		)
Storage	(127		)	(108		)
Other	(413		)	(512		)
Total Gas Utility	(1,581		)	(1,639		)
Non-utility and other	(688		)	(525		)
Total	(8,795		)	(8,582		)
Net Property, Plant and Equipment	$	13,746		$	12,992

Useful Life [Table Text Block]

	Estimated Useful Lives in Years
Utility	Generation	Distribution	Transmission
Electric	46	43	N/A
Gas	N/A	62	61

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Cash Flow Elements [Abstract]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

	2011			2010			2009
	(In millions)
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	71		$	79		$	167
Inventories	(129		)	(133		)	28
Recoverable pension and postretirement costs	(620		)	(32		)	(19		)
Accrued/prepaid pensions	432			67			11
Accounts payable	(23		)	12			(162		)
Income taxes payable/receivable	249			(245		)	43
Derivative assets and liabilities	(94		)	(48		)	(81		)
Postretirement obligation	209			(24		)	(147		)
Other assets	9			(52		)	58
Other liabilities	(10		)	83			171
	$	94		$	(293	)	$	69

Schedule of Other Significant Noncash Transactions [Table Text Block]

	2011			2010		2009
	(In millions)
Cash paid (received) for:
Interest (net of interest capitalized)	$	485		$	551	$	550
Income taxes	$	(205	)	$	93	$	18
Noncash financing activities: Common stock issued for employee benefit plans	$	1		$	156	$	47

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Financial and Other Derivative Instruments (Details 2)	Dec. 31, 2011 dte.volumes
Natural Gas [Member]
Derivative [Line Items]
Investment Contract Volume	770,624,682
Electricity [Member]
Derivative [Line Items]
Investment Contract Volume	48,286,149
Foreign currency exchange contracts [Member]
Derivative [Line Items]
Investment Contract Volume	34,904,696

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Consolidated Statements of Operations (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating Revenues	$ 8,897	$ 8,557	$ 8,014
Operating Expenses
Fuel, purchased power and gas	3,537	3,190	3,118
Operation and maintenance	2,628	2,578	2,372
Depreciation, depletion and amortization	995	1,027	1,020
Taxes other than income	313	308	275
Asset (gains) and losses, reserves and impairments, net	1	(10)	(20)
Total operating expenses	7,474	7,093	6,765
Operating Income	1,423	1,464	1,249
Other (Income) and Deductions
Interest expense	494	549	545
Interest income	(10)	(12)	(19)
Other income	(117)	(78)	(102)
Other expenses	69	55	43
Total Other (Income) and Deductions	436	514	467
Income Before Income Taxes	987	950	782
Income Tax Expense	267	311	247
Net Income	720	639	535
Less: Net Income Attributable to Noncontrolling Interests	9	9	3
Net Income Attributable to DTE Energy Company	$ 711	$ 630	$ 532
Basic Earnings per Common Share
Net Income Attributable to DTE Energy Company	$ 4.19	$ 3.75	$ 3.24
Diluted Earnings per Common Share
Net Income Attributable to DTE Energy Company	$ 4.18	$ 3.74	$ 3.24
Weighted Average Common Shares Outstanding
Basic	169	168	164
Diluted	170	169	164
Dividends Declared per Common Share	$ 2.32	$ 2.18	$ 2.12

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2011

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

	2011		2010		2009
	(In millions, expect per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	711	$	630	$	532
Average number of common shares outstanding	169		168		164
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	392	$	365	$	347
Dividends declared — net restricted shares	1		2		2
Total distributed earnings	$	393	$	367	$	349
Net income less distributed earnings	$	318	$	263	$	183
Distributed (dividends per common share)	$	2.32	$	2.18	$	2.12
Undistributed	1.87		1.57		1.12
Total Basic Earnings per Common Share	$	4.19	$	3.75	$	3.24
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	711	$	630	$	532
Average number of common shares outstanding	169		168		164
Average incremental shares from assumed exercise of options	1		1		—
Common shares for dilutive calculation	170		169		164
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	392	$	365	$	347
Dividends declared — net restricted shares	1		2		2
Total distributed earnings	$	393	$	367	$	349
Net income less distributed earnings	$	318	$	263	$	183
Distributed (dividends per common share)	$	2.32	$	2.18	$	2.12
Undistributed	1.86		1.56		1.12
Total Diluted Earnings per Common Share	$	4.18	$	3.74	$	3.24

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Long-Term Debt (Details 3) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011
Maturity of Long Term Debt [Line Items]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 519
Long-term Debt, Maturities, Repayments of Principal in Year Two	811
Long-term Debt, Maturities, Repayments of Principal in Year Three	892
Long-term Debt, Maturities, Repayments of Principal in Year Four	476
Long-term Debt, Maturities, Repayments of Principal in Year Five	465
Long-term Debt, Maturities, Repayments of Principal after Year Five	4,530
Long Term Debt Maturities Repayment of Principal	$ 7,693

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Segment Information (Details Textuals)	Dec. 31, 2011 customers
Entity Information [Line Items]
Number of Electric Utility Customers	2,100,000
Number of Gas Utility Customers	1,200,000
Number of Citizens Gas Customers	17,000

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Retirement Benefits and Trusteed Assets (Details 7) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	$ 59	$ 24
Realized gains (losses)	87	69
Unrealized gains (losses)		6
Purchases	3
Purchases, issuances and settlements		(87)
Ending Balance	44	59
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	75	(9)
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	478	644
Realized gains (losses)	2
Unrealized gains (losses)	(29)
Purchases	87
Sales	(74)
Total realized/unrealized gains (losses)		74
Purchases, issuances and settlements		(240)
Ending Balance	464	478
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	(24)	42
Pension Plans, Defined Benefit [Member] | Hedge Funds and Similar Investments [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	304	484
Realized gains (losses)	(4)
Unrealized gains (losses)	1
Purchases	64
Sales	(69)
Total realized/unrealized gains (losses)		51
Purchases, issuances and settlements		(231)
Ending Balance	296	304
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	4	29
Pension Plans, Defined Benefit [Member] | Private Equity and Other [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	174	160
Realized gains (losses)	6
Unrealized gains (losses)	(30)
Purchases	23
Sales	(5)
Total realized/unrealized gains (losses)		23
Purchases, issuances and settlements		(9)
Ending Balance	168	174
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	$ (28)	$ 13

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Consolidated Statements of Changes in Equity (USD $) In Millions, except Share data	Total	Common Stock	Retained Earnings	Accumulated Other Comprehensive Loss	Non-controlling Interest	Stockholders' Equity, Total [Member]
Beginning Balance at Dec. 31, 2008		$ 3,175	$ 2,985	$ (165)	$ 43	$ 6,038
Beginning Balance, shares at Dec. 31, 2008		163,020,000
Net Income	535		532			535
Net Income (Loss) Attributable to Noncontrolling Interest	3				3
Dividends declared on common stock			(349)			(349)
Stock Issued During Period, Shares, New Issues		1,109,000
Issuance of common stock, value		35				35
Benefit obligations, net of tax	7			7		7
Foreign currency translation, net of tax	2			2		2
Net change in unrealized losses on derivatives, net of tax	3			1		1
Net change in unrealized losses on investments, net of tax	5			8		8
Contributions from NonControlling Interests					4	4
Stock-based compensation, distributions to noncontrolling interests and other, shares		1,271,000
Stock-based compensation, distributions to noncontrolling interests and other		47				35
Payments of Dividends, Noncontrolling Interest					(12)
Ending Balance at Dec. 31, 2009		3,257	3,168	(147)	38	6,316
Ending Balance, shares at Dec. 31, 2009		165,400,000
Net Income	639
Net Income (Loss) Attributable to Noncontrolling Interest	9				9
Stock Issued During Period, Shares, New Issues		777,000
Issuance of common stock, value	3,440	36				36
Benefit obligations, net of tax	15			15		15
Foreign currency translation, net of tax	1			1		1
Net change in unrealized losses on derivatives, net of tax	1			2		2
Net change in unrealized losses on investments, net of tax	(10)			(20)		(20)
Stock-based compensation, distributions to noncontrolling interests and other, shares		1,027,000
Stock-based compensation, distributions to noncontrolling interests and other		47				45
Payments of Dividends, Noncontrolling Interest					(2)
Contribution of Common Stock to Pension Plan Shares		2,224,000
Contribution of Common Stock to Pension Plan		100				100
Ending Balance at Dec. 31, 2010	6,767	3,440		(149)	45	6,767
Ending Balance, shares at Dec. 31, 2010	169,428,406	169,428,000
Beginning Balance at Sep. 30, 2010
Net Income			630			639
Dividends declared on common stock			(367)			(367)
Issuance of common stock, value						36
Contribution of Common Stock to Pension Plan						100
Ending Balance at Dec. 31, 2010	6,767	3,440	3,431	(149)	45	6,767
Beginning Balance, shares at Dec. 31, 2010	169,428,406	169,428,000
Net Income	720		711			720
Net Income (Loss) Attributable to Noncontrolling Interest	9
Dividends declared on common stock			(392)			(392)
Issuance of common stock, value	3,417
Benefit obligations, net of tax	(9)			(9)		(9)
Foreign currency translation, net of tax	0
Net change in unrealized losses on derivatives, net of tax	0
Net change in unrealized losses on investments, net of tax	0
Stock-based compensation, distributions to noncontrolling interests and other, shares		1,003,000
Stock-based compensation, distributions to noncontrolling interests and other		35				25
Payments of Dividends, Noncontrolling Interest					(10)
Stock Repurchased and Retired During Period, Shares		(1,184,000)
Repurchase of common stock		(58)				(58)
Ending Balance at Dec. 31, 2011	$ 7,053	$ 3,417	$ 3,750	$ (158)	$ 44	$ 7,053
Ending Balance, shares at Dec. 31, 2011	169,247,282	169,247,000

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Long-Term Debt (Details 1) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 1,308
Tax Exempt Revenue Bonds [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.35%
Debt Instrument, Face Amount	31
Mortgages [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.90%
Debt Instrument, Face Amount	250
Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	300
Mortgages 1 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.31%
Debt Instrument, Face Amount	102
Mortgages 2 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.46%
Debt Instrument, Face Amount	77
Tax-Exempt Revenue Bonds 1 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.13%
Debt Instrument, Face Amount	82
Mortgages 3 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.67%
Debt Instrument, Face Amount	46
mortgages 4 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Debt Instrument, Face Amount	140
Junior Subordinated Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument, Face Amount	$ 280

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Supplementary Quarterly Financial Information (Unaudited) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Quarterly Information [Line Items]
Operating Revenues	$ 2,173	$ 2,265	$ 2,028	$ 2,431	$ 2,173	$ 2,139	$ 1,792	$ 2,453	$ 8,897	$ 8,557	$ 8,014
Operating Income (Loss)	346	399	288	390	350	386	256	472	1,423	1,464	1,249
Net Income Attributable to DTE Energy Company	150	183	202	176	152	163	86	229	711	630	532
Basic Earnings per Share	$ 0.88	$ 1.08	$ 1.19	$ 1.04	$ 0.90	$ 0.97	$ 0.51	$ 1.38	$ 4.19	$ 3.75	$ 3.24
Diluted Earnings per Share	$ 0.88	$ 1.07	$ 1.19	$ 1.04	$ 0.90	$ 0.96	$ 0.51	$ 1.38	$ 4.18	$ 3.74	$ 3.24
Income Tax Benefit			$ 87

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Significant Accounting Policies (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 years percent months Days	Dec. 31, 2010	Dec. 31, 2009
Significant Accounting Policies [Line Items]
Maturities on Temporary Investments	3
Receivables Due Date	21
Specific Review of Probable Future Collections Based on Receivable Balances in Excess of 90 Days	30
Unbilled Contracts Receivable	$ 597	$ 575
Notes Receivable Considered Delinquent Minimum Due Date	60
Notes Receivable Considered Delinquent Maximum Due Date	120
LIFO Inventory Amount	52	43
Excess of Replacement or Current Costs over Stated LIFO Value	95	147
Expense Related to Refueling Outages	23	3
Period Expenses Related To Refueling Outages Are Accrued	18
Finite-Lived Intangible Assets, Useful Life, Minimum	3
Finite-Lived Intangible Assets, Useful Life, Maximum	20
Amortization of Intangible Assets	5	4	4
Finite-Lived Intangible Assets, Future Amortization Expense	3
Collateral Already Posted, Aggregate Fair Value	71	77
Cash Collateral Paid or Received for Derivative Assets	19	9
Cash Collateral Paid or Received for Derivative Liabilities	74	53
Cash Collateral Received		2
Cash Collateral Paid	$ 16	$ 35
Contract Intangible Assets [Member]
Significant Accounting Policies [Line Items]
Finite-Lived Intangible Assets, Useful Life, Minimum	3
Finite-Lived Intangible Assets, Useful Life, Maximum	20

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Short-Term Credit Arrangements and Borrowings (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011
Availability under combined facilities
Total credit facilities at December 31, 2011	$ 2,015
Amounts Outstanding
Commercial paper issuances	419
Letters of credit	218
Total amounts outstanding	637
Net availability at December 31, 2011	1,378
Unsecured letter of credit facility, expiring in December 2012 [Member]
Availability under combined facilities
Total credit facilities at December 31, 2011	40
Unsecured letter of credit facility, expiering in May 2013 (Member
Availability under combined facilities
Total credit facilities at December 31, 2011	50
Unsecured letter of credit facility, expiring in August 2015[Member]
Availability under combined facilities
Total credit facilities at December 31, 2011	125
Unsecured revolving credit facility, expiring October 26 [Member]
Availability under combined facilities
Total credit facilities at December 31, 2011	1,800
DTE Energy [Member]
Availability under combined facilities
Total credit facilities at December 31, 2011	1,275
Amounts Outstanding
Commercial paper issuances	234
Letters of credit	178
Total amounts outstanding	412
Net availability at December 31, 2011	863
DTE Energy [Member] | Unsecured letter of credit facility, expiring in December 2012 [Member]
Availability under combined facilities
Total credit facilities at December 31, 2011	0
DTE Energy [Member] | Unsecured letter of credit facility, expiering in May 2013 (Member
Availability under combined facilities
Total credit facilities at December 31, 2011	50
DTE Energy [Member] | Unsecured letter of credit facility, expiring in August 2015[Member]
Availability under combined facilities
Total credit facilities at December 31, 2011	125
DTE Energy [Member] | Unsecured revolving credit facility, expiring October 26 [Member]
Availability under combined facilities
Total credit facilities at December 31, 2011	1,100
Detroit Edison [Member]
Availability under combined facilities
Total credit facilities at December 31, 2011	340
Amounts Outstanding
Commercial paper issuances	0
Letters of credit	40
Total amounts outstanding	40
Net availability at December 31, 2011	300
Detroit Edison [Member] | Unsecured letter of credit facility, expiring in December 2012 [Member]
Availability under combined facilities
Total credit facilities at December 31, 2011	40
Detroit Edison [Member] | Unsecured letter of credit facility, expiering in May 2013 (Member
Availability under combined facilities
Total credit facilities at December 31, 2011	0
Detroit Edison [Member] | Unsecured letter of credit facility, expiring in August 2015[Member]
Availability under combined facilities
Total credit facilities at December 31, 2011	0
Detroit Edison [Member] | Unsecured revolving credit facility, expiring October 26 [Member]
Availability under combined facilities
Total credit facilities at December 31, 2011	300
MichCon [Member]
Availability under combined facilities
Total credit facilities at December 31, 2011	400
Amounts Outstanding
Commercial paper issuances	185
Letters of credit	0
Total amounts outstanding	185
Net availability at December 31, 2011	215
MichCon [Member] | Unsecured letter of credit facility, expiring in December 2012 [Member]
Availability under combined facilities
Total credit facilities at December 31, 2011	0
MichCon [Member] | Unsecured letter of credit facility, expiering in May 2013 (Member
Availability under combined facilities
Total credit facilities at December 31, 2011	0
MichCon [Member] | Unsecured letter of credit facility, expiring in August 2015[Member]
Availability under combined facilities
Total credit facilities at December 31, 2011	0
MichCon [Member] | Unsecured revolving credit facility, expiring October 26 [Member]
Availability under combined facilities
Total credit facilities at December 31, 2011	$ 400

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Organization and Basis of Presentation (Tables)

12 Months Ended

Dec. 31, 2011

Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]

Schedule of Variable Interest Entities [Table Text Block]

	December 31, 2011
	Securitization		Other		Total		Restricted Amounts
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	25	$	25	$	—
Restricted cash	107		7		114		114
Accounts receivable	34		17		51		36
Inventories	—		183		183		—
Other current assets	—		1		1		—
Property, plant and equipment	—		73		73		23
Securitized regulatory assets	577		—		577		577
Other assets	10		6		16		16
	$	728	$	312	$	1,040	$	766
LIABILITIES
Accounts payable and accrued current liabilities	$	14	$	24	$	38	$	14
Current portion long-term debt, including capital leases	164		7		171		171
Other current liabilities	55		—		55		55
Mortgage bonds, notes and other	—		30		30		30
Securitization bonds	479		—		479		479
Capital lease obligations	—		14		14		14
Other long term liabilities	7		2		9		8
	$	719	$	77	$	796	$	771

	December 31, 2010
	Securitization		Other		Total		Restricted Amounts
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	4	$	4	$	—
Restricted cash	104		8		112		112
Accounts receivable	42		8		50		44
Inventories	—		99		99		—
Other current assets	—		1		1		—
Property, plant and equipment	—		54		54		38
Securitized regulatory assets	729		—		729		729
Other assets	13		9		22		21
	$	888	$	183	$	1,071	$	944
LIABILITIES
Accounts payable and accrued current liabilities	$	17	$	27	$	44	$	18
Current portion long-term debt, including capital leases	150		7		157		157
Other current liabilities	62		6		68		66
Mortgage bonds, notes and other	—		35		35		35
Securitization bonds	643		—		643		643
Capital lease obligations	—		23		23		23
Other long term liabilities	6		7		13		12
	$	878	$	105	$	983	$	954

Summary of amounts for non-consolidated VIEs [Table Text Block

	December 31, 2011		December 31, 2010
	(In millions)
Other investments	$	117	$	98
Notes receivable	7		6
Trust preferred — linked securities	—		289

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Stock-Based Compensation (Details 8) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 years
Share Based Compensation Unrecognized and Non-Vested Cost [Line Items]
Unrecognized Compensation Cost	$ 50
Weighted Average to be Recognized	1.36
Options [Member]
Share Based Compensation Unrecognized and Non-Vested Cost [Line Items]
Unrecognized Compensation Cost	1
Weighted Average to be Recognized	0.76
Stock Awards [Member]
Share Based Compensation Unrecognized and Non-Vested Cost [Line Items]
Unrecognized Compensation Cost	15
Weighted Average to be Recognized	1.12
Performance Share Awards [Member]
Share Based Compensation Unrecognized and Non-Vested Cost [Line Items]
Unrecognized Compensation Cost	34
Weighted Average to be Recognized	1.48
Total [Member]
Share Based Compensation Unrecognized and Non-Vested Cost [Line Items]
Unrecognized Compensation Cost	$ 50
Weighted Average to be Recognized	1.36

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Fair Value (Details 3) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	$ 937	$ 939
Fermi 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	915	910
Fermi 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	3	3
Low level radioactive waste [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	$ 19	$ 26

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Earnings Per Share

12 Months Ended

Dec. 31, 2011

Earnings Per Share [Abstract]

EARNINGS PER SHARE

EARNINGS PER SHARE

The Company reports both basic and diluted earnings per share. The calculation of diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period from the exercise of stock options. A reconciliation of both calculations is presented in the following table as of December 31:

	2011		2010		2009
	(In millions, expect per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	711	$	630	$	532
Average number of common shares outstanding	169		168		164
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	392	$	365	$	347
Dividends declared — net restricted shares	1		2		2
Total distributed earnings	$	393	$	367	$	349
Net income less distributed earnings	$	318	$	263	$	183
Distributed (dividends per common share)	$	2.32	$	2.18	$	2.12
Undistributed	1.87		1.57		1.12
Total Basic Earnings per Common Share	$	4.19	$	3.75	$	3.24
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	711	$	630	$	532
Average number of common shares outstanding	169		168		164
Average incremental shares from assumed exercise of options	1		1		—
Common shares for dilutive calculation	170		169		164
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	392	$	365	$	347
Dividends declared — net restricted shares	1		2		2
Total distributed earnings	$	393	$	367	$	349
Net income less distributed earnings	$	318	$	263	$	183
Distributed (dividends per common share)	$	2.32	$	2.18	$	2.12
Undistributed	1.86		1.56		1.12
Total Diluted Earnings per Common Share	$	4.18	$	3.74	$	3.24

Options to purchase approximately 5 million shares and 4 million shares of common stock in 2010 and 2009, respectively, 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.

