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, 2012
¨	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
2012 Series C 5.25% Junior Subordinated Debentures due 2062	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. þ

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, 2012, the aggregate market value of the Registrant’s voting and non-voting common equity held by non-affiliates was approximately $10.2 billion (based on the New York Stock Exchange closing price on such date). There were 172,545,941shares of common stock outstanding at January 31, 2013.

Certain information in DTE Energy Company’s definitive Proxy Statement for its 2013 Annual Meeting of Common Shareholders to be held May 2, 2013, 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, 2012

TABLE OF CONTENTS

		Page
Definitions		1
Forward-Looking Statements		3
PART I
Items 1. & 2.	Business and Properties	4
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	21
Item 3.	Legal Proceedings	21
Item 4.	Mine Safety Disclosures	21
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	22
Item 6.	Selected Financial Data	25
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 8.	Financial Statements and Supplementary Data	48
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	111
Item 9A.	Controls and Procedures	111
Item 9B.	Other Information	111
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	111
Item 11.	Executive Compensation	111
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	111
Item 13.	Certain Relationships and Related Transactions, and Director Independence	111
Item 14.	Principal Accountant Fees and Services	111
PART IV
Item 15.	Exhibits and Financial Statement Schedules	111
Signatures		120
EX-4.279
EX-10.81
EX-12.52
EX-21.8
EX-23.26
EX-31.79
EX-31.80
EX-32.79
EX-32.80
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 DTE Electric 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
Customer Choice	Michigan legislation giving customers the option to choose alternative suppliers for electricity and gas.
DTE Electric	DTE Electric Company (a direct wholly owned subsidiary of DTE Energy Company) and subsidiary companies. Formerly known as The Detroit Edison Company.
DTE Energy	DTE Energy Company, directly or indirectly the parent of DTE Electric, DTE Gas and numerous non-utility subsidiaries
DTE Gas	DTE Gas Company (an indirect wholly owned subsidiary of DTE Energy) and subsidiary companies. Formerly known as Michigan Consolidated Gas Company.
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 DTE Gas to recover through rates its natural gas costs.
MCIT	Michigan Corporate Income Tax
MDEQ	Michigan Department of Environmental Quality
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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PSCR	A Power Supply Cost Recovery mechanism authorized by the MPSC that allows DTE Electric 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.
Securitization	DTE Electric 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
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;

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

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

• 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 DTE Electric and DTE Gas. We also have three other segments that are engaged in a variety of energy-related businesses.

DTE Electric is a Michigan corporation organized in 1903 and is a public utility subject to regulation by the MPSC and the FERC. DTE Electric is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan.

DTE Gas is a Michigan corporation organized in 1898 and is a public utility subject to regulation by the MPSC. DTE Gas 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) power and industrial projects ; and 3) 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

• The Electric segment consists principally of DTE Electric, 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

• The Gas segment consists of DTE Gas and Citizens. DTE Gas 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.

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Non-utility Operations

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

• Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers; produce reduced emissions fuel 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.

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

Description

Our Electric segment consists principally of DTE Electric, an electric utility engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan. 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, a nuclear plant and our wind and other renewable assets, 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, throughout southeastern Michigan.

Revenue by Service

	2012		2011		2010
	(In millions)
Residential	$	2,354	$	2,182	$	2,052
Commercial	1,898		1,704		1,629
Industrial	784		692		688
Other	152		458		479
Subtotal	5,188		5,036		4,848
Interconnection sales (a)	105		118		145
Total Revenue	$	5,293	$	5,154	$	4,993

______________________________

(a) Represents power that is not distributed by DTE Electric.

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 DTE Electric.

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Fuel Supply and Purchased Power

Our power is generated from a variety of fuels and is supplemented with purchased power. We expect to have an adequate supply of fuel and purchased power to meet our obligation to serve customers. Our generating capability is heavily dependent upon the availability of coal. Coal is purchased from various sources in different geographic areas under agreements that vary in both pricing and terms. We expect to obtain the majority of our coal requirements through long-term contracts, with the balance to be obtained through short-term agreements and spot purchases. We have long-term and short-term contracts for the purchase of approximately 22.1 million tons of low-sulfur western coal to be delivered from 2013 through 2015 and approximately 3.5 million tons of Appalachian coal to be delivered from 2013 through 2014. All of these contracts have pricing schedules. We have approximately 81% of our 2013 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 coal rail requirements under contract through 2015. All of our expected eastern coal rail requirements are under contract through 2013. Our expected vessel transportation requirements for delivery of purchased coal to our generating facilities are under contract through 2014.