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2011

Significant Accounting Policies [Abstract]

Schedule of Comprehensive Income (Loss) [Table Text Block]

	Net Unrealized Gain/(Loss) on Derivatives			Net Unrealized Gain/(Loss) on Investments			Benefit Obligations			Foreign Currency Translation		Accumulated Other Comprehensive Loss
							(In millions)
Beginning balances	$	(4	)	$	(30	)	$	(116	)	$	1	$	(149	)
Current period change, net of tax	—			—			(9		)	—		(9		)
Ending balance	$	(4	)	$	(30	)	$	(125	)	$	1	$	(158	)

Schedule of Finite-Lived Intangible Assets by Major Class [Table Text Block]

Summary of intangible assets as of December 31:

(In millions)	2011		2010
Emission allowances	$	9	$	9
Renewable energy credits	27		17
Contract intangible assets	65		63
	101		89
Less accumulated amortization	28		22
Intangible assets, net	$	73	$	67

XML

Preferred and Preferenced Securities (Details) (USD $)	Dec. 31, 2011
DTE Energy [Member]
Preferred and Preferenced Securities [Line Items]
Preferred	$ 0
Preferred	5,000,000
Detroit Edison [Member]
Preferred and Preferenced Securities [Line Items]
Preferred	$ 100
Preferred	6,747,484
Preference	$ 1
Preference	30,000,000
MichCon [Member]
Preferred and Preferenced Securities [Line Items]
Preferred	$ 1
Preferred	7,000,000
Preference	$ 1
Preference	4,000,000

XML

Stock-Based Compensation (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 66	$ 52	$ 56
Tax benefit	25	20	22
Stock-based compensation cost capitalized in property, plant and equipment	$ 4	$ 3	$ 3

XML

Preferred and Preferenced Securities

12 Months Ended

Dec. 31, 2011

Preferred and Preference Securities [Abstract]

Preferred Stock [Text Block]

PREFERRED AND PREFERENCE SECURITIES

As of December 31, 2011, the amount of authorized and unissued stock is as follows:

Company	Type of Stock	Par Value		Shares Authorized
DTE Energy	Preferred	$	—	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

XML

Fair Value (Details 6) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Cash equivalents [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Available-for-sale Securities, Fair Value Disclosure	$ 140	$ 133
Available-for-sale Securities	140	133
Equity securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Available-for-sale Securities, Fair Value Disclosure	5	6
Available-for-sale Securities	$ 5	$ 6

XML

Retirement Benefits and Trusteed Assets (Details 2) (USD $) In Millions, unless otherwise specified	1 Months Ended		12 Months Ended
	Jan. 31, 2012	Jan. 31, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Regulatory Assets			$ 4,853	$ 4,158
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Accumulated benefit obligation, end of year			3,881	3,521
Benefit obligation, beginning of year	4,195	3,785	3,785	3,436
Consolidation of VIEs			0	82
Service cost			69	64	52
Interest cost			202	202	203
Actuarial loss			355	216
Special termination benefits			2	0	0
Benefits paid			(218)	(215)
Benefit obligation, end of year			4,195	3,785	3,436
Plan assets at fair value, beginning of the yeard Benefit Plan, Fair Value of Plan Assets	2,886	2,913	2,913	2,549
Consolidation of VIEs			0	64
Actual return on plan assets			(18)	309
Company contributions	240	200	209	206
Plan assets at fair value, end of the yeard Benefit Plan, Fair Value of Plan Assets			2,886	2,913	2,549
Funded status of the plans			(1,309)	(872)
Current liabilities			(11)	(6)
Noncurrent liabilities			(1,298)	(866)
Pension and Other Postretirement Defined Benefit Plans, Liabilities			(1,309)	(872)
Net actuarial loss			202	195
Prior serice cost (credit)			(3)	(4)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax			199	191
Net actuarial loss			2,201	1,730
Prior service cost			7	12
Regulatory Assets			$ 2,208	$ 1,742

XML

Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Statement of Income and Comprehensive Income [Abstract]
Net Income	$ 720	$ 639	$ 535
Benefit obligations:
Benefit obligation, net of taxes of $(5), $3 and $4	(9)	5	7
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $-, $5 and $-	0	10	0
Total Benefit obligations	(9)	15	7
Net unrealized gains (losses) on derivatives:
Gains during the period, net of taxes of $-, $1 and $2	0	1	3
Amounts reclassified to income, net of taxes of $-, $1 and $(1)	0	1	(2)
Net unrealized gains (losses) on derivatives	0	2	1
Net unrealized gains (losses) on investments:
Gains (losses) during the period, net of taxes of $-, $(6) and $3	0	(10)	5
Amounts reclassified to income, net of taxes of $-, $- and $2	0	0	3
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $-, $(5) and $-	0	(10)	0
Net unrealized gains (losses) on investments	0	(20)	8
Foreign currency translation, net of taxes of $-, $- and $1	0	1	2
Comprehensive income	711	637	553
Less: Comprehensive income attributable to noncontrolling interests	9	9	3
Comprehensive income attributable to DTE Energy Company	$ 702	$ 628	$ 550

XML

Consolidated Statements of Financial Position (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current Assets
Cash and cash equivalents	$ 68	$ 65
Restricted cash, principally Securitization	147	120
Accounts receivable (less allowance for doubtful accounts of $162 and $196, respectively)
Customer	1,317	1,351
Other	90	402
Inventories
Fuel and gas	572	460
Materials and supplies	219	202
Deferred income taxes	51	139
Derivative assets	222	131
Regulatory assets	314	100
Other	196	197
Total Current Assets	3,196	3,167
Investments
Nuclear decommissioning trust funds	937	939
Other	525	518
Total Investments	1,462	1,457
Property
Property, plant and equipment	22,541	21,574
Less accumulated depreciation, depletion and amortization	(8,795)	(8,582)
Property, plant and equipment, net	13,746	12,992
Other Assets
Goodwill	2,020	2,020
Regulatory assets	4,539	4,058
Securitized regulatory assets	577	729
Intangible assets	73	67
Notes receivable	123	123
Derivative assets	74	77
Other	199	206
Total Noncurrent Assets	7,605	7,280
Total Assets	26,009	24,896
Current Liabilities
Accounts payable	782	729
Accrued interest	95	111
Dividends payable	99	95
Short-term borrowings	419	150
Current portion long-term debt, including capital leases	526	925
Derivative liabilities	158	142
Other	549	597
Total Current Liabilities	2,628	2,749
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	6,405	6,114
Securitization bonds	479	643
Junior subordinated debentures	280	0
Trust preferred-linked securities	0	289
Capital lease obligations	23	43
Total Long-Term Debt (net of current portion)	7,187	7,089
Other Liabilities
Deferred income taxes	3,116	2,632
Regulatory liabilities	1,019	1,328
Asset retirement obligations	1,591	1,498
Unamortized investment tax credit	65	75
Derivative liabilities	89	110
Accrued pension liability	1,298	866
Accrued postretirement liability	1,484	1,275
Nuclear decommissioning	148	149
Other	331	358
Total Noncurrent Liabilities	9,141	8,291
Equity
Common stock, without par value, 400,000,000 shares authorized, 169,247,282 and 169,428,406 shares issued and outstanding, respectively	3,417	3,440
Retained earnings	3,750	3,431
Accumulated other comprehensive loss	(158)	(149)
Total DTE Energy Company Equity	7,009	6,722
Noncontrolling interests	44	45
Total Equity	7,053	6,767
Total Liabilities and Equity	$ 26,009	$ 24,896

XML

Disposals and Discontinued Operations

12 Months Ended

Dec. 31, 2011

Disposals and Discontinued Operations [Abstract]

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

DISPOSALS

Sale of Rail Services Assets

In 2010, the Company sold certain non-strategic rail services assets for gross proceeds of approximately $23 million. The Company recognized a gain of approximately $5 million, net of a write-off of goodwill of approximately $4 million.

Sale of Gathering and Processing Assets

In 2009, the Company sold certain non-strategic gas gathering and processing assets in northern Michigan for gross proceeds of approximately $45 million, which approximated its carrying value, including goodwill of approximately $13 million.

XML

Capital and Operating Leases (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 percent years	Dec. 31, 2010	Dec. 31, 2009
Schedule of Leased Assets [Line Items]
Operating Leases, Rent Expense	$ 71	$ 54	$ 58
Period For Extension of Renewal Options of Capital Lease Contract	5
Ownership Interest with Lessee	40.00%
Period For Extenstion of Renewal Options of Capital Lease Contract 1	3
Period For Extension of Renewal Options of Capital Lease Contract 2	5

XML

Long-Term Debt (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Debt Instrument [Line Items]
Long-term Debt	$ 7,700	$ 8,000
Less amount due within one year	(355)	(765)
Long-term Debt, Excluding Current Maturities	6,405	6,114
Securitization bonds	643	793
Less amount due within one year	(164)	(150)
Securitization bonds	479	643
Trust preferred-linked securities	0	289
DTE Energy Unsecured Debt 5.5% due in 2013 to 2033 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End	5.50%
DTE Energy Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt	1,298	1,597
Detroit Edison Taxable Debt Principally Secured 5.3% due in 2012 to 2041 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End	5.30%
Detroit Edison Tax-Exempt Revenue Bonds 5.1% due in 2012 to 2038 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End	5.10%
Detroit Edison Tax Exempt Revenue Bonds [Member]
Debt Instrument [Line Items]
Long-term Debt	893	1,283
MichCon Taxable Debt Principally Secured 6.1% due in 2012 to 2033 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End	6.10%
Other Long-term Debt, Including Non-Recourse Debt [Member]
Debt Instrument [Line Items]
Long-term Debt	165	195
Total [Member]
Debt Instrument [Line Items]
Long-term Debt	6,760	6,879
Securitization Bonds 6.5% due in 2012 to 2015 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End	6.50%
Junior Subordinated Debentures 6.5% due in 2061 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End	6.50%
Junior Subordinated Debt [Member]
Debt Instrument [Line Items]
Junior Subordinated Debentures	280
Trust Preferred Linked Securities 7.8% due 2032 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End		7.80%
Trust preferred-linked securities	0	186
Trust preferred-linked securities [Member]
Debt Instrument [Line Items]
Trust preferred-linked securities	0	289
Trust Preferred Linked Securities 7.5% due in 2044 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End		7.50%
Trust preferred-linked securities	0	103
Detroit Edison [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt	3,515	2,915
MichCon [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 889	$ 889

XML

Earnings Per Share (Details) (USD $) Share data in Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Basic Earnings per Share
Net Income Attributable to DTE Energy Company	$ 150,000,000	$ 183,000,000	$ 202,000,000	$ 176,000,000	$ 152,000,000	$ 163,000,000	$ 86,000,000	$ 229,000,000	$ 711,000,000	$ 630,000,000	$ 532,000,000
Average number of common shares outstanding									169	168	164
Weighted average net restricted shares outstanding									1	1	1
Dividends declared - common shares									392,000,000	365,000,000	347,000,000
Dividends declared - net restricted shares									1,000,000	2,000,000	2,000,000
Total distributed earnings									393,000,000	367,000,000	349,000,000
Net income less distributed earnings									318,000,000	263,000,000	183,000,000
Distributed (dividends per common share)									$ 2.32	$ 2.18	$ 2.12
Undistributed									$ 1.87	$ 1.57	$ 1.12
Total Basic Earnings per Common Share	$ 0.88	$ 1.08	$ 1.19	$ 1.04	$ 0.90	$ 0.97	$ 0.51	$ 1.38	$ 4.19	$ 3.75	$ 3.24
Diluted Earnings per Share
Net Income Attributable to DTE Energy Company	150,000,000	183,000,000	202,000,000	176,000,000	152,000,000	163,000,000	86,000,000	229,000,000	711,000,000	630,000,000	532,000,000
Average number of common shares outstanding									169	168	164
Average incremental shares from assumed exercise of options									1	1	0
Common shares for dilutive calculation									170	169	164
Weighted average net restricted shares outstanding									1	1	1
Dividends declared - common shares									392,000,000	365,000,000	347,000,000
Dividends declared - net restricted shares									1,000,000	2,000,000	2,000,000
Total distributed earnings									393,000,000	367,000,000	349,000,000
Net income less distributed earnings									318,000,000	263,000,000	183,000,000
Distributed (dividends per common share)									$ 2.32	$ 2.18	$ 2.12
Undistributed									$ 1.86	$ 1.56	$ 1.12
Total Diluted Earnings per Common Share	$ 0.88	$ 1.07	$ 1.19	$ 1.04	$ 0.90	$ 0.96	$ 0.51	$ 1.38	$ 4.18	$ 3.74	$ 3.24

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Retirement Benefits and Trusteed Assets (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended			1 Months Ended		3 Months Ended	12 Months Ended		1 Months Ended	12 Months Ended
	Dec. 31, 2011 percent years	Dec. 31, 2010	Dec. 31, 2009	Jan. 31, 2012 Pension Plans, Defined Benefit [Member]	Jan. 31, 2011 Pension Plans, Defined Benefit [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member]	Dec. 31, 2010 Pension Plans, Defined Benefit [Member]	Jan. 31, 2012 Other Postretirement Benefit Plans, Defined Benefit [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member]	Dec. 31, 2010 Other Postretirement Benefit Plans, Defined Benefit [Member]	Dec. 31, 2010 DTE Energy [Member]	Dec. 31, 2010 Detroit Edison [Member]	Dec. 31, 2010 MichCon [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Transfers between Level 2 and Level 3						$ 0	$ 0			$ 0	$ 0
Transfers between Level 1 and Level 2						0	0			0	0
Health Care Trend Increase in Percentage Point	1
Company contributions				240	200		209	206	140	111	160
Company Lowered Percentage of Long Term Rate of Return Assumption for Pension Plans	8.25%
Defined Contribution Plan, Cost Recognized	35	34	33
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	120
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components	35
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	306
Health Care Trend Decrease in Percentage Point	1
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components	23
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	297
Net Impact of Remeasurement of Deferred Tax Assets and Liabilities Related to Health Care Legislation Acts												22	18	3
Prescription Drug Benefit, Effect of Subsidy on Net Periodic Postretirement Benefit Cost	6	7	20
Prescription Drug Subsidy Receipts, Year One	6
Grantor Trust Balance	$ 13
Time period to pay benefit payments for qualified and unqualified plans	5
Time period for aggregate benefit payments for qualified and non qualtified benefit plans	5

XML

Stock-Based Compensation (Details Textuals) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 years performance	Dec. 31, 2010	Dec. 31, 2009
Schedule of Stock Based Compensation [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	9,000,000
Performance Units	1,000,000
Performance Units Price per Unit	1.00
Expiration Period After Date of Grant	10
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	4.25
Non Vested Stock Options	666,486
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Exercisable, Number	687,061
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 5.62	$ 4.41
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value	$ 20	$ 9	$ 3
Stock or Unit Option Plan Expense	2	4	3
Unrecognized Compensation Cost	$ 50
Weighted Average to be Recognized	1.36
Limit One [Member]
Schedule of Stock Based Compensation [Line Items]
Share Based Compensation Arragement by Share Based payment Terms of Award	500,000
Limit Two [Member]
Schedule of Stock Based Compensation [Line Items]
Share Based Compensation Arragement by Share Based payment Terms of Award	150,000
Limit Three [Member]
Schedule of Stock Based Compensation [Line Items]
Share Based Compensation Arragement by Share Based payment Terms of Award	300,000

XML

Retirement Benefits and Trusteed Assets Retirement Benefits and Trusteed Assets (Details 13) (Other Postretirement Benefit Plans, Defined Benefit [Member])	12 Months Ended
	Dec. 31, 2011 percent
Other Postretirement Benefits Target Allocations of Plan Assets [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Debt Securities	25.00%
Defined Benefit Plan Target Allocation Percentage of Assets Hedged Funds and Similar Investments	20.00%
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	13.00%
Defined Benefit Plan Target Allocation Percentage of Assets Total	100.00%
Us Large Cap Equity Securities [Member]
Other Postretirement Benefits Target Allocations of Plan Assets [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities	22.00%
Non US Equity Securities [Member]
Other Postretirement Benefits Target Allocations of Plan Assets [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities	20.00%

XML

Document Entity Information Document (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Jan. 31, 2012	Jun. 30, 2011
Entity Registrant Name	DTE ENERGY CO
Entity Central Index Key	0000936340
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q4
Amendment Flag	false
Entity Common Stock, Shares Outstanding		169,403,378
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 8.5

XML

Stock-Based Compensation (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2011 years
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Number of Options	2,764,670
Weighted Average Exercise Price	$ 41.25
Weighted Average Remaining Contractual Life (Years)	5.10
Exercise Price Range One [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices Lower Limit	$ 27.00
Range of Exercise Prices Upper Limit	$ 38.00
Number of Options	417,633
Weighted Average Exercise Price	$ 27.80
Weighted Average Remaining Contractual Life (Years)	7.16
Exercise Price Range Two [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices Lower Limit	$ 38.01
Range of Exercise Prices Upper Limit	$ 42.00
Number of Options	723,662
Weighted Average Exercise Price	$ 41.04
Weighted Average Remaining Contractual Life (Years)	3.11
Exercise Price Range Three [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices Lower Limit	$ 42.01
Range of Exercise Prices Upper Limit	$ 45.00
Number of Options	1,272,117
Weighted Average Exercise Price	$ 44.04
Weighted Average Remaining Contractual Life (Years)	5.64
Exercise Price Range Four [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices Lower Limit	$ 45.01
Range of Exercise Prices Upper Limit	$ 50.00
Number of Options	351,258
Weighted Average Exercise Price	$ 47.60
Weighted Average Remaining Contractual Life (Years)	4.81

XML

Other Impairments and Restructuring

12 Months Ended

Dec. 31, 2011

Other Impairments and Restructuring [Abstract]

Restructuring and Related Activities Disclosure [Text Block]

OTHER IMPAIRMENTS AND RESTRUCTURING

Other Impairments — Barnett Shale

Our Unconventional Gas Production segment recorded pre-tax impairment losses of $1 million, $10 million and $6 million in 2011, 2010 and 2009, respectively. The impairments related primarily to the write-off of expired or expiring leasehold positions that the Company does not intend to drill.

Restructuring Costs

In 2005, the Company initiated a company-wide review of its operations called the Performance Excellence Process. The Company incurred CTA restructuring expense. In September 2006, the MPSC issued an order approving a settlement agreement that allowed Detroit Edison and MichCon, commencing in 2006, to defer the incremental CTA. Further, the order provided 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. The recovery of these costs for Detroit Edison was provided for by the MPSC in the order approving the settlement in the show cause proceeding and in the December 23, 2008 MPSC rate order. Detroit Edison amortized deferred CTA costs of $18 million in 2011, 2010 and 2009. The September 2006 order did not provide a regulatory recovery mechanism for MichCon, therefore MichCon expensed CTA incurred during the period 2006 through 2008. The June 2010 MPSC order provided for MichCon’s recovery of the regulatory unamortized balance of CTA. At June 30, 2010, MichCon deferred and recognized in income approximately $32 million ($20 million after-tax) of previously expensed CTA. The non-pension component of CTA of approximately $21 million is included in Regulatory assets. The pension component of CTA of approximately $11 million is included in Regulatory liabilities. MichCon amortized approximately $3 million and $2 million of deferred CTA costs in 2011 and 2010, respectively. Amounts expensed are recorded in Operation and maintenance expense on the Consolidated Statements of Operations. Deferred amounts are recorded in Regulatory assets and Regulatory liabilities on the Consolidated Statements of Financial Position. See Note 11.

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Asset Retirement Obligations (Details Textuals) (USD $)	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2011	Jun. 30, 2011	Dec. 31, 2011 percent years	Dec. 31, 2010 years
Asset Retirement Obligations [Line Items]
Revision in estimated cash flows	$ 19,000,000	$ 20,000,000	$ (1,000,000)	$ 22,000,000
Reserve and Impairment of Retirement Obligation		6,000,000
Proposed Extension of Nuclear Plant 2 License				20
Decommissioning Expenses Current			1,400,000,000
Decommissioning Liability, Noncurrent			148,000,000	149,000,000
Inflation Rate Used to Determine Estimated Decommissioning Expenditures			6.00%
Nuclear Decommissioning Liabilities Funded Through Surcharge and Included In ARO Balance			1,400,000,000
Fermi 2 [Member]
Asset Retirement Obligations [Line Items]
Decommissioning Liability, Noncurrent			$ 10,000,000,000

XML

Common Stock (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 ratio	Dec. 31, 2010
Class of Stock [Line Items]
Contribution of Common stock to the Pension Plan Value		$ 100
Maximum Total Funded Debt to Total Capitalization Ratio	65.00%
Maximum Total Funded Debt to Total Capitilization Ration Denominator	100.00%
Line of Credit Facility, Dividend Restrictions	128	46
Retained Earnings (Accumulated Deficit)	$ 3,750	$ 3,431

XML

Consolidated Statements of Financial Position (Parentheticals) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current Assets:
Allowance for doubtful accounts	$ 162	$ 196
Stockholders' Equity:
Common stock, par value	$ 0.00	$ 0.00
Common stock, shares authorized	400,000,000	400,000,000
Common stock, shares issued	169,247,282	169,428,406
Common stock, shares outstanding	169,247,282	169,428,406

XML

Financial and Other Derivative Instruments

12 Months Ended

Dec. 31, 2011

Derivative Instruments and Hedges, Assets [Abstract]

FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

The Company recognizes all derivatives at their fair value as Derivative Assets or Liabilities on the Consolidated Statements of Financial Position unless they qualify for certain scope exceptions, including the 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 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 the derivative 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 exchange. The Company has risk management policies to monitor and manage 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 Power and Industrial Projects segment. Contracts classified as derivative instruments include power, gas, oil and certain coal forwards, futures, options and swaps, and foreign currency exchange contracts. Items not classified as derivatives include natural gas inventory, unconventional gas and oil reserves, power transmission, pipeline transportation and certain storage assets.

Electric Utility — 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 contracts 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 settled. This results in the deferral of unrealized gains and losses as Regulatory assets or liabilities until realized.

Gas Utility — MichCon purchases, stores, transports, distributes and sells natural gas and sells storage and transportation capacity. MichCon has fixed-priced contracts for portions of its expected gas supply requirements through 2014. Substantially all of these contracts meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. MichCon may also sell forward transportation and storage capacity contracts. Forward transportation and storage contracts are not derivatives and are therefore accounted for under the accrual method.

Gas Storage and Pipelines — This segment is primarily engaged in services related to the transportation and storage of natural gas. Primarily fixed-priced contracts are used in the marketing and management of transportation and storage services. Generally these contracts are not derivatives and are therefore accounted for under the accrual method.

Unconventional Gas Production — The Unconventional Gas Production business is engaged in unconventional natural gas and oil project development and production. The Company may use derivative contracts to manage changes in the price of natural gas and crude oil.

Power and Industrial Projects — Business units within this segment manage and operate onsite energy and pulverized coal projects, coke batteries, landfill gas recovery and power generation assets. These businesses utilize fixed-priced contracts in the marketing and management of their assets. These contracts are generally not derivatives and are therefore accounted for under the accrual method. The segment also engages in coal marketing which includes the marketing and trading of physical coal and coal financial instruments, and forward contracts for the purchase and sale of emission allowances. Certain of these physical and financial coal contracts and contracts for the purchase and sale of emission allowances are derivatives and are accounted for by recording changes in fair value to earnings.

Energy Trading — Commodity Price Risk — Energy Trading markets and trades electricity and natural gas physical products and energy financial instruments, and provides energy and asset 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 unless hedge accounting criteria are met.

Energy Trading — Foreign Currency Exchange Risk — Energy Trading has foreign currency exchange forward contracts to economically hedge fixed Canadian dollar commitments existing under power purchase and sale contracts and gas transportation contracts. The Company enters into these contracts to mitigate price volatility with respect to fluctuations of the Canadian dollar relative to the U.S. dollar. These derivatives are accounted for by recording changes in fair value to earnings unless hedge accounting criteria are met.

Corporate and Other — 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 through 2033. In 2012, the Company estimates reclassifying less than $1 million of losses to earnings.

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, 2011 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to have a material adverse effect on the Company’s financial statements.

Derivative Activities

The Company manages its mark-to-market (MTM) risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, it records and manages the energy purchase and sale obligations under its 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). The following describe the four categories of activities represented by their operating characteristics and key risks:

• Asset Optimization — Represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas production and trades associated with power transmission, gas 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.

• Marketing and Origination — Represents derivative activity transacted by originating substantially hedged positions with wholesale energy marketers, producers, end users, utilities, retail aggregators and alternative energy suppliers.

• Fundamentals Based 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.

• Other — Includes derivative activity at Detroit Edison related to FTRs and forward contracts related to emissions. Changes in the value of derivative contracts at Detroit Edison are recorded as Derivative Assets or Liabilities, with an offset to Regulatory Assets or Liabilities as the settlement value of these contracts will be included in the PSCR mechanism when realized.

The following tables present the fair value of derivative instruments as of December 31, 2011:

	Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	3	$	(5	)
Commodity Contracts:
Natural Gas	2,024		(2,080		)
Electricity	747		(705		)
Other	31		(20		)
Total derivatives not designated as hedging instruments:	$	2,805	$	(2,810	)
Total derivatives:
Current	$	2,272	$	(2,282	)
Noncurrent	533		(529		)
Total derivatives	$	2,805	$	(2,811	)

	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	2,272		$	533		$	(2,282	)	$	(529	)
Counterparty netting	(2,050		)	(440		)	2,050			440
Collateral adjustment	—			(19		)	74			—
Total derivatives as reported	$	222		$	74		$	(158	)	$	(89	)

The following tables present the fair value of derivative instruments as of December 31, 2010:

	Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	20	$	(30	)
Commodity Contracts:
Natural Gas	1,986		(2,118		)
Electricity	766		(716		)
Other	76		(71		)
Total derivatives not designated as hedging instruments:	$	2,848	$	(2,935	)
Total derivatives:
Current	$	2,011	$	(2,041	)
Noncurrent	837		(895		)
Total derivatives	$	2,848	$	(2,936	)

	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	2,011		$	837		$	(2,041	)	$	(895	)
Counterparty netting	(1,871		)	(760		)	1,871			760
Collateral adjustment	(9		)	—			28			25
Total derivatives as reported	$	131		$	77		$	(142	)	$	(110	)

The effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for years ended December 31, 2011 and December 31, 2010 is as follows:

	Location of Gain (Loss) Recognized in Income on Derivatives	Gain (Loss) Recognized in Income on Derivatives for Years Ended December 31
Derivatives not Designated as Hedging Instruments		2011			2010
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	(2	)	$	(14	)
Commodity Contracts:
Natural Gas	Operating Revenue	58			61
Natural Gas	Fuel, purchased power and gas	(21		)	(8		)
Electricity	Operating Revenue	115			80
Other	Operating Revenue	9			9
Other	Operation and maintenance	—			(5		)
Total		$	159		$	123

The effects of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position were $3 million in gains related to FTRs recognized in Regulatory liabilities for the year ended December 31, 2011, and $1 million in losses related to Emissions recognized in Regulatory assets and $6 million in gains related to FTRs recognized in Regulatory liabilities, for the year ended December 31, 2010.

The following represents the cumulative gross volume of derivative contracts outstanding as of December 31, 2011:

Commodity	Number of Units
Natural Gas (MMBtu)	770,624,682
Electricity (MWh)	48,286,149
Foreign Currency Exchange ($ CAD)	34,904,696

Various non-utility subsidiaries of the Company have entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade. Certain of these provisions (known as “hard triggers”) state specific circumstances under which the Company can be asked to post collateral upon the occurrence of a credit downgrade, while other provisions (known as “soft triggers”) are not as specific. For contracts with soft triggers, it is difficult to estimate the amount of collateral which may be requested by counterparties and/or which the Company may ultimately be required to post. The amount of such collateral which could be requested fluctuates based on commodity prices (primarily gas, power and coal) and the provisions and maturities of the underlying transactions. As of December 31, 2011, the value of the transactions for which the Company would have been exposed to collateral requests had DTE Energy’s credit rating been below investment grade on such date under both hard trigger and soft trigger provisions was approximately $315 million. In circumstances where an entity is downgraded below investment grade and collateral requests are made as a result, the requesting parties often agree to accept less than the full amount of their exposure to the downgraded entity.

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Fair Value

12 Months Ended

Dec. 31, 2011

Fair Value Disclosures [Abstract]

FAIR VALUE

FAIR VALUE

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The Company makes certain assumptions it believes that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and its counterparties is incorporated in the valuation of assets and liabilities through the use of credit reserves, the impact of which was immaterial at December 31, 2011 and December 31, 2010. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

A fair value hierarchy has been established, that prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement in its entirety. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The Company classifies fair value balances based on the fair value hierarchy defined as follows:

• Level 1 — Consists of unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access as of the reporting date.

• Level 2 — Consists of inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

• Level 3 — Consists of unobservable inputs for assets or liabilities whose fair value is estimated based on internally developed models or methodologies using inputs that are generally less readily observable and supported by little, if any, market activity at the measurement date. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2011:

	Level 1			Level 2			Level 3			Netting Adjustments (2)			Net Balance at December 31, 2011
	(In millions)
Assets:
Nuclear decommissioning trusts	$	577		$	360		$	—		$	—		$	937
Other investments (1)	57			54			—			—			111
Derivative assets:
Foreign currency exchange contracts	—			3			—			(3		)	—
Commodity Contracts:
Natural Gas	1,926			78			20			(1,991		)	33
Electricity	—			523			224			(490		)	257
Other	23			2			6			(25		)	6
Total derivative assets	1,949			606			250			(2,509		)	296
Total	$	2,583		$	1,020		$	250		$	(2,509	)	$	1,344
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(5	)	$	—		$	3		$	(2	)
Interest rate contracts	—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(1,940		)	(126		)	(14		)	1,976			(104		)
Electricity	—			(513		)	(192		)	565			(140		)
Other	(19		)	(1		)	—			20			—
Total derivative liabilities	(1,959		)	(646		)	(206		)	2,564			(247		)
Total	$	(1,959	)	$	(646	)	$	(206	)	$	2,564		$	(247	)
Net Assets as of December 31, 2011	$	624		$	374		$	44		$	55		$	1,097
Assets:
Current	$	1,571		$	520		$	181		$	(2,050	)	$	222
Noncurrent (3)	1,012			500			69			(459		)	1,122
Total Assets	$	2,583		$	1,020		$	250		$	(2,509	)	$	1,344
Liabilities:
Current	$	(1,603	)	$	(527	)	$	(152	)	$	2,124		$	(158	)
Noncurrent	(356		)	(119		)	(54		)	440			(89		)
Total Liabilities	$	(1,959	)	$	(646	)	$	(206	)	$	2,564		$	(247	)
Net Assets as of December 31, 2011	$	624		$	374		$	44		$	55		$	1,097

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2010:

	Level 1			Level 2			Level 3			Netting Adjustments (2)			Net Balance at December 31, 2010
	(In millions)
Assets:
Nuclear decommissioning trusts	$	599		$	340		$	—		$	—		$	939
Other investments (1)	56			55			—			—			111
Derivative assets:
Foreign currency exchange contracts	—			20			—			(20		)	—
Commodity Contracts:
Natural Gas	1,846			128			12			(1,960		)	26
Electricity	—			649			117			(589		)	177
Other	68			4			4			(71		)	5
Total derivative assets	1,914			801			133			(2,640		)	208
Total	$	2,569		$	1,196		$	133		$	(2,640	)	$	1,258
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(30	)	$	—		$	20		$	(10	)
Interest rate contracts	—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(1,844		)	(263		)	(11		)	1,955			(163		)
Electricity	—			(653		)	(63		)	643			(73		)
Other	(63		)	(8		)	—			66			(5		)
Total derivative liabilities	(1,907		)	(955		)	(74		)	2,684			(252		)
Total	$	(1,907	)	$	(955	)	$	(74	)	$	2,684		$	(252	)
Net Assets as of December 31, 2010	$	662		$	241		$	59		$	44		$	1,006
Assets:
Current	$	1,299		$	663		$	49		$	(1,880	)	$	131
Noncurrent (3)	1,270			533			84			(760		)	1,127
Total Assets	$	2,569		$	1,196		$	133		$	(2,640	)	$	1,258
Liabilities:
Current	$	(1,290	)	$	(730	)	$	(21	)	$	1,899		$	(142	)
Noncurrent	(617		)	(225		)	(53		)	785			(110		)
Total Liabilities	$	(1,907	)	$	(955	)	$	(74	)	$	2,684		$	(252	)
Net Assets as of December 31, 2010	$	662		$	241		$	59		$	44		$	1,006

(1) Excludes cash surrender value of life insurance investments.

(2) Amounts represent the impact of master netting agreements that allow the Company to net gain and loss positions and cash collateral held or placed with the same counterparties.

(3) Includes $111 million of other investments that are included in the Consolidated Statements of Financial Position in Other Investments at December 31, 2011 and December 31, 2010.

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2011 and 2010:

	Year Ended December 31, 2011
	Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets as of January 1, 2011	$	1		$	54		$	4		$	59
Transfers into Level 3	—			4			—			4
Transfers out of Level 3	1			(25		)	—			(24		)
Total gains:
Included in earnings	7			77			3			87
Recorded in regulatory assets/liabilities	—			—			2			2
Purchases, issuances and settlements:
Purchases	—			3			—			3
Settlements	(3		)	(81		)	(3		)	(87		)
Net Assets as of December 31, 2011	$	6		$	32		$	6		$	44
The amount of total gains included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at December 31, 2011	$	8		$	65		$	2		$	75

	Year Ended December 31, 2010
	Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets as of January 1, 2010	$	2		$	19		$	3		$	24
Changes in fair value included in earnings	4			64			1			69
Changes in fair value recorded in regulatory assets/liabilities	—			—			6			6
Purchases, issuances and settlements	(8		)	(73		)	(6		)	(87		)
Transfers in/out of Level 3	3			44			—			47
Net Assets as of December 31, 2010	$	1		$	54		$	4		$	59
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at December 31, 2010	$	(4	)	$	(6	)	$	1		$	(9	)

Transfers in/out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level and for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. Transfers in and transfers out of Level 3 are reflected as if they had occurred at the beginning of the period. For the year ended December 31, 2011, $25 million of net assets reflecting inputs related to certain power transactions identified as observable due to available broker quotes were transferred from Level 3 to Level 2, and $4 million of net assets reflecting inputs related to certain power transactions identified as unobservable due to lack of available broker quotes were transferred from Level 2 to Level 3. For the year ended December 31, 2010, $35 million of net liabilities reflecting inputs related to certain power transactions identified as observable due to available broker quotes were transferred from Level 3 to Level 2, and $9 million of net assets reflecting inputs related to certain power transactions identified as unobservable due to lack of available broker quotes were transferred from Level 2 to Level 3. No significant transfers between Levels 1 and 2 occurred in years ended December 31, 2011 and December 31, 2010.

Nuclear Decommissioning Trusts and Other Investments

The nuclear decommissioning trusts and other investments hold debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices in actively traded markets. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued based on the underlying securities, using quoted prices in actively traded markets. Non-exchange-traded fixed income securities are valued based upon quotations available from brokers or pricing services. A primary price source is identified by asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustees determine that another price source is considered to be preferable. DTE Energy has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, DTE Energy selectively corroborates the fair values of securities by comparison of market-based price sources.

Derivative Assets and Liabilities

Derivative assets and liabilities are comprised of physical and financial derivative contracts, including futures, forwards, options and swaps that are both exchange-traded and over-the-counter traded contracts. Various inputs are used to value derivatives depending on the type of contract and availability of market data. Exchange-traded derivative contracts are valued using quoted prices in active markets. DTE Energy considers the following criteria in determining whether a market is considered active: frequency in which pricing information is updated, variability in pricing between sources or over time and the availability of public information. Other derivative contracts are valued based upon a variety of inputs including commodity market prices, broker quotes, interest rates, credit ratings, default rates, market-based seasonality and basis differential factors. DTE Energy monitors the prices that are supplied by brokers and pricing services and may use a supplemental price source or change the primary price source of an index if prices become unavailable or another price source is determined to be more representative of fair value. DTE Energy has obtained an understanding of how these prices are derived. Additionally, DTE Energy selectively corroborates the fair value of its transactions by comparison of market-based price sources. Mathematical valuation models are used for derivatives for which external market data is not readily observable, such as contracts which extend beyond the actively traded reporting period.

Fair Value of Financial Instruments

The fair value of long-term debt is determined by using quoted market prices when available and a discounted cash flow analysis based upon estimated current borrowing rates when quoted market prices are not available. The table below shows the fair value and the carrying value for long-term debt securities. Certain other financial instruments, such as notes payable, customer deposits and notes receivable are not shown as carrying value approximates fair value. See Note 4 for further fair value information on financial and derivative instruments.

	December 31, 2011						December 31, 2010
	Fair Value			Carrying Value			Fair Value			Carrying Value
Long-Term Debt	$	8.8	billion	$	7.7	billion	$	8.5	billion	$	8.0	billion

Nuclear Decommissioning Trust Funds

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 Consolidated Statements of Financial Position. 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. See Note 8.

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

	December 31 2011		December 31 2010
	(In millions)
Fermi 2	$	915	$	910
Fermi 1	3		3
Low level radioactive waste	19		26
Total	$	937	$	939

At December 31, 2011, investments in the nuclear decommissioning trust funds consisted of approximately 57% in publicly traded equity securities, 41% in fixed debt instruments and 2% in cash equivalents. At December 31, 2010, investments in the nuclear decommissioning trust funds consisted of approximately 61% in publicly traded equity securities, 38% in fixed debt instruments and 1% in cash equivalents. The debt securities at both December 31, 2011 and December 31, 2010 had an average maturity of approximately 7 and 6 years, respectively.

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
	2011			2010			2009
	(In millions)
Realized gains	$	46		$	192		$	37
Realized losses	$	(38	)	$	(83	)	$	(55	)
Proceeds from sales of securities	$	80		$	377		$	295

Realized gains and losses from the sale of securities for the Fermi 2 and the low level radioactive waste funds are recorded to the Regulatory asset and Nuclear decommissioning liability. The following table sets forth the fair value and unrealized gains for the nuclear decommissioning trust funds:

	Fair Value		Unrealized Gains
	(In millions)
As of December 31, 2011
Equity securities	$	533	$	80
Debt securities	385		22
Cash and cash equivalents	19		—
	$	937	$	102
As of December 31, 2010
Equity securities	$	572	$	77
Debt securities	361		11
Cash and cash equivalents	6		—
	$	939	$	88

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.

Unrealized losses incurred by the Fermi 2 trust are recognized as a Regulatory asset. Detroit Edison recognized $67 million and $26 million of unrealized losses as Regulatory assets at December 31, 2011 and 2010, 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, unrealized losses incurred by the Fermi 1 trust are recognized in earnings immediately. There were no unrealized losses recognized in 2011, 2010 and 2009 for Fermi 1.

Other Available- For- Sale Securities

The following table summarizes the fair value of the Company’s investment in available-for-sale debt and equity securities, excluding nuclear decommissioning trust fund assets:

	December 31, 2011				December 31, 2010
(In millions)	Fair Value		Carrying value		Fair Value		Carrying Value
Cash equivalents	$	140	$	140	$	133	$	133
Equity securities	$	5	$	5	$	6	$	6

At December 31, 2011 and 2010, these securities are comprised primarily of money-market and equity securities. During the year ended December 31, 2011 and December 31, 2010no amounts of unrealized losses on available for sale securities were reclassified out of other comprehensive income into losses for the periods. Gains related to trading securities held at December 31, 2011, 2010, and 2009 were $3 million, $7 million and $8 million, respectively.

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Long-Term Debt

12 Months Ended

Dec. 31, 2011

Long-term Debt, Unclassified [Abstract]

Long-term Debt [Text Block]

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:

	2011			2010
	(In millions)
Mortgage bonds, notes, and other
DTE Energy Debt, Unsecured
5.5% due 2013 to 2033	$	1,298		$	1,597
Detroit Edison Taxable Debt, Principally Secured
5.3% due 2012 to 2041	3,515			2,915
Detroit Edison Tax-Exempt Revenue Bonds (2)
5.1% due 2012 to 2038	893			1,283
MichCon Taxable Debt, Principally Secured
6.1% due 2012 to 2033	889			889
Other Long-Term Debt, Including Non-Recourse Debt	165			195
	6,760			6,879
Less amount due within one year	(355		)	(765		)
	$	6,405		$	6,114
Securitization bonds
6.5% due 2012 to 2015	$	643		$	793
Less amount due within one year	(164		)	(150		)
	$	479		$	643
Junior Subordinated Debentures
6.5% due 2061	$	280		$	—
Trust preferred-linked securities
7.8% due 2032	$	—		$	186
7.5% due 2044	—			103
	$	—		$	289

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(1) Weighted average interest rates as of December 31, 2011 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 2011, the Company issued or remarketed the following long-term debt:

Company	Month Issued	Type	Interest Rate		Maturity	Amount
	(In millions)
Detroit Edison	April	Tax-Exempt Revenue Bonds (1)	2.35	%	2024	$	31
Detroit Edison	May	Mortgage Bonds (2)	3.90	%	2021	250
DTE Energy	May	Senior Notes (3)	Variable (4)		2013	300
Detroit Edison	September	Mortgage Bonds (5)	4.31	%	2023	102
Detroit Edison	September	Mortgage Bonds (5)	4.46	%	2026	77
Detroit Edison	September	Mortgage Bonds (5)	5.67	%	2041	46
Detroit Edison	September	Tax-Exempt Revenue Bonds (6)	2.13	%	2030	82
Detroit Edison	September	Mortgage Bonds (7)	4.50	%	2041	140
DTE Energy	December	Junior Subordinated Debentures (8)	6.50	%	2061	280
						$	1,308

(1) These bonds were remarketed for a three-year term ending April 1, 2014. The final maturity of the issue is October 1, 2024.

(2) Proceeds were used for general corporate purposes.

(3) Proceeds were used to repay a portion of DTE Energy's $600 million7.05% Senior Notes due June 1, 2011 and for general corporate purposes.

(4) The interest rate is reset quarterly at the three-month LIBOR plus 70 basis points.

(5) Proceeds were used to retire callable tax-exempt revenue bonds and for general corporate purposes.

(6) These bonds were remarketed for a five-year term ending September 1, 2016. The final maturity of the issue is September 1, 2030.

(7) Proceeds were used to retire approximately $140 million of callable tax-exempt revenue bonds and for general corporate purposes.

(8) Proceeds were used to redeem Trust Preferred-Linked Securities.

Debt Retirements and Redemptions

In 2011, the following debt was retired, through optional redemption or payment at maturity:

Company	Month Retired	Type	Interest Rate	Maturity	Amount
	(In millions)
Detroit Edison	May	Tax-Exempt Revenue Bonds	6.95%	2011	$	26
DTE Energy	June	Senior Notes	7.05%	2011	600
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.55%	2029	118
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.65%	2029	67
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.65%	2029	40
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.45%	2029	140
DTE Energy	December	Trust Preferred-Linked Securities	7.80%	2032	186
DTE Energy	December	Trust Preferred-Linked Securities	7.50%	2044	103
					$	1,280

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

	2012		2013		2014		2015		2016		2017 and Thereafter		Total
	(In millions)
Amount to mature	$	519	$	811	$	892	$	476	$	465	$	4,530	$	7,693

Junior Subordinated Debentures

In December 2011, DTE Energy issued $280 million of 6.50% Junior Subordinated Debentures due 2061 with proceeds used to redeem the Trust Preferred-Linked Securities.

The Company has the right to defer interest payments 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. Any deferred interest payments will bear additional interest at the rate of 6.50% per year.

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.

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Regulatory Matters

12 Months Ended

Dec. 31, 2011

Public Utilities, General Disclosures [Abstract]

REGULATORY MATTERS

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. Regulation results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses.

Regulatory Assets and Liabilities

Detroit Edison and MichCon are required to record regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Continued applicability of regulatory accounting treatment 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 discontinuance of this accounting treatment for regulatory assets and liabilities for some or all of our 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 use of regulatory assets and liabilities and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment.

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

	2011			2010
	(In millions)
Assets
Recoverable pension and postretirement costs:
Pension	$	2,208		$	1,742
Postretirement costs	778			624
Asset retirement obligation	420			336
Recoverable Michigan income taxes	324			383
Recoverable income taxes related to securitized regulatory assets	316			400
Choice incentive mechanism	166			105
Accrued PSCR/GCR revenue	147			52
Cost to achieve Performance Excellence Process	116			137
Other recoverable income taxes	81			85
Unamortized loss on reacquired debt	64			65
Recoverable restoration expense	58			19
Deferred environmental costs	49			41
Recoverable uncollectible expense	42			90
Enterprise Business Systems costs	18			21
Recoverable revenue decoupling	18			5
Other	48			53
	4,853			4,158
Less amount included in current assets	(314		)	(100		)
	$	4,539		$	4,058
Securitized regulatory assets	$	577		$	729

	2011			2010
	(In millions)
Liabilities
Asset removal costs	$	419		$	479
Refundable Michigan income taxes	—			418
Renewable energy	192			125
Refundable revenue decoupling	127			47
Negative pension offset	120			129
Refundable income taxes	66			77
Energy Optimization	34			27
Refundable uncollectible expense	31			—
Accrued PSCR/GCR refund	26			8
Low Income Energy Efficiency Fund	26			—
Fermi 2 refueling outage	23			3
Refundable self implemented rates	1			52
Refundable costs under PA 141	—			33
Refundable restoration expense	—			15
Other	8			9
	1,073			1,422
Less amount included in current liabilities	(54		)	(94		)
	$	1,019		$	1,328

As noted below, regulatory assets for which costs have been incurred have been included (or are expected to be included, for costs incurred subsequent to the most recently approved rate case) in Detroit Edison or MichCon’s rate base, thereby providing a return on invested costs. Certain regulatory assets do not result from cash expenditures and therefore do not represent investments included in rate base or have offsetting liabilities that reduce rate base.