DTE Electric 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 or during major plant outages.

Properties

DTE Electric 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, 2012 are as follows:

	Location by Michigan	Summer Net Rated Capability (a)
Plant Name	County	(MW)	(%)	Year in Service
Fossil-fueled Steam-Electric
Belle River (b)	St. Clair	1,036	9.8	1984 and 1985
Greenwood	St. Clair	793	7.5	1979
Harbor Beach	Huron	95	0.9	1968
Monroe (c)	Monroe	3,047	28.9	1971, 1973 and 1974
River Rouge	Wayne	524	5.0	1957 and 1958
St. Clair	St. Clair	1,379	13.0	1953, 1954, 1959, 1961 and 1969
Trenton Channel	Wayne	675	6.4	1949 and 1968
		7,549	71.5
Oil or Gas-fueled Peaking Units	Various	1,018	9.6	1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric Fermi 2 (d)	Monroe	1,086	10.3	1988
Hydroelectric Pumped Storage Ludington (e)	Mason	917	8.6	1973
		10,570	100.0

_______________________________________

(a) 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.

(b) The Belle River capability represents DTE Electric’s entitlement to 81% of the capacity and energy of the plant. See Note  9 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.

(c) The Monroe generating plant provided 37% of DTE Electric’s total 2012 power generation.

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

(e) Represents DTE Electric’s 49% interest in Ludington with a total capability of 1,872 MW. See Note 9 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.

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. DTE Electric has approximately 720 MW of owned or contracted renewable energy, principally wind turbines located in Gratiot, Tuscola, Huron and Sanilac counties in Michigan, at December 31, 2012 representing approximately 8% of electricity sold to retail customers. Approximately 510 MW is in commercial operation at December 31, 2012 with an additional 210 MW expected in commercial operation in 2013 or early 2014.

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DTE Electric owns and operates 671 distribution substations with a capacity of approximately 33,648,000 kilovolt-amperes (kVA) and approximately 430,600 line transformers with a capacity of approximately 22,306,000 kVA.

Circuit miles of electric distribution lines owned and in service as of December 31, 2012:

	Circuit Miles
Operating Voltage-Kilovolts (kV)	Overhead	Underground
4.8 kV to 13.2 kV	27,856	14,585
24 kV	182	696
40 kV	2,278	383
120 kV	54	8
	30,370	15,672

There are numerous interconnections that allow the interchange of electricity between DTE Electric 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

DTE Electric'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. DTE Electric'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 DTE Electric 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 DTE Electric'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, 10, 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 DTE Electric’s ability to control its uncollectible accounts receivable and collections expenses. DTE Electric’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 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 2012, 2011 and 2010. Customers 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 have placed a 10% cap on the total potential Customer Choice related migration, mitigating some of the unfavorable effects of electric Customer

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Choice on our financial performance and full service customer rates. We expect that in 2013 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

Description

Our Gas segment consists of DTE Gas and Citizens. DTE Gas is a natural gas utility 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.

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

Revenue by Service

	2012		2011		2010
	(In millions)
Gas sales	$	957	$	1,150	$	1,281
End user transportation	198		194		185
Intermediate transportation	58		58		69
Storage and other	102		103		113
Total Revenue	$	1,315	$	1,505	$	1,648

• 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 marketers, 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. The impacts of changes in average customer usage are minimized by the RDM. Effective with the self implementation of rates on November 1, 2012, the RDM was terminated. The DTE Gas partial rate case settlement agreement approved by the MPSC in December 2012 creates a new RDM effective November 1, 2013 which decouples weather normalized distribution revenue inside caps. The caps are tied to expected customer conservation attributable to DTE Gas' energy efficiency program. or 1.125% in year one, increasing to 2.25% for the second and future periods.

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 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 64% of the volume coming from underground storage for 2012. 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 2015.

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 1,173,000 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 139 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 68 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

DTE Gas' 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. DTE Gas' 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. DTE Gas 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.

DTE Gas 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 DTE Gas in interstate markets. FERC granted DTE Gas

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authority to provide storage and related services in interstate commerce at market-based rates. DTE Gas provides transportation services in interstate commerce at cost-based rates approved by the MPSC and filed with the FERC.

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 DTE Gas’ ability to control its uncollectible accounts receivable and collections expenses. DTE Gas’ 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 due to reduced natural gas usage by customers due to more efficient furnaces and appliances, and an increased emphasis on conservation of energy usage. 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 transportation 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.

DTE Gas’ storage capacity is used to store natural gas for delivery to DTE Gas' 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, intrastate lateral and intrastate gathering pipeline systems, 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
Bluestone Lateral	100	%	44-mile pipeline designed to flow over 275 MMcf per day	PA & NY
Susquehanna gathering system	100	%	Gathering system to transport gas to Bluestone Lateral	PA
Michigan gathering systems	100	%	Gathers production gas in northern Michigan	MI
Storage
Washington 10	100	%	75 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, DTE Gas provides physical operations, maintenance, and technical support for the Washington 10 and 28 storage facilities and for the DTE Gas 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. Bluestone Lateral is regulated as an intrastate pipeline by applicable agencies in the states of New York and Pennsylvania.

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 in 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 Susquehanna gathering system. Bluestone Lateral is a 44-mile pipeline in Susquehanna County, Pennsylvania and Broome County, New York with the southern portion of the pipeline placed in service in 2012 and the northern portion scheduled to be in service in the first quarter of 2013. 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.

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; produce reduced emissions fuel 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 fuel facilities recycle tar decanter sludge, a byproduct of the coking process. We also provide pulverized coal and petroleum coke to the steel, pulp and paper, and other industries.

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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 (REF): We own and operate nine REF 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 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 REF facilities is dependent upon the generation of production tax credits. We placed in service five REF facilities in 2009 and an additional four REF facilities in 2011. To optimize income and cash flow from the REF operations, we sold membership interests in 2011 at two of the facilities (treated as sales of tax credits for financial reporting purposes). 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 for financial reporting purposes, as production tax credits are generated. We continue to optimize these facilities by seeking investors for facilities operating at DTE Electric and other utility sites. Additionally, we intend to relocate certain underutilized facilities to alternative coal-fired power plants which may provide increased production and emission reduction opportunities in 2013 and future years.

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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
Airports	MI & PA	Electricity, Hot and Chilled Water
Chemical Manufacturing	IL, KY & OH	Electricity, Steam, Natural Gas, Compressed Air and Wastewater
Consumer Manufacturing	KY & OH	Electricity, Steam, Hot and Chilled Water, Sewer, Compressed Air
Business Park	FL, NY, OH & PA	Electricity, Steam, Hot and Chilled Water, Compressed Air
Hospital	CA	Electricity, Steam and Chilled Water
Wholesale Power and Renewables
Pulp and Paper	AL	Electric Generation and Steam
Renewables	CA, MN & WI	Electric Generation
Landfill Gas Recovery	Various U.S. sites	Electric Generation and Landfill Gas
Other Industries
REF	MI, OK, IL	REF Supply

	2012		2011		2010
	(In millions)
Production Tax Credits Generated (Allocated to DTE Energy)
REF	$	35	$	1	$	1
Power Generation	7		4		2
Landfill Gas Recovery	1		1		1
Steel Industry Fuels (a)	—		—		29
	$	43	$	6	$	33

______________________________

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

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; landfill gas recovery; and REF 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

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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:

• Selling membership interests in our REF projects;

• Relocating our underutilized REF facilities to alternative coal-fired power plants which may provide increased production and emission reduction opportunities in 2013 and future years;

• 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, gas and coal 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 generating capacity positions. Energy Trading also provides natural gas, power and related services which may include the management of associated storage and transportation contracts on the customers’ behalf under FERC Asset Management Arrangements, and the supply or purchase of renewable energy credits to various customers. Our customer base is predominantly utilities, local distribution companies, pipelines, producers and generators, 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, natural gas inventory, contracts for pipeline transportation, renewable energy credits 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, gas and coal marketers, financial 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.