ASSETS

• Recoverable pension and postretirement costs — Accounting rules for pension and other postretirement benefit costs require, among other things, the recognition in other comprehensive income of the actuarial gains or losses and the prior service costs that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Detroit Edison and MichCon record the impact of actuarial gains or losses and prior services costs as a Regulatory asset since the traditional rate setting process allows for the recovery of pension and postretirement costs. The asset will reverse as the deferred items are amortized and recognized as components of net periodic benefit costs. (1)

• Asset retirement obligation — This obligation is primarily for Fermi 2 decommissioning costs. The asset captures the timing differences between expense recognition and current recovery in rates and will reverse over the remaining life of the related plant. (1)

• Recoverable Michigan income taxes— In July 2007, the Michigan Business Tax (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 as the related taxable temporary differences reverse and flow through current income tax expense. In May 2011, the MBT was repealed and the Michigan Corporate Income Tax (MCIT) was enacted. The regulatory asset was remeasured to reflect the impact of the MCIT tax rate. (1)

• 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.

• Choice incentive mechanism (CIM) — Detroit Edison receivable for non-fuel revenues lost as a result of fluctuations in electric Customer Choice sales. The CIM was terminated in the October 20, 2011 MPSC order issued to Detroit Edison.

• 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.

• 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 are amortized over a ten-year period beginning with the year subsequent to the year the costs were deferred.

• Other recoverable income taxes — Income taxes receivable from Detroit Edison’s customers representing the difference in property-related deferred income taxes and amounts previously reflected in Detroit Edison’s rates. This asset will reverse over the remaining life of the related plant. (1)

• 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.

• Recoverable restoration expense — Receivable for the MPSC approved restoration expense tracking mechanism that tracks the difference between actual restoration expense and the amount provided for in base rates, recognized pursuant to the MPSC authorization. The restoration expense tracking mechanism was terminated in the October 20, 2011 MPSC order issued to Detroit Edison.

• Deferred environmental costs — The MPSC approved the deferral of investigation and remediation costs associated with Gas Utility’s former MGP sites. Amortization of deferred costs is over a ten-year period beginning in the year after costs were incurred, with recovery (net of any insurance proceeds) through base rate filings.

• Recoverable uncollectible expense (UETM) — Detroit Edison and MichCon receivable for the MPSC approved uncollectible expense tracking mechanism that tracks the difference in the fluctuation in uncollectible accounts and amounts recognized pursuant to the MPSC authorization. The UETM was terminated in the October 20, 2011 MPSC order issued to Detroit Edison.

• Enterprise Business Systems (EBS) costs — The MPSC approved the deferral and amortization over 10 years beginning in January 2009 of EBS costs that would otherwise be expensed.

• Recoverable revenue decoupling — Amounts recoverable from Detroit Edison customers for the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established by the MPSC. Amounts recoverable from MichCon customers for the change in revenue resulting from the difference in weather-adjusted average sales per customer compared to the base level of average sales per customer established by the MPSC.

• 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.

_______________________________________

(1) Regulatory assets not earning a return.

LIABILITIES

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

• Refundable Michigan income taxes — 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. In May 2011, the MBT was repealed and the MCIT was enacted. The state deferred tax assets were eliminated under the MCIT and related regulatory liabilities were remeasured to zero.

• Renewable energy — Amounts collected in rates in excess of renewable energy expenditures.

• Refundable revenue decoupling — Amounts refundable to Detroit Edison customers for the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established by the MPSC. Amounts refundable to MichCon customers for the change in revenue resulting from the difference in weather-adjusted average sales per customer compared to the base level of average sales per customer established by the MPSC.

• Negative pension offset — MichCon’s negative pension costs are not included as a reduction to its authorized rates; therefore, the Company is accruing a regulatory liability to eliminate the impact on earnings of the negative pension expense accrued. This regulatory liability will reverse to the extent MichCon’s pension expense is positive in future years.

• 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.

• Energy Optimization (EO) - The EO plan application is designed to help each customer class reduce their electric usage by: 1) building customer awareness of energy efficiency options and 2) offering a diverse set of programs and participation options that result in energy savings for each customer class.

• Refundable uncollectible expense (UETM )— Detroit Edison and MichCon liability for the MPSC approved uncollectible expense tracking mechanism that tracks the difference in the fluctuation in uncollectible accounts and amounts recognized pursuant to the MPSC authorization. The UETM was terminated in the October 20, 2011 MPSC order issued to Detroit Edison.

• Accrued PSCR refund — Liability 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.

• Low Income Energy Efficiency Fund (LIEEF) — Escrow of LIEEF funds collected by Detroit Edison and MichCon as ordered by the MPSC pursuant to July 2011 Michigan Court of Appeals decision.

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

• Refundable self implemented rates — Amounts refundable to customers for base rates implemented by Detroit Edison and MichCon in excess of amounts authorized in MPSC orders.

• Refundable costs under PA 141 — Detroit Edison’s 2007 CIM reconciliation and allocation resulted in the elimination of Regulatory Asset Recovery Surcharge (RARS) balances for commercial and industrial customers. RARS revenues received that exceed the regulatory asset balances are required to be refunded to the affected classes.

• Refundable restoration expense — Amounts refundable for the MPSC approved restoration expense tracking mechanism that tracks the difference between actual restoration expense and the amount provided for in base rates, recognized pursuant to the MPSC authorization. The restoration expense tracking mechanism was terminated in the October 20, 2011 MPSC order issued to Detroit Edison.

2010 Electric Rate Case Filing

On October 20, 2011, the MPSC issued an order in Detroit Edison's October 29, 2010 rate case filing. The MPSC approved an annual revenue increase of $175 million. Included in the approved increase in revenues was a return on equity of 10.5% on an expected permanent capital structure of 49% equity and 51% debt. Detroit Edison self-implemented a rate increase of $107 million on April 28, 2011. The MPSC stated the net revenue collected due to self-implementation be credited to the 2011 Choice Incentive Mechanism (CIM) regulatory asset, but the order did not define "net revenue." The Company credited the CIM Regulatory Asset for its estimate of the net revenue from self-implementation of approximately $37 million. In November 2011, Detroit Edison petitioned the MPSC for a rehearing and clarification of several issues in the October 2011 MPSC order. On December 20, 2011, the MPSC issued a rehearing order on selected issues, revising the annual revenue increase to $188 million. The rehearing order also affirmed the MPSC's decision to terminate the uncollectible expense tracker mechanism, but deferred ruling on other matters included in Detroit Edison's petition.

Other key aspects of the October 20, 2011 MPSC order include the following:

• adopt a new Revenue Decoupling Mechanism (RDM) effective April 1, 2012, that will compare actual revenue (excluding the impacts of weather) by rate class with the base established in this rate case. The RDM has an annual collar of 1.5% in the first year and 3% in the second and subsequent years. The RDM established in the previous rate case, which considered the impact of weather, was terminated effective October 31, 2011. Therefore, there will be no RDM in place from November 2011 through March 2012;

• recognition of the expiration of a wholesale contract. Since the expiration of the wholesale contract was not until December 31, 2011, the MPSC required Detroit Edison to calculate a customer credit for each kWh sold under the wholesale contract from October 29, 2011 through December 31, 2011, with the credit to be applied in its next PSCR reconciliation;

• the Restoration Expense Tracking Mechanism, Line Clearance Recovery Mechanism, Uncollectible Expense Tracking Mechanism and CIM are terminated as of the date of the order;

• due to uncertainty resulting from the Michigan Court of Appeals overturning collection of the Low Income Energy Efficiency Fund (LIEEF), the MPSC required the continued collection of LIEEF amounts in base rates and placement into escrow pending further orders by the MPSC;

• approval of Detroit Edison's proposal to reduce the Nuclear Decommissioning Surcharge by approximately $20 million annually; and

• implementation of lower depreciation rates previously approved in a June 2011 MPSC order.

2009 Detroit Edison Depreciation Filing

In compliance with an MPSC order, Detroit Edison filed a depreciation case in November 2009. On June 16, 2011, the MPSC issued an order reducing Detroit Edison's composite depreciation rates from 3.33% to 3.06%, effective for accounting and ratemaking purposes, the day after the issuance of the MPSC order in the 2010 rate case.

Renewable Energy Plan (REP)

In August 2010, Detroit Edison filed its reconciliation for the 2009 plan year indicating that the 2009 actual renewable plan revenues and costs approximated the related surcharge revenues and cost of the filed plan. An MPSC order is expected in the first quarter of 2012.

In June 2011, Detroit Edison filed an amended REP with the MPSC requesting authority to continue to recover approximately $100 million of surcharge revenues. The proposed revenues are necessary in order to continue to properly implement Detroit Edison's 20-year REP, to deliver cleaner, renewable electric generation to its customers, to further diversify Detroit Edison's and the State of Michigan's sources of electric supply, and to address the state and national goals of increasing energy independence. On December 20, 2011, the MPSC issued an order approving the amended REP and authorizing the continuation of the surcharges.

In August 2011, Detroit Edison filed its reconciliation for the 2010 plan year indicating that the 2010 actual renewable plan revenues and costs approximated the related surcharge revenues and cost of the filed plan. An MPSC order is expected in the third quarter of 2012.

Energy Optimization (EO) Plans

In April 2011, Detroit Edison and MichCon filed separate applications for approval of their respective reconciliations of their 2010 EO plan expenses. Specifically, Detroit Edison's EO reconciliation includes a cumulative $21 million net over-recovery at year end 2010 for the 2010 EO plan. MichCon's EO reconciliation includes a cumulative $5.6 million net over-recovery at year end 2010 for the 2010 EO plan. In November 2011, the MPSC approved settlement agreements for Detroit Edison and MichCon which authorized the over-recovery balances be included in the 2011 reconciliations.

In September 2011, Detroit Edison and MichCon filed biennial EO Plans with the MPSC as required. Detroit Edison's EO Plan application proposed the recovery of EO expenditures for the period 2012-2015 of $294 million and further requested approval of surcharges to recover these costs. MichCon's EO Plan application proposed the recovery of EO expenditures for the period 2012-2015 of $103 million and further requested approval of surcharges to recover these costs.

Detroit Edison Restoration Expense Tracker Mechanism (RETM) and Line Clearance Tracker (LCT) Reconciliation

In March 2010, Detroit Edison filed an application with the MPSC for approval of the reconciliation of its 2009 RETM and LCT. The Company's 2009 restoration and line clearance expenses were less than the amount provided in rates. Accordingly, Detroit Edison proposed a refund of approximately $16 million, including interest. On May 10, 2011, the MPSC issued an order approving the proposed refund and Detroit Edison began applying credits to customer bills in July 2011.

In March 2011, Detroit Edison filed an application with the MPSC for approval of the reconciliation of its 2010 RETM and LCT. The Company's 2010 restoration expenses were higher than the amount provided in rates. Accordingly, Detroit Edison requested recovery of $19.5 million. In October 2011, the MPSC approved a settlement agreement reconciling the RETM and approving the LCT report. The MPSC authorized surcharges to recover $19.5 million over a three-month period beginning November 1, 2011.

In January 2012, Detroit Edison filed an application with the MPSC for approval of the reconciliation of its 2011 RETM and LCT. The Company's 2011 restoration expenses were higher than the amount provided in rates. Accordingly, Detroit Edison requested net recovery of approximately $44 million.

Detroit Edison Revenue Decoupling Mechanism (RDM)

In May 2011, Detroit Edison filed an application with the MPSC for approval of its initial pilot RDM reconciliation for the period February 2010 through January 2011, requesting authority to refund to customers approximately $56 million, plus interest. This amount was accrued by Detroit Edison at December 31, 2011. There are various interpretations and alternative calculation methodologies relating to the pilot RDM refund calculation that could ultimately be adopted by the MPSC which may result in a range of customer refund amounts from $56 million to $140 million for this initial reconciliation filing under the pilot RDM.

In addition, Detroit Edison has accrued a pilot RDM liability for February 2011 through October 2011 of approximately $71 million, plus interest. Detroit Edison terminated the pilot RDM effective October 2011, and has requested a rehearing on this issue asserting that for reconciliation purposes, the pilot RDM should have been considered terminated in April 2011, when the Detroit Edison self-implemented rates, consistent with prior MPSC orders. An April 2011 termination would result in a decrease to the liability. However, there can be no assurance that Detroit Edison will prevail in this matter. Similar to the initial reconciliation case, there are various interpretations and alternative calculation methodologies that could be adopted which may result in a range of refund obligations in excess of the amount accrued. Considering these variables, the potential customer refund amount could range from $10 million to $130 million for the second and final pilot RDM period.

The primary uncertainties involved in the calculation methodologies of the pilot RDM for both reconciliation periods include customer class groupings and treatment of fixed customer charges. The Company believes that the calculation methodology used and the resulting refund estimates recorded follow the requirements and intent of the MPSC orders and represent the most probable amount of Detroit Edison's pilot RDM refund liability as of December 31, 2011. An MPSC order on the initial filing is expected in the first half of 2012. Detroit Edison is required to file an application with the MPSC for approval of its RDM reconciliation for the period February 2011 through October 2011 by May 2012. A newly designed RDM will be in effect beginning April 2012.

Detroit Edison Uncollectible Expense True-Up Mechanism (UETM)

In March 2011, Detroit Edison filed an application with the MPSC for approval of its UETM for 2010 requesting authority to refund approximately $7 million consisting of costs related to 2010 uncollectible expense. In August 2011, the MPSC approved a settlement agreement for the 2010 UETM authorizing a refund of approximately $7 million to be applied as credits to customer bills beginning September 1, 2011.

Detroit Edison Choice Incentive Mechanism (CIM)

In March 2011, Detroit Edison filed an application with the MPSC for approval of its CIM reconciliation for 2010 requesting recovery of approximately $105 million. On December 6, 2011, the MPSC approved a settlement agreement for the 2010 CIM authorizing surcharges of approximately $105 million effective on a service rendered basis for the 12-month period beginning January 1, 2012.

On January 17, 2012, Detroit Edison filed an application with the MPSC for approval of its CIM reconciliation for the period from January 1, 2011 through October 28, 2011. The termination date of the CIM pursuant to the October 20, 2011 MPSC rate order is October 20, 2011. Detroit Edison requested recovery of approximately $73 million, net of the self implementation credit applied per MPSC order.

Power Supply Cost Recovery Proceedings

The PSCR process is designed to allow Detroit Edison to recover all of its power supply costs if incurred under reasonable and prudent policies and practices. Detroit Edison's power supply costs include fuel and related transportation costs, purchased and net interchange power costs, nitrogen oxide and sulfur dioxide emission allowances costs, urea costs, transmission costs and MISO costs. The MPSC reviews these costs, policies and practices for prudence in annual plan and reconciliation filings.

2010 PSCR Year - In March 2011, Detroit Edison filed the 2010 PSCR reconciliation calculating a net under-recovery of $52.6 million that includes an over-recovery of $15.6 million for the 2009 PSCR year. In addition, the 2010 PSCR reconciliation includes an under-recovery of $7.1 million for the reconciliation of the 2007-2008 Pension Equalization Mechanism, and an over-refund of $3.8 million for the 2011 refund of the self-implemented rate increase related to the 2009 electric rate case filing.

2011 Plan Year - In September 2010, Detroit Edison filed its 2011 PSCR plan case seeking approval of a levelized PSCR factor of 2.98 mills/kWh below the amount included in base rates for all PSCR customers. The filing supports a total power supply expense forecast of $1.2 billion. The plan also includes approximately $36 million for the recovery of its projected 2010 PSCR under-recovery. An MPSC order was issued on December 6, 2011 approving the 2011 PSCR.

2012 Plan Year - In September 2011, Detroit Edison filed its 2012 PSCR plan case seeking approval of a levelized PSCR factor of 4.18 mills/kWh above the amount included in base rates for all PSCR customers. The filing supports a total power supply expense forecast of $1.4 billion. The plan also includes approximately $158 million for the recovery of its projected 2011 PSCR under-recovery.

Low Income Energy Efficiency Fund

The Customer Choice and Electricity Reliability Act of 2000 authorized the creation of the LIEEF administered by the MPSC. The purpose of the fund is to provide shut-off and other protection for low income customers and to promote energy efficiency by all customer classes. Detroit Edison and MichCon collect funding for the LIEEF as part of their base rates and remit the funds to the State of Michigan monthly. In July 2011, the Michigan Court of Appeals issued a decision reversing the portion of MichCon's June 2010 MPSC rate order that permitted MichCon to recover funding for the LIEEF in base rates. In response to the Court of Appeals decision, Detroit Edison and MichCon ceased remitting payments for LIEEF funding to the State of Michigan. In October 2011, the MPSC issued orders directing Detroit Edison and MichCon to continue collecting funds for LIEEF in rates and to escrow the collected funds pending further order by the MPSC. On January 26, 2012, the MPSC issued an order directing Detroit Edison and MichCon to file comprehensive plans by March 1, 2012 for refunding previously escrowed LIEEF funds of $23 million and $3 million, respectively. On December 20, 2011, The Vulnerable Household Warmth Fund (VHWF) was created under Michigan law. The purpose of the fund is to provide payment or partial payment of bills for electricity, natural gas, propane, heating oil, or any other type of fuel used to heat the primary residence of a vulnerable customer during the 2011-2012 heating season. Effective with the new law, Detroit Edison and MichCon are to contribute the amounts collected in their base rates, previously remitted for the LIEEF, to the new VHWF. The monthly payments into the VHWF will cease on the earlier of September 30, 2012 or when $48 million has been is accumulated in the fund from payments by major Michigan electric and gas utilities.

MichCon UETM

In March 2011, MichCon filed an application with the MPSC for approval of its UETM for 2010 requesting recovery of approximately $31 million, consisting of $7 million related to 2010 uncollectible expense and $24 million related to the 2008 UETM under-collection. In September 2011, the MPSC approved a settlement agreement approving the 2010 UETM and the implementation of a surcharge beginning October 1, 2011.

MichCon Revenue Decoupling Mechanism (RDM)

In September 2011, MichCon filed an application with the MPSC for approval of its RDM reconciliation for the period July 1, 2010 through June 30, 2011. MichCon's RDM application proposed the recovery of approximately $20 million.

Gas Cost Recovery Proceedings

The GCR process is designed to allow MichCon to recover all of its gas supply costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs, policies and practices for prudence in annual plan and reconciliation filings.

2009-2010 GCR Year - An MPSC order was issued on December 6, 2011 for the GCR reconciliation for the 12-month period ended March 31, 2010 disallowing recovery of $3.3 million related to the pricing of certain gas purchases from an affiliate. The MPSC also authorized MichCon to include in its 2010-2011 GCR reconciliation beginning balance the net overrecovery of approximately $9 million.

2010-2011 Plan Year - In June 2011, MichCon filed its 2010-2011 GCR plan year reconciliation case calculating a net over-recovery of $1 million, including interest. This over-recovery does not reflect the December 6, 2011 MPSC order on the 2009-2010 plan year reconciliation case.

2011-2012 Plan Year - In December 2010, MichCon filed its GCR plan case for the 2011-2012 GCR plan year. MichCon filed for a maximum base GCR factor of $5.89 per Mcf adjustable monthly by a contingency factor.

2012-2013 Plan Year - In December 2011, MichCon filed its GCR plan case for the 2012-2013 GCR plan year. MichCon filed for a maximum base GCR factor of $5.18 per Mcf adjustable monthly by a contingency factor.

Gas Main Renewal and Gas Meter Move Out Programs

The June 3, 2010 MPSC gas rate case order required MichCon to make filings related to gas main renewal and meter move-out programs. In a July 30, 2010 filing, MichCon proposed to implement a 10-year gas main renewal program beginning in 2012 which would require capital expenditures of approximately $17 million per year for renewing gas distribution mains, retiring gas mains, and where appropriate and when related to the gas main renewal or retirement activity, relocate inside meters to outside locations and renew service lines. In a September 30, 2010 filing, MichCon proposed to implement a 10-year gas meter move out program beginning in 2012 which would require capital expenditures of approximately $22 million per year primarily for relocation of inside meters to the outside of residents' houses. In September 2011, the MPSC issued orders approving both programs and requested MichCon to include the recovery of costs associated with these two programs in future MichCon rate cases.

Other

The Company is unable to predict the outcome of the unresolved 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.