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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. 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. Actual costs to comply could vary substantially. Additional costs may result as the effects of various substances on the environment are studied and governmental regulations are developed and implemented.

	Electric		Gas		Non-utility		Total
	(In millions)
Air	$	1,784	$	—	$	—	$	1,784
Water	80		—		23		103
Contaminated and other sites	13		30		—		43
Estimated total future expenditures through 2020	$	1,877	$	30	$	23	$	1,930
Estimated 2013 expenditures	$	336	$	10	$	21	$	367
Estimated 2014 expenditures	$	324	$	6	$	2	$	332

Air - DTE Electric 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 emission controls on fossil-fueled power plants to reduce nitrogen oxide and sulfur dioxide, with further emission controls planned for reductions of mercury and other emissions. Future 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, DTE Electric 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, DTE Electric may be required to install technologies to reduce the impacts of the water intakes. However, the types of technologies are unknown at this time. 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 segment owns, or previously owned, fifteen such former MGP sites. DTE Electric owns, or previously owned, three former MGP sites. The Company anticipates the cost amortization methodology approved by the MPSC for DTE Gas, which allows DTE Gas 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, electric generating power plants, 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 and the rates we charge our customers.

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.

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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 9,900 employees as of December 31, 2012, of which approximately 4,900 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 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 prior DTE Electric 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.

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.

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We may also incur liabilities as a result of potential future requirements to address climate change issues. Proposals for voluntary initiatives and mandatory controls are being discussed both in the United States and worldwide to reduce greenhouse gases such as carbon dioxide, a by-product of burning fossil fuels. If increased regulation of greenhouse gas emissions are implemented, the operations of our fossil-fuel generation assets may be significantly impacted. Since there can be no assurances that environmental costs may be recovered through the regulatory process, our financial performance may be negatively impacted as a result of environmental matters.

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.

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 our utility 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

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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.

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 markets. Our long term revolving credit facilities do not expire until 2016, but we regularly access capital markets to refinance existing debt or fund new projects at our utilities and non-utility businesses, and we cannot predict the pricing or demand for those future transactions.

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 non-utility businesses may not perform to our expectations. We rely on our non-utility operations for an increasing 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 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 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 generation, steel industry fuel and gas production operations. All production tax credits taken after 2010 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 power generation facilities 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

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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 implementing 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.

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. 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 gas or stolen gas and electricity could result in decreased earnings and cash flow.

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 4,900 of our employees. Our contracts with several bargaining units for the majority of our represented employees are due to expire in June and October 2013. 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.

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

19

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.

20

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 July 2009, DTE Energy received a Notice of Violation (NOV)/Finding of Violation (FOV) from the EPA alleging, among other things, that five of DTE Electric'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 DTE Electric, 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 DTE Electric 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 DTE Electric 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 DTE Electric'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 DTE Electric. 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. Oral arguments at the Court of Appeals were held on November 27, 2012 and a decision is expected in early 2013.

DTE Energy and DTE Electric 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, DTE Electric 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 DTE Electric 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 the contractor 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.

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.

21

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
2012
	First	$	56.52	$	52.46	$	0.5875
	Second	$	60.25	$	53.70	$	0.5875
	Third	$	62.54	$	58.06	$	0.6200
	Fourth	$	62.49	$	58.20	$	0.6200
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

At December 31, 2012, there were 172,351,680 shares of our common stock outstanding. These shares were held by a total of 67,753 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 $407 million in 2012, $389 million in 2011, and $360 million in 2010. 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, 2012.