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Regulatory Matters (Details Textuals) (USD $)	3 Months Ended	6 Months Ended	9 Months Ended	12 Months Ended		9 Months Ended	12 Months Ended		48 Months Ended
	Mar. 31, 2011	Jun. 30, 2011 percent	Sep. 30, 2011 MCF kWh years percent months	Dec. 31, 2011 years MCF months	Dec. 31, 2010	Sep. 30, 2011 Electric Utility [Member]	Dec. 31, 2011 Electric Utility [Member]	Dec. 31, 2011 Gas Utility [Member]	Dec. 31, 2015 Gas Utility [Member]
Regulatory Asset and Liability [Line Items]
Time Period Required by Non-Bypassable Securitization Bond Surcharge to Recover Securitized Regulatory Asset				14
Deferral of Investigation and Remediation of Costs Associated with Gas Utilities Former MGP Sites				10
Amortization Period of Cost to Achieve Deferral				10
MPSC Approved Annual Rate Increase			$ 175,000,000
MPSC Approved Return on Equity			10.50%
Expected Permanent Capital Structure Equity Percent			49.00%
Expected Permanent Capital Structure Debt Percent			51.00%
Self Implemented Rate Increase		107,000,000
Amount of Credit to CIM Regulatory Asset			37,000,000
Revised Annual Rate Increase				188,000,000
Annual Revenue Decoupling Mechanism Collar on Surcharge and Refund Year 1			1.50%
Annual Revenue Decoupling Mechanism Collar on Surcharge and Refund Year 2 and Subsequent Years			3.00%
To Reduce Nuclear Decommisssioning Surcharge Annually			20,000,000
Current Composite Depreciation Rate		3.33%
New Composite Depreciation Rates		3.06%
Additional Revenue for Renewable Energy Plan		100,000,000
Period to Implement Electric Utilities Renewable Energy Plan				20
Energy Optimization Overrecovery Electric Utility	21,000,000
Energy Optimization Overrecovery Gas Utility	5,600,000
Requested Recovery of Enery Optimization Expenses for Future Period						294,000,000			103,000,000
Proposed Refund of Restoration and Line Clearance Expense		16,000,000
Requested Recovery of Restoration Expenses	19,500,000
MPSC Authorized Surcharges to Recover Restoration Expenses			19,500,000
Period to Recover Surcharges for RETM and LCT			3
Requested net recovery of RETM and LCT			44,000,000
Requested Authority to Refund Revenue Decoupling Mechanism		56,000,000
RDM Refund Range Minimum First Pilot				56,000,000
RDM Refund Range Maximum First Pilot				140,000,000
Possible Refund Calculations for Revenue Decoupling Mechanism Maximum			71,000,000
RDM Refund Range Minimum Second Pilot				10,000,000
RDM Refund Range Maximum Second Pilot				130,000,000
Requesting Authority to Refund Uncollectible Expense to Customers	7,000,000
MPSC Authorized Refund to Customer Bills			7,000,000
Requested Recovery of Electric Utility Choice Incentive Mechanism					105,000,000
Approved Recovery of Electric Utility Choice Incentive Mechanism				105,000,000
Period to Apply Approved Electric Utility Choice Icentive Mechanism Surcharges				12
Requested Recovery Net of the Self Implementation Credit Applied per MPSC Order			73,000,000
Net Under Recovery of Power Suppy Cost Recovery Expense	52,600,000
Net Over Recovery of Power Supply Cost Recovery Expense			15,600,000
Under Recovery for the Pension Equalization Mechanism			7,100,000
Overy Recovery on Refund for Self Implemented Rates			3,800,000
Power Supply Cost Recovery Plan Case Factor Current Year			2.98
Power Supply Cost Recovery Expense Forecast For Current Year			1,200,000,000
Power Supply Cost Recovery Under Collection One Year Prior			36,000,000
Power Supply cost Recovery Plan Case Factor Next Year			4.18
Power Supply Cost Recovery Expense Forecast Next Year			1,400,000,000
Projected Power Supply Cost Recovery Under Recovery for Current Year			158,000,000
Escrowed LIEEF Amounts							23,000,000	3,000,000
Vulnerable household warmth fund amount to be collected				48,000,000
MPSC Authorized Recovery of Uncollectibe Expense	31,000,000
Uncollectibe Expense Prior Year			7,000,000
Uncollectible Expense Tracking Mechanism Under Collection Three Years Prior			24,000,000
Requested Recovery for Revenue Decoupling Mechanism			20,000,000
Period of Gas Cost Recovery Reconciliation				12
Disallowed Recovery Related fo the Pricing of Certain Gas Purchases				3,000,000
Gas Cost Reconciliation Over Recovery				9,000,000
GCR Plan Case Factor Current Year and Next Year			5.89
GCR Plan Case Factor Next Year and Following Year				5
Gas Main Renewal Program Implentation Time Period			10
Gas Main Renewal Program Capital Expenditures			17,000,000
Gas Meter Move Out Program Implementation Time Period			10
Gas Meter Move Out Program Capital Expenditures			$ 22,000,000

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Jointly Owned Utility Plant

12 Months Ended

Dec. 31, 2011

Jointly Owned Utility Plant [Abstract]

Jointly Owned Utility Plant [Text Block]

JOINTLY OWNED UTILITY PLANT

Detroit Edison has joint ownership interest in two power plants, Belle River and Ludington Hydroelectric Pumped Storage. Detroit Edison’s share of direct expenses of the jointly owned plants are included in Fuel, purchased power and gas and Operation and maintenance expenses in the Consolidated Statements of Operations. Ownership information of the two utility plants as of December 31, 2011 was as follows:

	Belle River			Ludington Hydroelectric Pumped Storage
In-service date	1984-1985			1973
Total plant capacity	1,270		MW	1,872		MW
Ownership interest	*			49		%
Investment (in millions)	$	1,645		$	199
Accumulated depreciation (in millions)	$	943		$	158

_______________________________________

* 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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Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Comprehensive Income [Line Items]
Net Unrealized Gain/(Loss) on Derivaive	$ (4)	$ (4)
Net Unrealized Gain/(Loss) on Investments	(30)	(30)
Benefit Obligations	(125)	(116)
Foreign Currency Translation	1	1
Accumulated Other Comprehensive Loss	(158)	(149)
Current period change, net of tax Net Unrealized Gain/(Loss) on Derivatives Gain (Loss) on Derivatives Arising During Period, Net of Tax	0	1	3
Current period change, net of tax Net Unrealized Gain/(Loss) on Investments	0	(20)	8
Current period change, net of tax Benefit Obligations	(9)	15	7
Current period change, net of tax Foreign Currency Translation	0	1	2
Current period change, net of tax AccumulatedOther Comprehensive Loss	$ (9)

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Retirement Benefits and Trusteed Assets (Details 4) (Pension Plans, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2011
Pension Plans, Defined Benefit [Member]
Pension Benefits to be Paid Over the Next 5 Years and Thereafter [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in 2012	$ 240
Defined Benefit Plan, Expected Future Benefit Payments in 2013	239
Defined Benefit Plan, Expected Future Benefit Payments in 2014	244
Defined Benefit Plan, Expected Future Benefit Payments in 2015	253
Defined Benefit Plan, Expected Future Benefit Payments in 2016	260
Defined Benefit Plan, Expected Future Benefit Payments in 2017-2021	1,439
Total Defined Benefit Pension Plan Expected Future Payments	$ 2,675

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Goodwill

12 Months Ended

Dec. 31, 2011

Goodwill [Abstract]

Goodwill and Intangible Assets Disclosure [Text Block]

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, 2011and December 31, 2010 is as follows:

	2011		2010
	(In millions)
Balance as of January 1	$	2,020	$	2,024
Goodwill attributable to sale of subsidiary in Power and Industrial Projects segment	—		(4		)
Balance at December 31	$	2,020	$	2,020

In September 2011, the FASB issued ASU No. 2011-08, Intangibles-Goodwill and Other (Topic 350)—Testing Goodwill for Impairment, which is intended to simplify how entities test for goodwill impairment by permitting an entity the option of performing a qualitative assessment to determine whether further impairment testing is necessary. The standard will be effective for annual and interim goodwill impairments tests for fiscal years beginning after December 15, 2011. The adoption of ASU 2011-08 is not expected to have a material impact to the Company's financial statements.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2011

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure [Text Block]

PROPERTY, PLANT AND EQUIPMENT

Summary of property by classification as of December 31:

	2011			2010
	(In millions)
Property, Plant and Equipment
Electric Utility
Generation	$	9,785		$	9,268
Distribution	7,003			6,800
Total Electric Utility	16,788			16,068
Gas Utility
Distribution	2,561			2,460
Storage	406			395
Other	902			991
Total Gas Utility	3,869			3,846
Non-utility and other	1,884			1,660
Total	22,541			21,574
Less Accumulated Depreciation, Depletion and Amortization
Electric Utility
Generation	(3,946		)	(3,850		)
Distribution	(2,580		)	(2,568		)
Total Electric Utility	(6,526		)	(6,418		)
Gas Utility
Distribution	(1,041		)	(1,019		)
Storage	(127		)	(108		)
Other	(413		)	(512		)
Total Gas Utility	(1,581		)	(1,639		)
Non-utility and other	(688		)	(525		)
Total	(8,795		)	(8,582		)
Net Property, Plant and Equipment	$	13,746		$	12,992

AFUDC capitalized during 2011 and 2010 was approximately $10 million.

The composite depreciation rate for Detroit Edison was approximately 3.3% in 2011, 2010 and 2009. The composite depreciation rate for MichCon was 2.3% in 2011, 2.5% in 2010 and 3.1% in 2009.

The average estimated useful life for each major class of utility property, plant and equipment as of December 31, 2011 follows:

	Estimated Useful Lives in Years
Utility	Generation	Distribution	Transmission
Electric	46	43	N/A
Gas	N/A	62	61

The estimated useful lives for major classes of non-utility assets and facilities ranges from 3 to 55 years.

Capitalized software costs are classified as Property, plant and equipment and the related amortization is included in Accumulated depreciation, depletion and amortization 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 capitalized software costs on a straight-line basis over the expected period of benefit, ranging from 3 to 20 years.

Capitalized software costs amortization expense was $65 million in 2011 and 2010 and $66 million in 2009. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2011 were $623 million and $300 million, respectively. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2010 were $602 million and $252 million, respectively. Amortization expense of capitalized software costs is estimated to be approximately $64 million annually for 2012 through 2016.

Gross property under capital leases was $57 million and $153 million at December 31, 2011 and December 31, 2010, respectively. Accumulated amortization of property under capital leases was $34 million and $114 million at December 31, 2011 and December 31, 2010, respectively.

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Segment Information (Details 1) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Segment Reporting Information [Line Items]
Depreciation, Depletion and Amortization									$ 995	$ 1,027	$ 1,020
Interest Expense									494	549	545
Income Taxes									(205)	93	18
Net Income Attributable to DTE Energy Company	150	183	202	176	152	163	86	229	711	630	532
Total Assets	26,009				24,896				26,009	24,896
Goodwill	2,020				2,020				2,020	2,020	2,024
Electric Utility [Member]
Segment Reporting Information [Line Items]
Operating Revenue									5,154	4,993	4,714
Depreciation, Depletion and Amortization									818	849	844
Interest Income									(1)	(1)	(1)
Interest Expense									289	313	324
Income Taxes									265	270	228
Net Income Attributable to DTE Energy Company									434	441	376
Total Assets	17,370				16,375				17,370	16,375	15,879
Goodwill	1,208				1,206				1,208	1,206	1,206
Capital Expenditures									1,203	864	794
Gas Utility [Member]
Segment Reporting Information [Line Items]
Operating Revenue									1,505	1,648	1,788
Depreciation, Depletion and Amortization									89	92	107
Interest Income									(7)	(9)	(8)
Interest Expense									64	66	68
Income Taxes									60	67	39
Net Income Attributable to DTE Energy Company									110	127	80
Total Assets	3,933				3,854				3,933	3,854	3,832
Goodwill	745				759				745	759	759
Capital Expenditures									179	147	166
Gas Storage and Pipelines [Member]
Segment Reporting Information [Line Items]
Operating Revenue									91	83	82
Depreciation, Depletion and Amortization									6	5	5
Interest Income									(5)	(1)	(1)
Interest Expense									7	6	10
Income Taxes									35	32	33
Net Income Attributable to DTE Energy Company									57	51	49
Total Assets	421				391				421	391	367
Goodwill	22				9				22	9	9
Capital Expenditures									16	5	2
Unconventional Gas Production [Member]
Segment Reporting Information [Line Items]
Operating Revenue									39	32	31
Depreciation, Depletion and Amortization									18	15	16
Interest Income									0	0	0
Interest Expense									7	6	6
Income Taxes									(3)	(6)	(4)
Net Income Attributable to DTE Energy Company									(6)	(11)	(9)
Total Assets	319				308				319	308	309
Goodwill	2				2				2	2	2
Capital Expenditures									29	27	26
Power and Industrial Projects [Member]
Segment Reporting Information [Line Items]
Operating Revenue									1,129	1,144	661
Depreciation, Depletion and Amortization									60	60	40
Interest Income									(8)	(3)	(3)
Interest Expense									32	33	30
Income Taxes									11	3	(7)
Net Income Attributable to DTE Energy Company									38	85	31
Total Assets	1,210				1,236				1,210	1,236	1,118
Goodwill	26				27				26	27	31
Capital Expenditures									56	53	45
Energy Trading [Member]
Segment Reporting Information [Line Items]
Operating Revenue									1,276	875	804
Depreciation, Depletion and Amortization									3	5	5
Interest Income									0	0	(1)
Interest Expense									9	13	10
Income Taxes									34	5	37
Net Income Attributable to DTE Energy Company									52	6	75
Total Assets	552				483				552	483	552
Goodwill	17				17				17	17	17
Capital Expenditures									1	1	2
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating Revenue									4	1	0
Depreciation, Depletion and Amortization									1	1	3
Interest Income									(47)	(47)	(55)
Interest Expense									144	160	147
Income Taxes									(134)	(60)	(79)
Net Income Attributable to DTE Energy Company									26	(69)	(70)
Total Assets	2,204				2,249				2,204	2,249	2,138
Goodwill	0				0				0	0	0
Capital Expenditures									0	0	0
Corporate Elimination [Member]
Segment Reporting Information [Line Items]
Operating Revenue									(301)	(219)	(66)
Depreciation, Depletion and Amortization									0	0	0
Interest Income									58	49	50
Interest Expense									(58)	(48)	(50)
Income Taxes									(1)	0	0
Net Income Attributable to DTE Energy Company									0	0	0
Total Assets	0				0				0	0	0
Goodwill	0				0				0	0	0
Capital Expenditures									0	0	0
Total [Member]
Segment Reporting Information [Line Items]
Operating Revenue									8,897	8,557	8,014
Depreciation, Depletion and Amortization									995	1,027	1,020
Interest Income									(10)	(12)	(19)
Interest Expense									494	549	545
Income Taxes									267	311	247
Net Income Attributable to DTE Energy Company									711	630	532
Total Assets	26,009				24,896				26,009	24,896	24,195
Goodwill	2,020				2,020				2,020	2,020	2,024
Capital Expenditures									$ 1,484	$ 1,097	$ 1,035

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligation [Abstract]

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS

The Company has a legal retirement obligation for the decommissioning costs for its Fermi 1 and Fermi 2 nuclear plants, gas production facilities, gas gathering facilities and various other operations. The Company has conditional retirement obligations for gas pipelines, asbestos at certain of its power plants, 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 when they are incurred, which generally is 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. In its regulated operations, the Company recognizes regulatory assets or liabilities for timing differences in expense recognition for legal asset retirement costs that are currently recovered in rates.

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 2011 follows:

	(In millions)
Asset retirement obligations at January 1, 2011	$	1,514
Accretion	93
Liabilities incurred	10
Liabilities settled	(23		)
Revision in estimated cash flows	(1		)
Asset retirement obligations at December 31, 2011	1,593
Less amount included in current liabilities	(2		)
	$	1,591

In 2001, Detroit Edison began the final decommissioning of Fermi 1, with the goal of removing the remaining radioactive material and terminating the Fermi 1 license. In 2011, based on management decisions revising the timing and estimate of cash flows, Detroit Edison accrued an additional $19 million with respect to the decommissioning of Fermi 1. Management intends to suspend decommissioning activities and place the facility in safe storage status. The expense amount has been recorded in Asset (gains) and losses, reserves and impairments, net on the Consolidated Statements of Operations. In addition, based on updated studies revising the timing and estimate of cash flows, a reduction of approximately $20 million was made to the Detroit Edison asset retirement obligation for asbestos removal with approximately $6 million of the decrease associated with Fermi 1 recorded in Asset (gains) and losses, reserves and impairments, net on the Consolidated Statements of Operations.

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 Consolidated Statements of Financial Position. In October 2011, the MPSC approved Detroit Edison's request for a reduction to the nuclear decommissioning surcharge under the assumption that it would request an extension of the Fermi 2 license for an additional 20 years beyond the term of the existing license which expires in 2025. Detroit Edison expects to request the license extension in 2014. This proposed extension of the license, including the associated impact on spent nuclear fuel, resulted in a revision in estimated cash flows for the Fermi 2 asset retirement obligation of approximately $22 million. It is estimated that the cost of decommissioning Fermi 2 is $1.4 billion in 2011 dollars and $10 billion in 2045 dollars, using a 6% inflation rate. Approximately $1.4 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.

The NRC has jurisdiction over the decommissioning of nuclear power plants and requires minimum 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. The decommissioning assets, anticipated earnings thereon and future revenues from decommissioning collections will be used to decommission Fermi 2. The Company expects the liabilities to be reduced to zero at the conclusion of the decommissioning activities. If amounts remain in the trust funds for Fermi 2 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 liability. The decommissioning of Fermi 1 is funded by Detroit Edison. Contributions to the Fermi 1 trust are discretionary. See Note 3 for additional discussion of Nuclear Decommissioning Trust Fund Assets.

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Fair Value (Details 2) (USD $) In Billions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Fair Value of Long Term Debt [Line Items]
Long-Term Debt, Fair value	$ 8.8	$ 8.5
Long-Term Debt, Carrying value	$ 7.7	$ 8.0

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Retirement Benefits and Trusteed Assets Retirement Benefits and Trusteed Assets (Details 14) (Other Postretirement Benefit Plans, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 985	$ 1,029	$ 864
Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	525	345
Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	305	550
Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	155	134
Short-term investments [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	13	8
Short-term investments [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Short-term investments [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	13	8
Short-term investments [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Us Large Cap Equity Securities [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	190	188
Us Large Cap Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	175	126
Us Large Cap Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	15	62
Us Large Cap Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
US Small Cap and Mid Cap Equity Securities [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	76	118
US Small Cap and Mid Cap Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	70	60
US Small Cap and Mid Cap Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	6	58
US Small Cap and Mid Cap Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Non US Equity Securities [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	190	201
Non US Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	176	79
Non US Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	14	122
Non US Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fixed income securities [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	260	256
Fixed income securities [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	24	4
Fixed income securities [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	236	252
Fixed income securities [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Hedge Funds and Similar Investments [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	196	203
Hedge Funds and Similar Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	80	76
Hedge Funds and Similar Investments [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	21	48
Hedge Funds and Similar Investments [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	95	79
Private Equity and Other [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	60
Private Equity and Other [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0
Private Equity and Other [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0
Private Equity and Other [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	60
Other [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		55
Other [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Other [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Other [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 55

XML

Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2011 percent	Dec. 31, 2010 percent	Dec. 31, 2009 percent
Reconciliation of Income Tax Expense to Federal Tax Rate [Line Items]
Income before income taxes		$ 987	$ 950	$ 782
Income tax expense at 35% statutory rate		345	333	274
Production tax credits		(6)	(33)	(12)
Investment tax credits		(6)	(6)	(7)
Depreciation		(4)	(4)	(4)
Employee Stock Ownership Plan dividends		(4)	(5)	(5)
Medicare part D subsidy		0	0	(6)
Domestic production activities deduction		(7)	(7)	(5)
Goodwill attributed to the sale of Gas Utility subsidiaries		0	0	4
Settlement of Federal tax audit		0	(12)	(11)
State and Local income taxes, net of federal benefit		37	44	25
Enactment of Michigan Corporate income Tax, net of federal expense		(87)	0	0
Other, net		(1)	1	(6)
Income Tax Expense	$ 87	$ 267	$ 311	$ 247
Effective Income Tax Rate		27.10%	32.70%	31.60%

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Fair Value (Details 4) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Fair Value, Option, Quantitative Disclosures [Line Items]
Realized gains	$ 46	$ 192	$ 37
Realized losses	(38)	(83)	(55)
Proceeds from sales of securities	$ 80	$ 377	$ 295

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Capital and Operating (Details 1) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011
Capital Lease Receivable [Line Items]
Capital Lease Payments Receivable in 2012	$ 12
Capital Lease Payments Receivable in 2013	12
Capital Lease Payments Receivable in 2014	12
Capital Lease Payments Receivable in 2015	12
Capital Lease Payments Receivable in 2016	12
Capital Lease Payments Receivable Thereafter	43
Total minimum future lease receipts	103
Residual value of leased pipeline	40
Less unearned income	(56)
Net Iivestment in Capital lease	87
Less current portion	(4)
Capital Leases, Lessor Balance Sheet, Net Investment in Direct Financing Leases, Noncurrent	$ 83

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Fair Value (Details 1) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis
Beginning Balance	$ 59	$ 24
Transfers into Level 3	4	9
Transfer out of Level 3	(24)	35
Total gains: [Abstract]
Included in earnings	87	69
Recorded in regulatory assets/liabilities	2
Purchases issuances and settlements [Abstract]
Purchases	3
Settlements	(87)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Other Comprehensive Income (Loss)		6
Purchases, issuances and settlements		(87)
Ending Balance	44	59
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	75	(9)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net		47
Natural Gas [Member]
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis
Beginning Balance	1	2
Transfers into Level 3	0
Transfer out of Level 3	1
Total gains: [Abstract]
Included in earnings	7	4
Recorded in regulatory assets/liabilities	0
Purchases issuances and settlements [Abstract]
Purchases	0
Settlements	(3)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Other Comprehensive Income (Loss)		0
Purchases, issuances and settlements		(8)
Ending Balance	6	1
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	8	(4)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net		3
Electricity [Member]
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis
Beginning Balance	54	19
Transfers into Level 3	4
Transfer out of Level 3	(25)
Total gains: [Abstract]
Included in earnings	77	64
Recorded in regulatory assets/liabilities	0
Purchases issuances and settlements [Abstract]
Purchases	3
Settlements	(81)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Other Comprehensive Income (Loss)		0
Purchases, issuances and settlements		(73)
Ending Balance	32	54
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	65	(6)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net		44
Other [Member]
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis
Beginning Balance	4	3
Transfers into Level 3	0
Transfer out of Level 3	0
Total gains: [Abstract]
Included in earnings	3	1
Recorded in regulatory assets/liabilities	2
Purchases issuances and settlements [Abstract]
Purchases	0
Settlements	(3)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Other Comprehensive Income (Loss)		6
Purchases, issuances and settlements		(6)
Ending Balance	6	4
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	2	1
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net		$ 0

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Earnings Per Share (Details Textuals) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	5	4

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Stock-Based Compensation (Details 6) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Compensation Expense Recorded [Line Items]
Compensation expense	$ 66	$ 52	$ 56
Performance Share Awards [Member]
Compensation Expense Recorded [Line Items]
Compensation expense	53	36	35
Cash settlements (1)	3	3	1
Stock settlements (1)	$ 25	$ 23	$ 8

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Significant Accounting Policies

3 Months Ended

12 Months Ended

Dec. 31, 2011

Dec. 31, 2011

Accounting Policies [Abstract]

Revenues Policy [Policy Text Block]

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 electricity and gas provided but unbilled at the end of each month. Rates for Detroit Edison and MichCon include provisions to adjust billings for fluctuations in fuel and purchased power costs, cost of natural gas and certain other costs. Revenues are adjusted for differences between actual costs and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are recorded on the Consolidated Statement of Financial Position and are recovered or returned to customers through adjustments to the billing factors.