	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	1,192,670	$41.86	3,784,351

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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, 2012:

	Number of Shares Purchased (a)	Average Price Paid per Share (a)		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
01/01/2012 — 01/31/2012	6,492	$	53.58	—	—	—
02/01/2012 — 02/28/2012	181,394	53.94		—	—	—
03/01/2012 — 03/31/2012	160,870	54.93		—	—	—
04/01/2012 — 04/30/2012	101,299	56.27		—	—	—
05/01/2012 — 05/31/2012	880	55.74		—	—	—
06/01/2012 — 06/30/2012	25,052	57.54		—	—	—
07/01/2012 — 07/31/2012	51,873	60.74		—	—	—
08/01/2012 — 08/31/2012	9,114	51.70		—	—	—
09/01/2012 — 09/30/2012	1,500	47.69		—	—	—
10/01/2012 — 10/31/2012	1,278	59.51		—	—	—
11/01/2012 — 11/30/2012	1,000	59.23		—	—	—
12/01/2012 — 12/31/2012	27,791	51.26		—	—	—
Total	568,543			—

_______________________________________

(a) 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.

COMPARISON OF CUMULATIVE FIVE YEAR TOTAL RETURN

Total Return To Shareholders

(Includes reinvestment of dividends)

	Annual Return Percentage Year Ended December 31
Company/Index	2008		2009	2010	2011	2012
DTE Energy Company	(14.37	)	30.08	9.06	25.76	14.90
S&P 500 Index	(37.00	)	26.46	15.06	2.11	16.00
S&P 500 Multi-Utilities Index	(24.34	)	20.92	11.08	18.41	4.24

	Indexed Returns Year Ended December 31
	Base Period
Company/Index	2007	2008	2009	2010	2011	2012
DTE Energy Company	100	85.63	111.38	121.47	152.76	175.53
S&P 500 Index	100	63.00	79.67	91.68	93.61	108.59
S&P 500 Multi-Utilities Index	100	75.66	91.49	101.63	120.33	125.43

23

24

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.

	2012			2011			2010			2009			2008
	(In millions, except per share amounts)
Operating Revenues	$	8,791		$	8,858		$	8,525		$	7,983		$	9,281
Net Income Attributable to DTE Energy Company
Income from continuing operations (a)	$	666		$	714		$	638		$	538		$	439
Discontinued operations (b)	(56		)	(3		)	(8		)	(6		)	107
Net Income Attributable to DTE Energy Company	$	610		$	711		$	630		$	532		$	546
Diluted Earnings Per Common Share
Income from continuing operations	$	3.88		$	4.20		$	3.78		$	3.27		$	2.69
Discontinued operations	(0.33		)	(0.02		)	(0.04		)	(0.03		)	0.65
Diluted Earnings Per Common Share	$	3.55		$	4.18		$	3.74		$	3.24		$	3.34
Financial Information
Dividends declared per share of common stock	$	2.42		$	2.32		$	2.18		$	2.12		$	2.12
Total assets	$	26,339		$	26,009		$	24,896		$	24,195		$	24,590
Long-term debt, including capital leases	$	7,014		$	7,187		$	7,089		$	7,370		$	7,741
Shareholders’ equity	$	7,373		$	7,009		$	6,722		$	6,278		$	5,995

_______________________________________

(a) 2011 results include an $87 million income tax benefit related to the enactment of the MCIT.

(b) Discontinued operations represents the Unconventional Gas Production business that was sold in 2012 resulting in a $55 million after-tax loss on sale. The 2008 results include an $80 million after-tax gain on the sale of a portion of the Unconventional Gas Production properties.

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

EXECUTIVE OVERVIEW

DTE Energy is a diversified energy company with 2012 operating revenues of approximately $8.8 billion and approximately $26 billion in assets. We are the parent company of DTE Electric and DTE Gas, 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 three energy-related non-utility segments with operations throughout the United States.

The following table summarizes our financial results:

	2012		2011		2010
	(In millions, except per share amounts)
Income from continuing operations	$	674	$	723	$	647
Diluted earnings per common share from continuing operations	$	3.88	$	4.20	$	3.78

The decrease in 2012 Income from continuing operations is principally driven by 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 and lower results in the Energy Trading segment, partially offset by improved results in the Electric segment. The increase in 2011 Income from continuing operations is due to the above mentioned income tax benefit and higher earnings in Energy Trading, partially offset by lower earnings in the Electric and Gas segments and in the Power and Industrial Projects segment.

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, maintain a strong balance sheet and continue our attractive dividend yield.

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.

25

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, issuance of debt and issuance of equity through our dividend reinvestment plan and pension and other employee benefit plans. We have 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. DTE Electric's capital investments over the 2013-2017 period are estimated at $4.7 billion for base infrastructure, $1.2 billion for mandated environmental compliance requirements and $500 million for renewable energy and energy efficiency expenditures. DTE Gas' capital investments over the 2013-2017 period are estimated at $650 million for base infrastructure and $400 million for gas main renewal, meter move out and pipeline integrity programs. DTE Gas proposed in its rate case filing in April 2012, starting in 2013, a five-year annual incremental Infrastructure Recovery Mechanism (IRM) to recover costs associated with capital investment for the gas main renewal and meter move out programs. The IRM was not part of the rate case settlement approved in December 2012 and is expected to be resolved in 2013. DTE Electric and DTE Gas 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. DTE Electric 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 DTE Electric's and the State of Michigan's sources of electric supply and addressing the state and national goals of increasing energy independence. DTE Electric 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.

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.

DTE Electric 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 emission controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, DTE Electric has spent approximately $1.9 billion through 2012. It is estimated that DTE Electric will make capital expenditures of approximately $335 million in 2013 and up to approximately $1.6 billion of additional capital expenditures through 2020 based on current regulations.

Climate regulation and/or legislation has been proposed and discussed within the U.S. Congress and the EPA. The EPA is implementing regulatory actions under the Clean Air Act to address emissions of greenhouse gases (GHGs). EPA regulation of GHGs requires the best available control technology (BACT) for new major sources or modifications to existing major sources that cause significant increases in GHG emissions. In June 2012, the EPA proposed new source performance standards for carbon dioxide emissions from new fossil-fueled power plants. These new source performance standards are expected to be finalized in 2013 as well as a proposed performance standard for carbon dioxide emissions from existing plants. 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

26

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 customer satisfaction;

• effectively manage rate competitiveness and affordability;

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

• managing the growth of our utility asset base;

• continuing to improve employee engagement;

• 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.

	2012			2011			2010
	(In millions)
Net Income Attributable to DTE Energy by Segment:
Electric	$	483		$	434		$	441
Gas	115			110			127
Gas Storage and Pipelines	61			57			51
Power and Industrial Projects	42			38			85
Energy Trading	12			52			6
Corporate and Other	(47		)	23			(72		)
Income From Continuing Operations Attributable to DTE Energy Company	666			714			638
Discontinued Operations	(56		)	(3		)	(8		)
Net Income Attributable to DTE Energy Company	$	610		$	711		$	630

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ELECTRIC

Our Electric segment consists principally of DTE Electric.

Electric results are discussed below:

	2012			2011			2010
	(In millions)
Operating Revenues	$	5,293		$	5,154		$	4,993
Fuel and Purchased Power	1,758			1,716			1,580
Gross Margin	3,535			3,438			3,413
Operation and Maintenance	1,429			1,370			1,305
Depreciation and Amortization	827			818			849
Taxes Other Than Income	257			240			237
Asset (Gains) and Losses, Reserves and Impairments, Net	(2		)	13			(6		)
Operating Income	1,024			997			1,028
Other (Income) and Deductions	261			298			317
Income Tax Expense	280			265			270
Net Income Attributable to DTE Energy Company	$	483		$	434		$	441
Operating Income as a Percent of Operating Revenues	19		%	19		%	21		%

Gross margin increased $97 million in 2012 and increased $25 million in 2011. 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:

	2012			2011
	(In millions)
2011 rate case increase and weather effect, net of 2011 RDM	$	79		$	29
Restoration tracker, discontinued in October 2011	(47		)	27
Securitization bond and tax surcharge	25			(39		)
Renewable energy program	35			26
Energy optimization performance incentive	(7		)	17
Low Income Energy Efficiency Fund revenue deferral	4			(23		)
Regulatory mechanisms and other	8			(12		)
Increase in gross margin	$	97		$	25

	2012	2011	2010
	(In thousands of MWh)
Electric Sales
Residential	15,666	15,907	15,726
Commercial	16,832	16,779	16,570
Industrial	9,989	9,739	10,195
Other	958	3,136	3,210
	43,445	45,561	45,701
Interconnection sales (a)	2,125	3,512	4,876
Total Electric Sales	45,570	49,073	50,577
Electric Deliveries
Retail and Wholesale	43,445	45,561	45,701
Electric Customer Choice, including self generators	5,197	5,445	5,005
Total Electric Sales and Deliveries	48,642	51,006	50,706

______________________________

(a) Represents power that is not distributed by DTE Electric.