Detroit Edison had a CIM, which was an over/under recovery mechanism that measured non-fuel revenues lost or gained as a result of fluctuations in electric Customer Choice sales. If annual electric Customer Choice sales exceeded the baseline amount from Detroit Edison's most recent rate case, 90 percent of its lost non-fuel revenues associated with sales above that level may be recovered from full service customers. If annual electric Customer Choice sales decreased below the baseline, the Company must refund 90 percent of its increase in non-fuel revenues associated with sales below that level to full service customers. The CIM was terminated effective with the October 20, 2011 MPSC rate order. On January 17, 2012, Detroit Edison filed an application with the MPSC for approval of its CIM reconciliation for 2011.

Detroit Edison and MichCon had RDMs in place in 2011 designed to minimize the impact on revenues of changes in average customer usage of electricity and natural gas. The electric RDM enabled Detroit Edison to recover or refund the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established in the MPSC order. The 2011 pilot RDM established in Detroit Edison's 2009 rate case was terminated by the MPSC in October 2011, but the Company has requested rehearing on this point asserting the termination should have occurred in April 2011. Detroit Edison will have a newly designed RDM that will be effective in April 2012. See Note 11 for further discussion of the newly designed RDM. The June 2010 MPSC order in MichCon's 2009 rate case provided for the implementation of a pilot gas RDM effective July 1, 2010, which enables MichCon to recover or refund the change in revenue resulting from the difference in weather-adjusted average sales per customer compared to the base average sales per customer established in the MPSC order. The gas RDM is subject to review in future MPSC proceedings during the pilot program. The gas RDM addresses changes in customer usage due to general economic conditions and conservation, but does not shield MichCon from the impacts of lost customers or weather variations.

See Note 11 for further discussion of recovery mechanisms authorized by the MPSC.

Non-utility businesses recognize revenues as services are provided and products are delivered. Revenues and energy costs related to trading contracts are presented on a net basis in the Consolidated Statements of Operations. Commodity derivatives used for trading purposes are accounted for using the mark-to-market method with unrealized gains and losses recorded in Operating Revenues.

Accounting For ISO Transactions [Policy Text Block]

Accounting for ISO Transactions

Detroit Edison participates in the energy market through MISO. MISO requires that we submit hourly day-ahead, real time and FTR bids and offers for energy at locations across the MISO region. Detroit Edison accounts for MISO transactions on a net hourly basis in each of the day-ahead, real-time and FTR markets and net transactions across all MISO energy market locations. In any single hour Detroit Edison records net purchases in Fuel, purchased power and gas and net sales in Operating revenues on the Consolidated Statements of Operations. Detroit Edison records net sale billing adjustments when invoices are received.

Energy Trading participates in the energy markets through various independent system operators and regional transmission organizations (ISOs and RTOs). These markets require that we submit hourly day-ahead, real time bids and offers for energy at locations across each region. We submit bids in the annual and monthly auction revenue rights and FTR auctions to the regional transmission organizations. Energy Trading accounts for these transactions on a net hourly basis for the day-ahead, real-time and FTR markets. These transactions are related to our trading contracts which are presented on a net basis in Operating revenues in the Consolidated Statements of Income.

Detroit Edison and Energy Trading record expense accruals for future net purchases adjustments based on historical experience, and reconcile accruals to actual expenses when invoices are received from MISO, the ISOs and RTOs.

Comprehensive Income [Policy Text Block]

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 accumulated other comprehensive loss for the year ended December 31, 2011 include unrealized gains and losses from derivatives accounted for as cash flow hedges, unrealized gains and losses on available for sale securities, the Company’s interest in comprehensive income of equity investees, changes in benefit obligations, consisting of deferred actuarial losses, prior service costs and transition amounts related to pension and other postretirement benefit plans, and foreign currency translation adjustments.

Cash and Cash Equivalents [Policy Text Block]

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, primarily Securitization bonds, and partnership operating agreements. Restricted cash designated for interest and principal payments within one year is classified as a current asset.

Receivables [Policy Text Block]

Receivables

Accounts receivable are primarily composed of trade receivables and unbilled revenue. Our accounts receivable are stated at net realizable value.

The allowance for doubtful accounts for Detroit Edison and MichCon is generally calculated using the aging approach that utilizes rates developed in reserve studies. We establish an allowance for uncollectible accounts based on historical losses and management’s assessment of existing economic conditions, customer trends, and other factors. Customer accounts are generally considered delinquent if the amount billed is not received by the due date, which is typically in 21 days, however, factors such as assistance programs may delay aggressive action. We assess late payment fees on trade receivables based on past-due terms with customers. Customer accounts are written off when collection efforts have been exhausted, generally one year after service has been terminated.

The customer allowance for doubtful accounts for our other businesses is calculated based on specific review of probable future collections based on receivable balances in excess of 30 days.

Unbilled revenues of $597 million and $575 million are included in customer accounts receivable at December 31, 2011 and 2010, respectively

Notes Receivable [Policy Text Block]

Notes Receivable

Notes receivable, or financing receivables, are primarily comprised of capital lease receivables and loans and are included in Notes receivable and Other current assets on the Company’s Consolidated Statements of Financial Position.

Notes receivable are typically considered delinquent when payment is not received for periods ranging from 60 to 120 days. The Company ceases accruing interest (nonaccrual status), considers a note receivable impaired, and establishes an allowance for credit loss when it is probable that all principal and interest amounts due will not be collected in accordance with the contractual terms of the note receivable. Cash payments received on nonaccrual status notes receivable, that do not bring the account contractually current, are first applied to contractually owed past due interest, with any remainder applied to principal. Accrual of interest is generally resumed when the note receivable becomes contractually current.

In determining the allowance for credit losses for notes receivable, we consider the historical payment experience and other factors that are expected to have a specific impact on the counterparty’s ability to pay. In addition, the Company monitors the credit ratings of the counterparties from which we have notes receivable.

Inventories [Policy Text Block]

Inventories

The Company generally values inventory at average cost.

Gas inventory of $52 million and $43 million as of December 31, 2011and 2010, respectively, at MichCon is determined using the last-in, first-out (LIFO) method. At December 31, 2011, the replacement cost of gas remaining in storage exceeded the LIFO cost by $95 million. At December 31, 2010, the replacement cost of gas remaining in storage exceeded the LIFO cost by $147 million.

Property, Retirement and Maintenance, Depreciation, Depletion and Amortization [Policy Text Block]

Property, Retirement and Maintenance, and Depreciation, Depletion and Amortization

Property is stated at cost and includes construction-related labor, materials, overheads and, for utility property, an allowance for funds used during construction (AFUDC). The cost of utility properties retired, including the cost of removal, less salvage value, is charged to accumulated depreciation. Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2.

Utility property at Detroit Edison and MichCon is depreciated over its estimated useful life using straight-line rates approved by the MPSC.

Non-utility property is depreciated over its estimated useful life using straight-line and units-of-production methods.

The Company credits depreciation, depletion and amortization expense when it establishes regulatory assets for plant-related costs such as depreciation or plant-related financing costs. The Company charges depreciation, depletion and amortization expense when it amortizes these regulatory assets. The Company credits interest expense to reflect the accretion income on certain regulatory assets.

Approximately $23 million and $3 million of expenses related to Fermi 2 refueling outages were accrued at December 31, 2011 and December 31, 2010, respectively. Amounts are accrued on a pro-rata basis over an 18-month period that coincides with scheduled refueling outages at Fermi 2. This accrual of outage costs matches the regulatory recovery of these costs in rates set by the MPSC. See Note 11.

The cost of nuclear fuel is capitalized. The amortization of nuclear fuel is included within Fuel, purchased power, and gas in the Consolidated Statement of Operations and is recorded using the units-of-production method.

Unconventional Gas Production [Policy Text Block]

Unconventional Gas Production

The Company follows the successful efforts method of accounting for investments in oil and 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 contains proved reserves. If an exploratory well does not contain 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 properties without economical quantities of proved reserves are expensed as incurred. An impairment loss is recorded if the net capitalized costs of proved gas properties exceed the aggregate related undiscounted future net revenues. 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. Depreciation, depletion and amortization of proved gas properties are determined using the units-of-production method.

Long-Lived Assets [Policy Text Block]

Long-Lived Assets

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

Intangible Assets

Emission allowances and renewable energy credits are charged to expense, using average cost, as the allowances and credits are consumed in the operation of the business. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 3 to 20 years. Intangible assets amortization expense was $5 million in 2011, $4 million in 2010 and $4 million in 2009. Amortization expense of intangible assets is estimated to be $3 million annually for 2012 through 2016.

Excise and Sales Taxes [Policy Text Block]

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 net impact on the Consolidated Statements of Operations.

Deferred Debt Costs [Policy Text Block]

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.

Investments in Debt and Equity Securities [Policy Text Block]

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 equity 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 equity investment being written down to its estimated fair value. See Note 3.

Offsetting Amounts Related to Certain Contracts, Policy [Policy Text Block]

Offsetting Amounts Related to Certain Contracts

The Company offsets 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 agreement, which reduces the Company’s total assets and total liabilities. As of December 31, 2011 and December 31, 2010, the total cash collateral posted, net of cash collateral received, was $71 million and $77 million, respectively. Derivative assets and derivative liabilities are shown net of collateral of $19 million and $74 million, respectively, as of December 31, 2011 and $9 million and $53 million, respectively, as of December 31, 2010. The Company recorded cash collateral paid of $16 million not related to unrealized derivative positions as of December 31, 2011. The Company recorded cash collateral received of $2 million and cash collateral paid of $35 million not related to unrealized derivative positions, as of December 31, 2010. These amounts are included in accounts receivable and accounts payable and are recorded net by counterparty.

Government Grants [Policy Text Block]

Government Grants

Grants are recognized when there is reasonable assurance that the grant will be received and that any conditions associated with the grant will be met. When grants are received related to Property, Plant and Equipment, the Company reduces the basis of the assets on the Consolidated Statements of Financial Position, resulting in lower depreciation expense over the life of the associated asset. Grants received related to expenses are reflected as a reduction of the associated expense in the period in which the expense is incurred.

Other Accounting Policies [Policy Text Block]

d of $2 million and cash collateral paid of $35 million not related to unrealized derivative positions, as of December 31, 2010. These amounts are included in accounts receivable and accounts payable and are recorded net by counterparty.

Government Grants

Grants are recognized when there is reasonable assurance that the grant will be received and that any conditions associated with the grant will be met. When grants are received related to Property, Plant and Equipment, the Company reduces the basis of the assets on the Consolidated Statements of Financial Position, resulting in lower depreciation expense over the life of the associated asset. Grants received related to expenses are reflected as a reduction of the associated expense in the period in which the expense is incurred.

Other Accounting Policies

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

Note	Title
3	Fair Value
4	Financial and Other Derivative Instruments
5	Goodwill
8	Asset Retirement Obligations
11	Regulatory Matters
12	Income Taxes
20	Retirement Benefits and Trusteed Assets
21	Stock-based Compensation

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Retirement Benefits and Trusteed Assets (Tables)

12 Months Ended

Dec. 31, 2011

Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]

Schedule of Net Benefit Costs [Table Text Block]

	2011			2010			2009
	(In millions)
Service cost	$	69		$	64		$	52
Interest cost	202			202			203
Expected return on plan assets	(246		)	(258		)	(255		)
Amortization of:
Net actuarial loss	142			100			52
Prior service cost	3			4			6
Special termination benefits	2			—			—
Net pension cost	$	172		$	112		$	58

Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]

	2011			2010
	(In millions)
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income
Net actuarial loss	$	619		$	166
Amortization of net actuarial loss	(142		)	(100		)
Amortization of prior service cost	(3		)	(4		)
Total recognized Regulatory assets and Other comprehensive income	$	474		$	62
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	646		$	174
Estimated amounts to be amortized from Regulatory assets and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year
Net actuarial loss	$	171		$	133
Prior service cost	—			3

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

	2011			2010
	(In millions)
Accumulated benefit obligation, end of year	$	3,881		$	3,521
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	3,785		$	3,436
Consolidation of VIEs	—			82
Service cost	69			64
Interest cost	202			202
Actuarial loss	355			216
Special termination benefits	2			—
Benefits paid	(218		)	(215		)
Projected benefit obligation, end of year	$	4,195		$	3,785
Change in plan assets
Plan assets at fair value, beginning of year	$	2,913		$	2,549
Consolidation of VIEs	—			64
Actual return on plan assets	(18		)	309
Company contributions	209			206
Benefits paid	(218		)	(215		)
Plan assets at fair value, end of year	$	2,886		$	2,913
Funded status of the plans	$	(1,309	)	$	(872	)
Amount recorded as:
Current liabilities	$	(11	)	$	(6	)
Noncurrent liabilities	(1,298		)	(866		)
	$	(1,309	)	$	(872	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	202		$	195
Prior service (credit)	(3		)	(4		)
	$	199		$	191
Amounts recognized in Regulatory assets (see Note 11)
Net actuarial loss	$	2,201		$	1,730
Prior service cost	7			12
	$	2,208		$	1,742

Assumptions Used to Determine the Projected Benefit Obligation and Net Pension Cost [Table Text Block]

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

	2011		2010		2009
Projected benefit obligation
Discount rate	5.00	%	5.50	%	5.90	%
Rate of compensation increase	4.20	%	4.00	%	4.00	%
Net pension costs
Discount rate	5.50	%	5.90	%	6.90	%
Rate of compensation increase	4.00	%	4.00	%	4.00	%
Expected long-term rate of return on plan assets	8.50	%	8.75	%	8.75	%

Schedule of Expected Benefit Payments [Table Text Block]

	(In millions)
2012	$	240
2013	239
2014	244
2015	253
2016	260
2017-2021	1,439
	$	2,675

Schedule of Allocation of Plan Assets [Table Text Block]

Target allocations for plan assets as of December 31, 2011 are listed below:

U.S. Large Cap Equity Securities	22	%
U.S. Small Cap and Mid Cap Equity Securities	5
Non U.S. Equity Securities	20
Fixed Income Securities	25
Hedge Funds and Similar Investments	20
Private Equity and Other	8
	100	%

Pension Plans Fair Value Hierachy Level [Table Text Block]

Fair Value Measurements at December 31, 2011(a)

	Level 1		Level 2		Level 3		Balance at December 31, 2011
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	33	$	—	$	33
Equity securities
U.S. Large Cap (c)	640		40		—		680
U.S. Small/Mid Cap (d)	159		5		—		164
Non U.S (e)	392		114		—		506
Fixed income securities (f)	88		703		—		791
Hedge Funds and Similar Investments (g)	190		58		296		544
Private Equity and Other (h)	—		—		168		168
Total	$	1,469	$	953	$	464	$	2,886

Fair Value Measurements at December 31, 2010(a)

	Level 1		Level 2		Level 3		Balance at December 31, 2010
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	34	$	—	$	34
Equity securities
U.S. Large Cap (c)	686		38		—		724
U.S. Small/Mid Cap (d)	181		8		—		189
Non U.S (e)	285		222		—		507
Fixed income securities (f)	61		658		—		719
Hedge Funds and Similar Investments (g)	189		73		304		566
Private Equity and Other (h)	—		—		174		174
Total	$	1,402	$	1,033	$	478	$	2,913

Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets [Table Text Block]

Fair Value Measurements Using Significant Unobservable Inputs (Level 3):

	Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1, 2011	$	304		$	174		$	478
Total realized/unrealized gains (losses):
Realized gains (losses)	(4		)	6			2
Unrealized gains (losses)	1			(30		)	(29		)
Purchases, sales and settlements:
Purchases	64			23			87
Sales	(69		)	(5		)	(74		)
Ending Balance at December 31, 2011	$	296		$	168		$	464
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	4		$	(28	)	$	(24	)

	Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1, 2010	$	484		$	160		$	644
Total realized/unrealized gains (losses)	51			23			74
Purchases, sales and settlements	(231		)	(9		)	(240		)
Ending Balance at December 31, 2010	$	304		$	174		$	478
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	29		$	13		$	42

Schedule of Net Postretirement Costs [Table Text Block]

Net postretirement cost includes the following components:

	2011			2010			2009
	(In millions)
Service cost	$	64		$	61		$	59
Interest cost	121			125			133
Expected return on plan assets	(94		)	(74		)	(55		)
Amortization of:
Net loss	55			54			72
Prior service (credit)	(26		)	(4		)	(6		)
Net transition obligation	2			2			2
Net postretirement cost	$	122		$	164		$	205

Schedule of Postretirement Plan Amounts Recognized in Other Comprehensive Income [Table Text Block]

	2011			2010
	(In millions)
Other changes in plan assets and APBO recognized in Regulatory assets and Other comprehensive income
Net actuarial loss	$	195		$	93
Amortization of net actuarial loss	(55		)	(54		)
Prior service credit	(4		)	(79		)
Amortization of prior service credit	26			4
Amortization of transition asset	(2		)	(2		)
Total recognized in Regulatory assets and Other comprehensive income	$	160		$	(38	)
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	282		$	126
Estimated amounts to be amortized from Regulatory assets and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year
Net actuarial loss	$	78		$	59
Prior service credit	$	(27	)	$	(26	)
Net transition obligation	$	2		$	2

Schedule of Other Postretirement Benefit Plans Disclosures [Table Text Block]

The following table reconciles the obligations, assets and funded status of the plans including amounts recorded as accrued postretirement cost in the Consolidated Statements of Financial Position at December 31:

	2011			2010
	(In millions)
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation, beginning of year	$	2,305		$	2,151
Consolidation of VIEs	—			21
Service cost	64			61
Interest cost	121			125
Plan amendments	(4		)	(79		)
Actuarial loss	80			127
Medicare Part D subsidy	6			7
Benefits paid	(102		)	(108		)
Accumulated postretirement benefit obligation, end of year	$	2,470		$	2,305
Change in plan assets
Plan assets at fair value, beginning of year	$	1,029		$	864
Actual return on plan assets	(22		)	108
Company contributions	111			160
Benefits paid	(133		)	(103		)
Plan assets at fair value, end of year	$	985		$	1,029
Funded status, end of year	$	(1,485	)	$	(1,276	)
Amount recorded as:
Current liabilities	$	(1	)	$	(1	)
Noncurrent liabilities	$	(1,484	)	$	(1,275	)
	$	(1,485	)	$	(1,276	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	47		$	46
Prior service credit	(20		)	(28		)
Net transition asset	(1		)	(2		)
	$	26		$	16
Amounts recognized in Regulatory assets (See Note 11)
Net actuarial loss	$	835		$	692
Prior service cost	(60		)	(74		)
Net transition obligation	3			6
	$	778		$	624

Assumptions used to Determine Projected Benefit Obligations and Net OPEB Costs [Table Text Block]

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

	2011		2010		2009
Projected benefit obligation
Discount rate	5.00	%	5.50	%	5.90	%
Net benefit costs
Discount rate	5.50	%	5.90	%	6.90	%
Expected long-term rate of return on plan assets	8.75	%	8.75	%	8.75	%
Health care trend rate pre- and post- 65	7.00	%	7.00	%	7.00	%
Ultimate health care trend rate	5.00	%	5.00	%	5.00	%
Year in which ultimate reached	2019		2016		2016

Schedule of Expected Benefit Payments OPEB [Table Text Block]

	(In millions)
2012	$	109
2013	116
2014	124
2015	132
2016	142
2017 — 2021	839
	$	1,462

Schedule of Allocation of Plan Assets OPEB [Table Text Block]

Target allocations for plan assets as of December 31, 2011 are listed below:

U.S. Large Cap Equity Securities	22	%
Non U.S. Equity Securities	20
Fixed Income Securities	25
Hedge Funds and Similar Investments	20
Private Equity and Other	13
	100	%

Other Postretirement Benefit Plans Hierachy Level [Table Text Block]

Fair Value Measurements at December 31, 2011(a)

	Level 1		Level 2		Level 3		Balance at December 31, 2011
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	13	$	—	$	13
Equity securities:
U.S. Large Cap (c)	175		15		—		190
U.S. Small/Mid Cap (d)	70		6		—		76
Non U.S (e)	176		14		—		190
Fixed income securities (f)	24		236		—		260
Hedge Funds and Similar Investments (g)	80		21		95		196
Private Equity and Other (h)	—		—		60		60
Total	$	525	$	305	$	155	$	985

Fair Value Measurements at December 31, 2010(a)

	Level 1		Level 2		Level 3		Balance at December 31, 2010
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	8	$	—	$	8
Equity securities
U.S. Large Cap (c)	126		62		—		188
U.S. Small/Mid Cap (d)	60		58		—		118
Non U.S (e)	79		122		—		201
Fixed income securities (f)	4		252		—		256
Hedge Funds and Similar Investments (g)	76		48		79		203
Private Equity and Other (h)	—		—		55		55
Total	$	345	$	550	$	134	$	1,029

Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets OPEB [Table Text Block]

Fair Value Measurements Using Significant Unobservable Inputs (Level 3):

	Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1, 2011	$	79		$	55		$	134
Total realized/unrealized gains (losses):
Realized gains (losses)	(1		)	2			1
Unrealized gains (losses)	2			(22		)	(20		)
Purchases, sales and settlements:
Purchases	68			48			116
Sales	(53		)	(23		)	(76		)
Ending Balance at December 31, 2011	$	95		$	60		$	155
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	5		$	(16	)	$	(11	)

	Hedge Funds and Similar Investments			Private Equity and Other		Total
	(In millions)
Beginning Balance at January 1, 2010	$	92		$	46	$	138
Total realized/unrealized gains	10			8		18
Purchases, sales and settlements	(23		)	1		(22		)
Ending Balance at December 31, 2010	$	79		$	55	$	134
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	6		$	7	$	13

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Common Stock

12 Months Ended

Dec. 31, 2011

Common Stock [Abstract]

Schedule of Stock by Class [Table Text Block]

COMMON STOCK

Common Stock

In March 2010, the Company contributed $100 million of DTE Energy common stock to the DTE Energy Company Affiliates Employee Benefit Plans Master Trust. The common stock was contributed over four business days from March 26, 2010 through March 31, 2010 and was valued using the closing market prices of DTE Energy common stock on each of those days in accordance with fair value measurement and accounting requirements.