Operation and maintenance expense increased $59 million in 2012 and increased $65 million in 2011. The increase in 2012 is primarily due to higher employee benefit expenses of $53 million, increased energy optimization and renewable energy expenses of $17 million, higher power plant generation expenses of $12 million, increased distribution operations expenses of $4 million and higher expenses for low income energy assistance of $4 million, partially offset by reduced restoration and line clearance expenses of $22 million and reduced uncollectible expenses of $9 million. The increase in 2011 is primarily due to higher restoration and line clearance expenses of $41 million, higher generation maintenance and outage expenses of

28

$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.

Depreciation and amortization expense increased $9 million in 2012 due primarily to higher amortization of regulatory assets, partially offset by the net effect of lower depreciation rates on a higher depreciable base. Depreciation and amortization expense was $31 million lower in 201l due primarily to reduced amortization of regulatory assets, partially offset by expenses related to a higher depreciable base.

Asset (gains) and losses, reserves and impairments, net decreased $15 million in 2012 and increased $19 million in 2011 principally attributable to a 2011 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 2011 revision of $6 million in the timing and estimate of cash flows for the Fermi 1 asbestos removal obligation and other items. See Note 10 of the Notes to the Consolidated Financial Statements.

Other (income) and deductions were lower by $37 million in 2012 and $19 million in 2011. The decrease in 2012 was due primarily to the lower contributions to the DTE Foundation of $21 million and lower interest expense of $17 million. The 2011 decrease was due to lower interest expense of $24 million, partially offset by higher contributions to the DTE Foundation of $7 million.

Outlook— 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 weather, 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 and electric choice. We expect to continue our efforts to improve productivity and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.

On June 25, 2012, our Fermi 2 nuclear power plant was manually shutdown after one of the plant's two non-safety related feed-water pumps failed. Supported by a detailed analysis, DTE Electric decided to operate the plant with one feed-water pump at a reduced power level until the second feed-water pump is returned to service. The plant was restarted on July 30, 2012 which restored production to 68% of full capacity. We expect that a substantial portion of the property damage will be covered by existing insurance coverage, subject to deductibles. We are able to purchase sufficient power from MISO to continue to provide uninterrupted service to our customers. We plan to seek recovery of the related incremental purchased power costs through the PSCR process. The plant is scheduled to be brought down in the first quarter of 2013 to complete the repair.

GAS

Our Gas segment consists of DTE Gas and Citizens.

Gas results are discussed below:

	2012			2011			2010
	(In millions)
Operating Revenues	$	1,315		$	1,505		$	1,648
Cost of Gas	550			744			870
Gross Margin	765			761			778
Operation and Maintenance	385			394			378
Depreciation and Amortization	92			89			92
Taxes Other Than Income	54			54			55
Operating Income	234			224			253
Other (Income) and Deductions	69			54			59
Income Tax Expense	50			60			67
Net Income Attributable to DTE Energy Company	$	115		$	110		$	127
Operating Income as a Percent of Operating Revenues	18		%	15		%	15		%

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Gross margin increased $4 million in 2012 and decreased $17 million in 2011. 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:

	2012			2011
	(In millions)
Weather	$	(41	)	$	25
Uncollectible expenses tracking mechanism	—			(27		)
Lost and stolen gas	29			—
Self-implementation and rate orders	5			(4		)
Revenue decoupling mechanism	11			5
Energy optimization performance incentive	(2		)	7
Energy optimization revenue	6			10
Midstream storage and transportation revenues	6			(12		)
Subsidiaries transferred to Gas Storage and Pipelines segment	—			(17		)
Lower average consumption	(6		)	—
Other	(4		)	(4		)
Increase (decrease) in gross margin	$	4		$	(17	)

	2012	2011	2010
Gas Markets (in Bcf)
Gas sales	104	123	118
End user transportation	157	141	140
	261	264	258
Intermediate transportation	264	273	391
	525	537	649

Operation and maintenance expense decreased $9 million in 2012 and increased $16 million in 2011. The decrease in 2012 is primarily due to reduced uncollectible expenses of $9 million, lower legal liability expenses of $4 million and lower customer service expenses of $3 million, partially offset by increased energy optimization expenses of $6 million and higher employee benefit-related expenses of $3 million. The increase in 2011 is primarily due to the 2010 deferral of $32 million of previously expensed costs to achieve 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.