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.

Dividends

Certain of the Company’s credit facilities contain a provision requiring the Company to maintain a total funded debt to capitalization ratio, as defined in the agreements, of no more than 0.65 to 1, which has the effect of limiting the amount of dividends the Company can pay in order to maintain compliance with this provision. See Note 17 for a definition of this ratio. The effect of this provision as of December 31, 2011 and December 31, 2010 was to restrict the payment of approximately $128 million and $46 million, respectively, of total retained earnings of approximately $3.75 billion and $3.4 billion, respectively. There are no other effective limitations with respect to the Company’s ability to pay dividends.

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Retirement Benefits and Trusteed Assets (Details 9) (Other Postretirement Benefit Plans, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ 195	$ 93
Amortization of net actuarial loss	(55)	(54)
Prior service credit	(4)	(79)
Amortization of prior service cost	26	4
Amortization of transition asset	(2)	(2)
Total recognized Regulatory assets and Other comprehensive income	160	(38)
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive icnome	282	126
Net actuarial loss	78	59
Prior service credit	(27)	(26)
Net transition obligation	$ 2	$ 2

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Capital and Operating Leases

12 Months Ended

Dec. 31, 2011

Capital and Operating Leases [Abstract]

Capital and OPERATING LEASES [Text Block]

CAPITAL AND OPERATING LEASES

Lessee — The Company leases various assets under capital and operating leases, including coal railcars, 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, 2011 were:

	Capital Leases		Operating Leases
	(In millions)
2012	$	9	$	37
2013	7		29
2014	9		24
2015	7		20
2016	3		18
Thereafter	—		67
Total minimum lease payments	$	35	$	195
Less imputed interest	5
Present value of net minimum lease payments	30
Less current portion	7
Non-current portion	$	23

Rental expense for operating leases was $71 million in 2011, $54 million in 2010, and $58 million in 2009.

Lessor  — The Company leases a portion of its pipeline system to the Vector Pipeline through a capital lease contract that expires in 2020, with renewal options extending for five years. The Company owns a 40% interest in the Vector Pipeline. In addition, the Company has an energy services agreement, a portion of which is accounted for as a capital lease. The agreement expires in 2019, with a three or five year renewal option. The components of the net investment in the capital leases at December 31, 2011, were as follows:

	(In millions)
2012	$	12
2013	12
2014	12
2015	12
2016	12
Thereafter	43
Total minimum future lease receipts	103
Residual value of leased pipeline	40
Less unearned income	(56		)
Net investment in capital lease	87
Less current portion	(4		)
	$	83

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Long-Term Debt (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Dec. 31, 2011
Extinguishment of Debt [Line Items]
Extinguishment of Debt, Amount	$ 1,280
Tax-Exempt Revenue Bonds 2 [Member]
Extinguishment of Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.95%
Extinguishment of Debt, Amount	26
Senior Notes 1 [Member]
Extinguishment of Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.05%
Extinguishment of Debt, Amount	600
Tax-Exempt Revenue Bonds 3 [Member]
Extinguishment of Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.55%
Extinguishment of Debt, Amount	118
Tax-Exempt Revenue Bonds 4 [Member]
Extinguishment of Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.65%
Extinguishment of Debt, Amount	67
Tax Exempt Revenue Bonds 5 [Member]
Extinguishment of Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.65%
Extinguishment of Debt, Amount	40
Tax Exempt Revenue Bonds 6 [Member]
Extinguishment of Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.45%
Extinguishment of Debt, Amount	140
Trust preferred-linked securities [Member]
Extinguishment of Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.80%
Extinguishment of Debt, Amount	186
Trust preferred-linked securities 1 [Member]
Extinguishment of Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.50%
Extinguishment of Debt, Amount	$ 103

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Capital and Operating Leases (Tables)

12 Months Ended

Dec. 31, 2011

Capital and Operating Leases [Abstract]

Capital and Operating Leases [Table Text Block]

	Capital Leases		Operating Leases
	(In millions)
2012	$	9	$	37
2013	7		29
2014	9		24
2015	7		20
2016	3		18
Thereafter	—		67
Total minimum lease payments	$	35	$	195
Less imputed interest	5
Present value of net minimum lease payments	30
Less current portion	7
Non-current portion	$	23

Schedule of Capital Lease of Lessor [Table Text Block]

	(In millions)
2012	$	12
2013	12
2014	12
2015	12
2016	12
Thereafter	43
Total minimum future lease receipts	103
Residual value of leased pipeline	40
Less unearned income	(56		)
Net investment in capital lease	87
Less current portion	(4		)
	$	83

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Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	$ 5,300
2012 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	2,276
2013 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	1,221
2014 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	732
2015 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	237
2016 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	109
2017 - 2051 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	740
Total [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	$ 5,315

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Jointly Owned Utility Plant (Tables)

12 Months Ended

Dec. 31, 2011

Jointly Owned Utility Plant [Abstract]

Schedule of Jointly Owned Utility Plants [Table Text Block]

	Belle River			Ludington Hydroelectric Pumped Storage
In-service date	1984-1985			1973
Total plant capacity	1,270		MW	1,872		MW
Ownership interest	*			49		%
Investment (in millions)	$	1,645		$	199
Accumulated depreciation (in millions)	$	943		$	158

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Retirement Benefits and Trusteed Assets (Details 1) (Pension Plans, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ 619	$ 166
Amortization of net actuarial loss	(142)	(100)
Amortization of prior service cost	(3)	(4)
Total recognized Regulatory assets and Other comprehensive income	474	62
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	646	174
Net actuarial loss	171	133
Prior service credit	$ 0	$ 3

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating Activities
Net Income	$ 720	$ 639	$ 535
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	995	1,027	1,020
Deferred income taxes	220	457	205
Asset (gains), losses and reserves and impairments, net	(21)	(5)	(10)
Changes in assets and liabilities, exclusive of changes shown separately (Note 22)	94	(293)	69
Net cash from operating activities	2,008	1,825	1,819
Investing Activities
Plant and equipment expenditures — utility	(1,382)	(1,011)	(960)
Plant and equipment expenditures — non-utility	(102)	(88)	(75)
Proceeds from sale of assets	18	56	83
Restricted cash for debt redemption, principally Securitization	(5)	(32)	2
Proceeds from sale of nuclear decommissioning trust fund assets	80	377	295
Investment in nuclear decommissioning trust funds	(97)	(410)	(315)
Consolidation of VIEs	0	19	0
Investment in Millennium Pipeline Project	(3)	(49)	(15)
Other	(69)	(88)	(79)
Net cash used for investing activities	(1,560)	(1,226)	(1,064)
Financing Activities
Issuance of long-term debt, net	1,179	614	427
Redemption of long-term debt	(1,455)	(663)	(486)
Short-term borrowings	269	(177)	(417)
Issuance of common stock	0	36	35
Repurchase of common stock	(18)	0	0
Dividends on common stock	(389)	(360)	(348)
Other	(31)	(36)	0
Net cash used for financing activities	(445)	(586)	(789)
Net Increase (Decrease) in Cash and Cash Equivalents	3	13	(34)
Cash and Cash Equivalents at Beginning of Period	65	52	86
Cash and Cash Equivalents at End of Period	$ 68	$ 65	$ 52

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Income Taxes (Details 3) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Increases Resulting from Prior Period Tax Positions		$ 53
Uncertain Tax Positions [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits	48	28	81	72
Unrecognized Tax Benefits, Increases Resulting from Prior Period Tax Positions	27	4	15
Unrecognized Tax Benefits, Decreases Resulting from Prior Period Tax Positions	(4)	(4)	(5)
Unrecognized Tax Benefits, Increases Resulting from Current Period Tax Positions	1	0	7
Unrecognized Tax Benefits, Decreases Resulting from Settlements with Taxing Authorities	(3)	(53)	(5)
Unrecognized Tax Benefits, Reductions Resulting from Lapse of Applicable Statute of Limitations	$ (1)	$ 0	$ (3)

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Significant Accounting Policies (Notes)

12 Months Ended

Dec. 31, 2011

Significant Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

SIGNIFICANT ACCOUNTING POLICIES

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 electricity and gas provided but unbilled at the end of each month. Rates for Detroit Edison and MichCon include provisions to adjust billings for fluctuations in fuel and purchased power costs, cost of natural gas and certain other costs. Revenues are adjusted for differences between actual costs and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are recorded on the Consolidated Statement of Financial Position and are recovered or returned to customers through adjustments to the billing factors.

Detroit Edison had a CIM, which was an over/under recovery mechanism that measured non-fuel revenues lost or gained as a result of fluctuations in electric Customer Choice sales. If annual electric Customer Choice sales exceeded the baseline amount from Detroit Edison's most recent rate case, 90 percent of its lost non-fuel revenues associated with sales above that level may be recovered from full service customers. If annual electric Customer Choice sales decreased below the baseline, the Company must refund 90 percent of its increase in non-fuel revenues associated with sales below that level to full service customers. The CIM was terminated effective with the October 20, 2011 MPSC rate order. On January 17, 2012, Detroit Edison filed an application with the MPSC for approval of its CIM reconciliation for 2011.

Detroit Edison and MichCon had RDMs in place in 2011 designed to minimize the impact on revenues of changes in average customer usage of electricity and natural gas. The electric RDM enabled Detroit Edison to recover or refund the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established in the MPSC order. The 2011 pilot RDM established in Detroit Edison's 2009 rate case was terminated by the MPSC in October 2011, but the Company has requested rehearing on this point asserting the termination should have occurred in April 2011. Detroit Edison will have a newly designed RDM that will be effective in April 2012. See Note 11 for further discussion of the newly designed RDM. The June 2010 MPSC order in MichCon's 2009 rate case provided for the implementation of a pilot gas RDM effective July 1, 2010, which enables MichCon to recover or refund the change in revenue resulting from the difference in weather-adjusted average sales per customer compared to the base average sales per customer established in the MPSC order. The gas RDM is subject to review in future MPSC proceedings during the pilot program. The gas RDM addresses changes in customer usage due to general economic conditions and conservation, but does not shield MichCon from the impacts of lost customers or weather variations.

See Note 11 for further discussion of recovery mechanisms authorized by the MPSC.

Non-utility businesses recognize revenues as services are provided and products are delivered. Revenues and energy costs related to trading contracts are presented on a net basis in the Consolidated Statements of Operations. Commodity derivatives used for trading purposes are accounted for using the mark-to-market method with unrealized gains and losses recorded in Operating Revenues.

Accounting for ISO Transactions

Detroit Edison participates in the energy market through MISO. MISO requires that we submit hourly day-ahead, real time and FTR bids and offers for energy at locations across the MISO region. Detroit Edison accounts for MISO transactions on a net hourly basis in each of the day-ahead, real-time and FTR markets and net transactions across all MISO energy market locations. In any single hour Detroit Edison records net purchases in Fuel, purchased power and gas and net sales in Operating revenues on the Consolidated Statements of Operations. Detroit Edison records net sale billing adjustments when invoices are received.

Energy Trading participates in the energy markets through various independent system operators and regional transmission organizations (ISOs and RTOs). These markets require that we submit hourly day-ahead, real time bids and offers for energy at locations across each region. We submit bids in the annual and monthly auction revenue rights and FTR auctions to the regional transmission organizations. Energy Trading accounts for these transactions on a net hourly basis for the day-ahead, real-time and FTR markets. These transactions are related to our trading contracts which are presented on a net basis in Operating revenues in the Consolidated Statements of Income.

Detroit Edison and Energy Trading record expense accruals for future net purchases adjustments based on historical experience, and reconcile accruals to actual expenses when invoices are received from MISO, the ISOs and RTOs.

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 accumulated other comprehensive loss for the year ended December 31, 2011 include unrealized gains and losses from derivatives accounted for as cash flow hedges, unrealized gains and losses on available for sale securities, the Company’s interest in comprehensive income of equity investees, changes in benefit obligations, consisting of deferred actuarial losses, prior service costs and transition amounts related to pension and other postretirement benefit plans, and foreign currency translation adjustments.

	Net Unrealized Gain/(Loss) on Derivatives			Net Unrealized Gain/(Loss) on Investments			Benefit Obligations			Foreign Currency Translation		Accumulated Other Comprehensive Loss
							(In millions)
Beginning balances	$	(4	)	$	(30	)	$	(116	)	$	1	$	(149	)
Current period change, net of tax	—			—			(9		)	—		(9		)
Ending balance	$	(4	)	$	(30	)	$	(125	)	$	1	$	(158	)

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, primarily Securitization bonds, and partnership operating agreements. Restricted cash designated for interest and principal payments within one year is classified as a current asset.

Receivables

Accounts receivable are primarily composed of trade receivables and unbilled revenue. Our accounts receivable are stated at net realizable value.

The allowance for doubtful accounts for Detroit Edison and MichCon is generally calculated using the aging approach that utilizes rates developed in reserve studies. We establish an allowance for uncollectible accounts based on historical losses and management’s assessment of existing economic conditions, customer trends, and other factors. Customer accounts are generally considered delinquent if the amount billed is not received by the due date, which is typically in 21 days, however, factors such as assistance programs may delay aggressive action. We assess late payment fees on trade receivables based on past-due terms with customers. Customer accounts are written off when collection efforts have been exhausted, generally one year after service has been terminated.

The customer allowance for doubtful accounts for our other businesses is calculated based on specific review of probable future collections based on receivable balances in excess of 30 days.

Unbilled revenues of $597 million and $575 million are included in customer accounts receivable at December 31, 2011 and 2010, respectively.

Notes Receivable

Notes receivable, or financing receivables, are primarily comprised of capital lease receivables and loans and are included in Notes receivable and Other current assets on the Company’s Consolidated Statements of Financial Position.

Notes receivable are typically considered delinquent when payment is not received for periods ranging from 60 to 120 days. The Company ceases accruing interest (nonaccrual status), considers a note receivable impaired, and establishes an allowance for credit loss when it is probable that all principal and interest amounts due will not be collected in accordance with the contractual terms of the note receivable. Cash payments received on nonaccrual status notes receivable, that do not bring the account contractually current, are first applied to contractually owed past due interest, with any remainder applied to principal. Accrual of interest is generally resumed when the note receivable becomes contractually current.

In determining the allowance for credit losses for notes receivable, we consider the historical payment experience and other factors that are expected to have a specific impact on the counterparty’s ability to pay. In addition, the Company monitors the credit ratings of the counterparties from which we have notes receivable.

Inventories

The Company generally values inventory at average cost.

Gas inventory of $52 million and $43 million as of December 31, 2011and 2010, respectively, at MichCon is determined using the last-in, first-out (LIFO) method. At December 31, 2011, the replacement cost of gas remaining in storage exceeded the LIFO cost by $95 million. At December 31, 2010, the replacement cost of gas remaining in storage exceeded the LIFO cost by $147 million.

Property, Retirement and Maintenance, and Depreciation, Depletion and Amortization

Property is stated at cost and includes construction-related labor, materials, overheads and, for utility property, an allowance for funds used during construction (AFUDC). The cost of utility properties retired, including the cost of removal, less salvage value, is charged to accumulated depreciation. Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2.

Utility property at Detroit Edison and MichCon is depreciated over its estimated useful life using straight-line rates approved by the MPSC.

Non-utility property is depreciated over its estimated useful life using straight-line and units-of-production methods.

The Company credits depreciation, depletion and amortization expense when it establishes regulatory assets for plant-related costs such as depreciation or plant-related financing costs. The Company charges depreciation, depletion and amortization expense when it amortizes these regulatory assets. The Company credits interest expense to reflect the accretion income on certain regulatory assets.

Approximately $23 million and $3 million of expenses related to Fermi 2 refueling outages were accrued at December 31, 2011 and December 31, 2010, respectively. Amounts are accrued on a pro-rata basis over an 18-month period that coincides with scheduled refueling outages at Fermi 2. This accrual of outage costs matches the regulatory recovery of these costs in rates set by the MPSC. See Note 11.

The cost of nuclear fuel is capitalized. The amortization of nuclear fuel is included within Fuel, purchased power, and gas in the Consolidated Statement of Operations and is recorded using the units-of-production method.

Unconventional Gas Production

The Company follows the successful efforts method of accounting for investments in oil and 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 contains proved reserves. If an exploratory well does not contain 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 properties without economical quantities of proved reserves are expensed as incurred. An impairment loss is recorded if the net capitalized costs of proved gas properties exceed the aggregate related undiscounted future net revenues. 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. Depreciation, depletion and amortization of proved gas properties are determined using the units-of-production method.

Long-Lived Assets

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

Intangible Assets

The Company has certain intangible assets relating to emission allowances, renewable energy credits and non-utility contracts. Summary of intangible assets as of December 31:

(In millions)	2011		2010
Emission allowances	$	9	$	9
Renewable energy credits	27		17
Contract intangible assets	65		63
	101		89
Less accumulated amortization	28		22
Intangible assets, net	$	73	$	67

Emission allowances and renewable energy credits are charged to expense, using average cost, as the allowances and credits are consumed in the operation of the business. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 3 to 20 years. Intangible assets amortization expense was $5 million in 2011, $4 million in 2010 and $4 million in 2009. Amortization expense of intangible assets is estimated to be $3 million annually for 2012 through 2016.

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 net 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.

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 equity 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 equity investment being written down to its estimated fair value. See Note 3.

Offsetting Amounts Related to Certain Contracts

The Company offsets 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 agreement, which reduces the Company’s total assets and total liabilities. As of December 31, 2011 and December 31, 2010, the total cash collateral posted, net of cash collateral received, was $71 million and $77 million, respectively. Derivative assets and derivative liabilities are shown net of collateral of $19 million and $74 million, respectively, as of December 31, 2011 and $9 million and $53 million, respectively, as of December 31, 2010. The Company recorded cash collateral paid of $16 million not related to unrealized derivative positions as of December 31, 2011. The Company recorded cash collateral received of $2 million and cash collateral paid of $35 million not related to unrealized derivative positions, as of December 31, 2010. These amounts are included in accounts receivable and accounts payable and are recorded net by counterparty.

Government Grants

Grants are recognized when there is reasonable assurance that the grant will be received and that any conditions associated with the grant will be met. When grants are received related to Property, Plant and Equipment, the Company reduces the basis of the assets on the Consolidated Statements of Financial Position, resulting in lower depreciation expense over the life of the associated asset. Grants received related to expenses are reflected as a reduction of the associated expense in the period in which the expense is incurred.

Other Accounting Policies

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

Note	Title
3	Fair Value
4	Financial and Other Derivative Instruments
5	Goodwill
8	Asset Retirement Obligations
11	Regulatory Matters
12	Income Taxes
20	Retirement Benefits and Trusteed Assets
21	Stock-based Compensation

XML

Organization and Basis of Presentation (Details 1) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Variable Interest Entity [Line Items]
Notes receivable	$ 123	$ 123
Trust preferred-linked securities	0	289
Unconsolidated Variable Interest Entity [Member]
Variable Interest Entity [Line Items]
Other investments	117	98
Notes receivable	7	6
Trust preferred-linked securities	$ 0	$ 289

XML

Other Impairments and Restructuring (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 years	Dec. 31, 2010	Dec. 31, 2009	Jun. 30, 2010
Restructuring Cost and Reserve [Line Items]
Asset Impairment Charges	$ 1	$ 10	$ 6
Amortization Period of CTA	10
Pre Tax Amount of Cost To Achieve Previously Expensed Deferred and Recognized in Income				32
After Tax Amount of Cost To Achieve Previously Expensed deferred and Recognized in Income				20
Non Pension Component of Cost To Achieve Included in Regulatory Assets				21
Pension Componenet of Costs to Achieve Included in Regulatory Liabilities				11
Electric Utility [Member]
Restructuring Cost and Reserve [Line Items]
Amortization of Deferred Cost to Achieve	18	18	18
Gas Utility [Member]
Restructuring Cost and Reserve [Line Items]
Amortization of Deferred Cost to Achieve	$ 3	$ 2

XML

Retirement Benefits and Trusteed Assets (Details) (Pension Plans, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 69	$ 64	$ 52
Interest cost	202	202	203
Expected return on plan assets	(246)	(258)	(255)
Amortization of: [Abstract]
Net actuarial loss	142	100	52
Prior service cost	3	4	6
Special termination benefits	2	0	0
Net pension cost	$ 172	$ 112	$ 58

XML

Fair Value (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2011 years	Dec. 31, 2010 years	Dec. 31, 2009
Fair Value, Option, Quantitative Disclosures [Line Items]
Other investments	$ 111,000,000	$ 111,000,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3	(24,000,000)	35,000,000
Transfers into Level 3	4,000,000	9,000,000
Fair Value, Level 1 to level 2 Transfers, Amount	0	0
Average Maturity of Debt Securities	7	6
Unrealized losses recognized as regulatory assets	67,000,000	26,000,000
Other than Temporary Impairment Losses, Investments, Portion Recognized in Earnings, Net	0	0	0
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, before Tax	0	0
Trading Securities, Change in Unrealized Holding Gain (Loss)	3,000,000	7,000,000	8,000,000
Publicly Traded Equity Securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Nuclear Decommissioning Trust Fund Investments	57.00%	61.00%
Fixed Income Securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Nuclear Decommissioning Trust Fund Investments	41.00%	38.00%
Cash Equivalents [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Nuclear Decommissioning Trust Fund Investments	2.00%	1.00%
Fair Value, Measurements, Recurring [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3	$ 25,000,000

XML

Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

Environmental

Electric Utility

Air - Detroit Edison is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze, mercury, and other air pollution. These rules have led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, mercury and other emissions. To comply with these requirements, Detroit Edison has spent approximately $1.7 billion through 2011. The Company estimates Detroit Edison will make capital expenditures of approximately $255 million in 2012 and up to approximately $1.9 billion of additional capital expenditures through 2021 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants. The Cross State Air Pollution Rule (CSAPR), finalized in July 2011, requires further reductions of sulfur dioxide and nitrogen oxides emissions beginning in 2012. On December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit granted the motions to stay the rule, leaving Detroit Edison temporarily subject to the previously existing Clean Air Interstate Rule (CAIR). The Electric Generating Unit Maximum Achievable Control Technology (EGU MACT) Rule was finalized on December 16, 2011. The EGU MACT requires reductions of mercury and other hazardous air pollutants beginning in 2015. Because these rules were recently finalized and technologies to comply are still being tested, it is not possible to quantify the impact of these rulemakings.

In July 2009, DTE Energy received a Notice of Violation/Finding of Violation (NOV/FOV) from the EPA alleging, among other things, that five Detroit Edison power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and operating permit requirements under the Clean Air Act. An additional NOV/FOV was received in June 2010 related to a recent project and outage at Unit 2 of the Monroe Power Plant.

On August 5, 2010, the United States Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and Detroit Edison, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require Detroit Edison to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require Detroit Edison to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from Detroit Edison's fleet of coal-fired power plants until the new control equipment is operating.

On August 23, 2011, the U.S. District judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy.On October 20, 2011, the EPA caused to be filed a Notice of Appeal. A decision by the Court of Appeals is not expected until late 2012. DTE Energy and Detroit Edison believe that the plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of discussions with the EPA regarding the NOV/FOV and the result of the appeals process, the Company could also be required to install additional pollution control equipment at some or all of the power plants in question, implement early retirement of facilities where control equipment is not economical, engage in supplemental environmental programs, and/or pay fines. The Company cannot predict the financial impact or outcome of this matter, or the timing of its resolution.

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 completed studies and expected future studies, 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 in additional capital expenditures over the four to six years subsequent to 2008 to comply with these requirements. However, a January 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation that has resulted 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. In 2008, the Supreme Court agreed to review the remanded cost-benefit analysis provision of the rule and in April 2009 upheld the EPA's use of this provision in determining best technology available for reducing environmental impacts. The EPA published a proposed rule in 2011 that extended the time line to 2020 with an estimated expected increase in costs to $80 million. A final rule is expected in mid-2012. The EPA has also issued an information collection request to begin a review of steam electric effluent guidelines. It is not possible at this time to quantify the impacts of these developing requirements.

Contaminated and Other 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, have been designated as manufactured gas plant (MGP) sites. Detroit Edison conducted remedial investigations at contaminated sites, including three former MGP sites. The 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, including the area surrounding an ash landfill, electrical distribution substations, and 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. At December 31, 2011 and December 31, 2010, the Company had $8 million and $9 million, respectively, accrued for remediation. 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.

Detroit Edison owns and operates a permitted engineered ash storage facility at the Monroe Power Plant to dispose of fly ash from the coal fired power plant. Detroit Edison performed an engineering analysis in 2009 and identified the need for embankment side slope repairs and reconstruction.

The EPA has published proposed rules to regulate coal ash under the authority of the Resources Conservation and Recovery Act (RCRA). The proposed rule published in June 2010 contains two primary regulatory options to regulate coal ash residue. The EPA is currently considering either designating coal ash as a “Hazardous Waste” as defined by RCRA or regulating coal ash as non-hazardous waste under RCRA. Agencies and legislatures have urged the EPA to regulate coal ash as a non-hazardous waste. If the EPA designates coal ash as a hazardous waste, the agency could apply some, or all, of the disposal and reuse standards that have been applied to other existing hazardous wastes to disposal and reuse of coal ash. Some of the regulatory actions currently being contemplated could have a significant impact on our operations and financial position and the rates we charge our customers. It is not possible to quantify the impact of those expected rulemakings at this time.

Gas Utility

Contaminated Sites — 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, 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.

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. As of December 31, 2011 and December 31, 2010, the Company had $36 million, accrued for remediation.

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. The Company anticipates the cost amortization methodology approved by the MPSC for MichCon, which allows MichCon to amortize the MGP costs over a ten-year period beginning with the year subsequent to the year the MGP costs were incurred, and the cost deferral and rate recovery mechanism for Citizens Fuel Gas approved by the City of Adrian, will prevent environmental costs from having a material adverse impact on the Company’s 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 Michigan coke battery facility received and responded to information requests from the EPA that resulted in the issuance of a NOV in June of 2007 alleging 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. Furthermore, the Michigan coke battery facility is the subject of an investigation by the MDEQ concerning visible emissions readings that resulted from the Company self reporting to MDEQ questionable activities by an employee of a contractor hired by the Company to perform the visible emissions readings. At this time, the Company cannot predict the impact of this investigation.

In April 2006, the prior owners of the coke battery facility in Pennsylvania that the Company purchased in 2008 received a Notice of Violation/Finding of Violation from the EPA alleging violations of the lowest achievable emission rate requirements associated with visible emissions from the combustion stack, door leaks and charging activities at the coke battery facility. The EPA has also alleged certain violations of the Clean Water Act, but has not issued a notice of violation in connection with these alleged violations. The Company is in the process of negotiating a Consent Order with the EPA to settle these historic air and water issues. The Company expects to enter into the Consent Order during the first quarter of 2012.

The Company received two Notices of Violation from the Pennsylvania Department of Environmental Protection in 2010 alleging violations of the permit for the Pennsylvania coke battery facility in connection with coal pile storm water runoff. The Company has implemented best management practices to address this issue and is currently seeking a permit from the Pennsylvania Department of Environmental Protection to upgrade its wastewater treatment technology to a biological treatment facility. The Company expects to spend less than $1 million on the existing waste water treatment system to comply with existing water discharge requirements and to upgrade its coal pile storm water runoff management program. The Company may spend an additional $13 million over the next few years to meet future regulatory requirements and gain other operational improvements savings.

The Company believes that its non-utility affiliates are substantially in compliance with all environmental requirements, other than as noted above.

Other

In March 2011, the EPA finalized a new set of regulations regarding the identification of non-hazardous secondary materials that are considered solid waste, industrial boiler and process heater maximum achievable control technologies (IBMACT) for major and area sources, and commercial/industrial solid waste incinerator new source performance standard and emission guidelines (CISWI). The effective dates of the major source IBMACT and CISWI regulations were stayed anda re-proposal was issued by the EPA in December 2011. The re-proposed rules may impact our existing operations and may require us, in certain instances, to install new air pollution control devices. The re-proposed regulations will provide a minimum period of three years for compliance with the applicable standards. Based on the final approved regulations, anticipated in the first half of 2012, the Company will assess the financial impact, if any, on current operations for compliance with the applicable new standards.

In February 2008, DTE Energy was named as one of approximately 24 defendant oil, power and coal companies in a lawsuit filed in a United States District Court. DTE Energy was served with process in March 2008. The plaintiffs, the Native Village of Kivalina and City of Kivalina, which are home to approximately 400 people in Alaska, claim that the defendants’ business activities have contributed to global warming and, as a result, higher temperatures are damaging the local economy and leaving the island more vulnerable to storm activity in the fall and winter. As a result, the plaintiffs are seeking damages of up to $400 million for relocation costs associated with moving the village to a safer location, as well as unspecified attorney’s fees and expenses. On October 15, 2009, the U.S. District Court granted defendants’ motions dismissing all of plaintiffs’ federal claims in the case on two independent grounds: (1) the court lacks subject matter jurisdiction to hear the claims because of the political question doctrine; and (2) plaintiffs lack standing to bring their claims. The court also dismissed plaintiffs’ state law claims because the court lacked supplemental jurisdiction over them after it dismissed the federal claims; the dismissal of the state law claims was without prejudice. The plaintiffs have appealed to the U.S. Court of Appeals for the Ninth Circuit.

Nuclear Operations

Property Insurance

Detroit Edison maintains 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 policies.

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.

In 2007, the Terrorism Risk Insurance Extension Act of 2005 (TRIA) was extended through 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 $29 million per event if the loss associated with any one event at any nuclear plant in the United States should exceed the accumulated funds available to NEIL.

Public Liability Insurance

As of January 1, 2012, as required by federal law, Detroit Edison maintains $375 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 $117.5 million could be levied against each licensed nuclear facility, but not more than $17.5 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.

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. The DOE's Yucca Mountain Nuclear Waste Repository program for the acceptance and disposal of spent nuclear fuel was terminated in 2011. 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 spent nuclear fuel storage strategy utilizing a fuel pool. The Company continues to develop its on-site dry cask storage facility and has postponed the initial offload from the spent fuel pool until 2013. The dry cask storage facility is expected to provide sufficient spent fuel storage capability for the life of the plant as defined by the original operating license. Issues relating to long-term waste disposal policy and to the disposition of funds contributed by Detroit Edison ratepayers to the federal waste fund await future governmental action.

Synthetic Fuel Guarantees

The Company discontinued the operations of its synthetic fuel production facilities throughout the United States as

of December 31, 2007. The Company 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, 2011 is approximately $1.2 billion. Payment under these guarantees is considered remote.

Reduced Emissions Fuel Guarantees

The Company has provided certain guarantees and indemnities in conjunction with the sales of interests in its reduced emissions fuel facilities. The guarantees cover potential commercial, environmental, 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, 2011 is approximately $15 million. Payment under these guarantees is considered remote.

Other 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. The Company’s guarantees are not individually material with maximum potential payments totaling $10 million at December 31, 2011.

The Company is periodically required to obtain performance surety bonds in support of obligations to various governmental entities and other companies in connection with its operations. As of December 31, 2011, the Company had approximately $23 million of performance bonds outstanding. In the event that such bonds are called for nonperformance, the Company would be obligated to reimburse the issuer of the performance bond. The Company is released from the performance bonds as the contractual performance is completed and does not believe that a material amount of any currently outstanding performance bonds will be called.

Labor Contracts

There are several bargaining units for the Company’s approximately 5,000 represented employees. The majority of represented employees are under contracts that expire in August 2012 and June and October 2013.

Purchase Commitments

As of December 31, 2011, 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 $5.3 billion from 2012 through 2051 as detailed in the following table:

	(In millions)
2012	$	2,276
2013	1,221
2014	732
2015	237
2016	109
2017 — 2051	740
	$	5,315

The Company also estimates that 2012 capital expenditures will be approximately $1.9 billion. The Company has made certain commitments in connection with expected capital expenditures.

Bankruptcies

The Company purchases and sells electricity, gas, coal, coke and other energy products from and to governmental entities and numerous companies operating in the steel, automotive, energy, retail, financial and other industries. Certain of its 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 records provisions for amounts considered at risk of probable loss. The Company believes its accrued amounts are adequate for probable loss. The final resolution of these matters may have a material effect on its consolidated financial statements.

Other Contingencies

The Company is involved in certain other 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 that 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 Notes 4 and 11 for a discussion of contingencies related to derivatives and regulatory matters.

XML

Retirement Benefits and Trusteed Assets (Details 11) (Other Postretirement Benefit Plans, Defined Benefit [Member])	12 Months Ended
	Dec. 31, 2011 percent	Dec. 31, 2010 percent	Dec. 31, 2009 percent
Other Postretirement Benefit Plans, Defined Benefit [Member]
Assumptions Used to Determine Projected Benefit Obligation and Benefit Costs [Line Items]
Discount rate	5.00%	5.50%	5.90%
Discount Rate	5.50%	5.90%	6.90%
Expected long-term rate of return on plan assets	8.75%	8.75%	8.80%
Health care trend rate pre and post 65	7.00%	7.00%	7.00%
Ultimate health care trend rate	5.00%	5.00%	5.00%

XML

Stock-Based Compensation (Details 7)	12 Months Ended
	Dec. 31, 2011
Performance Share Awards [Line Items]
Performance Shares - Balance at January 1, 2011	1,527,253
Performance Shares - Grants	621,114
Performance Shares - Forfeitures	(71,946)
Performance Shares - Payouts	(467,688)
Performance Shares - Balance at December 31, 2011	1,608,733

XML

Stock-Based Compensation (Details 3)	12 Months Ended
	Dec. 31, 2010 years percent	Dec. 31, 2009 percent years
Share Based Compensation Summary of Fair Value of Options Assumptions [Line Items]
Risk-free interest rate	2.91%	2.04%
Dividend yield	5.08%	4.98%
Expected volatility	22.96%	27.88%
Expected Life	6	6

XML

Goodwill (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Goodwill [Line Items]
Balance as of January 1	$ 2,020	$ 2,024
Goodwill attributable to sale of subsidiary in Power and Industrial Projects segment	0	(4)
Balance as of December 31	$ 2,020	$ 2,020

XML

Financial and Other Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2011

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair value of derivative instruments

The following tables present the fair value of derivative instruments as of December 31, 2011:

	Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	3	$	(5	)
Commodity Contracts:
Natural Gas	2,024		(2,080		)
Electricity	747		(705		)
Other	31		(20		)
Total derivatives not designated as hedging instruments:	$	2,805	$	(2,810	)
Total derivatives:
Current	$	2,272	$	(2,282	)
Noncurrent	533		(529		)
Total derivatives	$	2,805	$	(2,811	)

	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	2,272		$	533		$	(2,282	)	$	(529	)
Counterparty netting	(2,050		)	(440		)	2,050			440
Collateral adjustment	—			(19		)	74			—
Total derivatives as reported	$	222		$	74		$	(158	)	$	(89	)

The following tables present the fair value of derivative instruments as of December 31, 2010:

	Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	20	$	(30	)
Commodity Contracts:
Natural Gas	1,986		(2,118		)
Electricity	766		(716		)
Other	76		(71		)
Total derivatives not designated as hedging instruments:	$	2,848	$	(2,935	)
Total derivatives:
Current	$	2,011	$	(2,041	)
Noncurrent	837		(895		)
Total derivatives	$	2,848	$	(2,936	)

	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	2,011		$	837		$	(2,041	)	$	(895	)
Counterparty netting	(1,871		)	(760		)	1,871			760
Collateral adjustment	(9		)	—			28			25
Total derivatives as reported	$	131		$	77		$	(142	)	$	(110	)

Gain (Loss) Recognized in Income on Derivative

The effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for years ended December 31, 2011 and December 31, 2010 is as follows:

	Location of Gain (Loss) Recognized in Income on Derivatives	Gain (Loss) Recognized in Income on Derivatives for Years Ended December 31
Derivatives not Designated as Hedging Instruments		2011			2010
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	(2	)	$	(14	)
Commodity Contracts:
Natural Gas	Operating Revenue	58			61
Natural Gas	Fuel, purchased power and gas	(21		)	(8		)
Electricity	Operating Revenue	115			80
Other	Operating Revenue	9			9
Other	Operation and maintenance	—			(5		)
Total		$	159		$	123

Volume of Commodity Contracts [Table Text Block]

Commodity	Number of Units
Natural Gas (MMBtu)	770,624,682
Electricity (MWh)	48,286,149
Foreign Currency Exchange ($ CAD)	34,904,696

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Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Income Tax Disclosure [Text Block]

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:

	2011			2010			2009
	(In millions)
Income before income taxes	$	987		$	950		$	782
Income tax expense at 35% statutory rate	$	345		$	333		$	274
Production tax credits	(6		)	(33		)	(12		)
Investment tax credits	(6		)	(6		)	(7		)
Depreciation	(4		)	(4		)	(4		)
Employee Stock Ownership Plan dividends	(4		)	(5		)	(5		)
Medicare part D subsidy	—			—			(6		)
Domestic production activities deduction	(7		)	(7		)	(5		)
Goodwill attributed to the sale of Gas Utility subsidiaries	—			—			4
Settlement of Federal tax audit	—			(12		)	(11		)
State and local income taxes, net of federal benefit	37			44			25
Enactment of Michigan Corporate Income Tax, net of federal expense	(87		)	—			—
Other, net	(1		)	1			(6		)
Income tax expense	$	267		$	311		$	247
Effective income tax rate	27.1		%	32.7		%	31.6		%

Components of income tax expense were as follows:

	2011			2010			2009
	(In millions)
Current income tax expense (benefit)
Federal	$	25		$	(172	)	$	25
State and other income tax	22			26			17
Total current income taxes	47			(146		)	42
Deferred income tax expense (benefit)
Federal	318			415			182
State and other income tax	(98		)	42			23
Total deferred income taxes	220			457			205
Total	$	267		$	311		$	247

Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in the financial statements. Deferred tax assets and liabilities are classified as current or noncurrent according to the classification of the related assets or liabilities. Deferred tax assets and liabilities not related to assets or liabilities are classified according to the expected reversal date of the temporary differences. Consistent with rate making treatment, deferred taxes are offset in the table below for temporary differences which have related regulatory assets and liabilities.

Deferred tax assets (liabilities) were comprised of the following at December 31:

	2011			2010
	(In millions)
Property, plant and equipment	$	(3,131	)	$	(2,558	)
Securitized regulatory assets	(360		)	(396		)
Alternative minimum tax credit carry-forwards	294			337
Merger basis differences	50			49
Pension and benefits	(39		)	(36		)
Other comprehensive income	99			83
Derivative assets and liabilities	64			29
State net operating loss and credit carry-forwards	30			33
Other	(45		)	(2		)
	(3,038		)	(2,461		)
Less valuation allowance	(27		)	(32		)
	$	(3,065	)	$	(2,493	)
Current deferred income tax assets	$	51		$	139
Long-term deferred income tax liabilities	(3,116		)	(2,632		)
	$	(3,065	)	$	(2,493	)
Deferred income tax assets	$	1,048		$	1,418
Deferred income tax liabilities	(4,113		)	(3,911		)
	$	(3,065	)	$	(2,493	)

Production tax credits earned in prior years but not utilized totaled $294 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 had 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.

The above table excludes deferred tax liabilities associated with unamortized investment tax credits that are shown separately on the Consolidated Statements of Financial Position. Investment tax credits are deferred and amortized to income over the average life of the related property.

The Company has state deferred tax assets related to net operating loss and credit carry-forwards of $30 million and $33 million at December 31, 2011 and 2010, respectively. The state net operating loss and credit carry-forwards expire from 2012 through 2031. The Company has recorded valuation allowances at December 31, 2011 and 2010 of approximately $27 million and $32 million, respectively, with respect to these deferred tax assets. 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.

Uncertain Tax Positions

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	2011			2010			2009
	(In millions)
Balance at January 1	$	28		$	81		$	72
Additions for tax positions of prior years	27			4			15
Reductions for tax positions of prior years	(4		)	(4		)	(5		)
Additions for tax positions related to the current year	1			—			7
Settlements	(3		)	(53		)	(5		)
Lapse of statute of limitations	(1		)	—			(3		)
Balance at December 31	$	48		$	28		$	81

The Company had $4 million and $5 million of unrecognized tax benefits at December 31, 2011 and at December 31, 2010, respectively, that, if recognized, would favorably impact its effective tax rate. During the next twelve months, it is reasonably possible that the Company will settle certain federal and state tax examinations and audits. As a result, the Company believes that it is possible that there will be a decrease in unrecognized tax benefits of up to $31 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 $2 million and $3 million at December 31, 2011 and December 31, 2010, respectively. The Company had no accrued penalties pertaining to income taxes. The Company recognized interest expense related to income taxes of $(2) million, $1 million and $(2) million in 2011, 2010 and 2009, respectively.

In 2010, the Company settled a federal tax audit for the 2007 and 2008 tax years, which resulted in the recognition of $53 million of unrecognized tax benefits. The Company's federal income tax returns for 2009 and subsequent years remain subject to examination by the IRS. The Company's Michigan Business Tax returns for the year 2008 and subsequent years remain subject to examination by the State of Michigan. The Company also files tax returns in numerous state and local jurisdictions with varying statutes of limitation.

Michigan Corporate Income Tax (MCIT)

On May 25, 2011, the Michigan Business Tax (MBT) was repealed and the MCIT was enacted and became effective January 1, 2012. The MCIT subjects corporations with business activity in Michigan to a 6 percent tax rate on an apportioned income tax base and eliminates the modified gross receipts tax and nearly all credits available under the MBT. The MCIT also eliminated the future deductions allowed under MBT that enabled companies to establish a one-time deferred tax asset upon enactment of the MBT to offset deferred tax liabilities that resulted from enactment of the MBT.

As a result of the enactment of the MCIT, the net state deferred tax liability was remeasured to reflect the impact of the MCIT tax rate on cumulative temporary differences expected to reverse after the effective date. The net impact of this remeasurement was a decrease in deferred income tax liabilities of $36 million attributable to our regulated utilities that was offset against the regulatory asset established upon the enactment of the MBT. Due to the elimination of the future tax deductions allowed under the MBT, the one-time MBT deferred tax asset that was established upon the enactment of the MBT has been remeasured to zero. The net impact of this remeasurement is a reduction of the net deferred tax assets of $308 million, with $395 million of this decrease in deferred tax assets attributable to our regulated utilities, partially offset by an $87 million decrease in deferred tax liabilities attributable to our non-utilities. The $395 million decrease in deferred tax assets at our regulated utilities was offset against the regulatory liabilities established upon enactment of the MBT. The $87 million is primarily due to a lower apportionment factor from inclusion of non-utility entities in DTE Energy's unitary Michigan tax return and was recognized as a reduction to income tax expense in 2011.

Consistent with the original establishment of these deferred tax liabilities (assets), no recognition of these non-cash transactions have been reflected in the Consolidated Statement of Cash Flows.

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Capital and Operating Leases (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Capital and Operaing Lease [Line Items]
Capital Lease Payments in 2012	$ 9
Operating Leases Payments in 2012	37
Capital Lease Payments in 2013	7
Operating Lease Payments in 2013	29
Capital Lease Payments in 2014	9
Operating Lease Payments in 2014	24
Capital Lease Payments in 2015	7
Operating Lease Payments in 2015	20
Capital Lease Payments in 2016	3
Operating Lease Payments in 2016	18
Capital Lease Payments Thereafter	0
Operating Lease Payments Thereafter	67
Capital Lease - Total minimum payments	35
Operating Lease - Total minimum payments	195
Less imputed interest	5
Present value of net minimum lease payments	30
Less current portion	7
Non-current portion	$ 23	$ 43