Other (income) and deductions were higher by $14 million in 2012 and lower by $5 million in 2011. The increase in 2012 was due primarily to higher contributions to the DTE Foundation of $21 million, partially offset by lower interest expenses of $5 million. The decrease in 2011 was due primarily to lower interest expense of $3 million.

Income tax expense was lower by $10 million in 2012. The decrease is principally due to adjustments to deferred taxes.

Outlook — 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 infrastructure capital expenditures will result in earnings growth. Looking forward, additional factors may impact earnings such as weather, the outcome of 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 and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.

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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:

	2012			2011			2010
	(In millions)
Operating Revenues	$	96		$	91		$	83
Operation and Maintenance	19			16			14
Depreciation and Amortization	8			6			5
Taxes Other Than Income	3			3			2
Asset (Gains) and Losses and Reserves, Net	3			—			—
Operating Income	63			66			62
Other (Income) and Deductions	(40		)	(28		)	(25		)
Income Tax Expense	39			35			32
Net Income	64			59			55
Noncontrolling interest	3			2			4
Net Income Attributable to DTE Energy	$	61		$	57		$	51

Net income attributable to DTE Energy increased $4 million and $6 million in 2012 and 2011, respectively. The 2012 increase was primarily driven by higher earnings from our pipeline equity investments. The 2011 increase was primarily driven by earnings from subsidiaries that were transferred from Gas segment, increased earnings from our pipeline equity investments, and a settlement for customer gas treating services performed in prior years.

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 2013. 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, the Company has executed an agreement with Southwestern Energy Services Company to support its Bluestone lateral and Susquehanna gathering system. Bluestone is a 44-mile pipeline in Susquehanna County, Pennsylvania and Broome County, New York designed to initially flow over 275,000 dth/d to both Millennium Pipeline and Tennessee Pipeline. The southern portion of Bluestone was placed in service in the fourth quarter of 2012 and the northern portion is scheduled to be placed in service in the first quarter of 2013. A portion of the Susquehanna gathering system was placed in service in the fourth quarter of 2012 and additional segments will be placed in service periodically over the next few years.

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; produce reduced emissions fuel (REF) and sell electricity from biomass-fired energy projects.

Power and Industrial Projects results are discussed below:

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	2012			2011			2010
	(In millions)
Operating Revenues	$	1,823		$	1,129		$	1,144
Operation and Maintenance	1,788			1,025			978
Depreciation and Amortization	65			60			60
Taxes other than Income	16			10			14
Asset (Gains) and Losses, Reserves and Impairments, Net	(5		)	(12		)	(14		)
Operating Income (Loss)	(41		)	46			106
Other (Income) and Deductions	(44		)	(10		)	13
Income Taxes
Expense	—			17			36
Production Tax Credits	(44		)	(6		)	(33		)
	(44		)	11			3
Net Income	47			45			90
Noncontrolling interest	5			7			5
Net Income Attributable to DTE Energy Company	$	42		$	38		$	85

Operating revenues increased $694 million in 2012 and decreased $15 million in 2011. The 2012 increase is primarily due to a $740 million increase associated with higher volumes from REF projects, of which $554 million represents affiliate transactions, and a $30 million increase due to the newly acquired on-site projects, partially offset by a $44 million decrease primarily due to lower volumes associated with the steel business, and a $28 million decrease in coal transportation and marketing services business. 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 REF projects, of which $90 million represents affiliate transactions, a $74 million increase in coke demand and pricing, and a $26 million increase in new on-site energy services projects.

Operation and maintenance expense increased $763 million in 2012 and increased $47 million in 2011. The 2012 increase is primarily due to a $770 million increase associated with higher volumes from REF projects, of which $562 million represents affiliate transactions, a $25 million increase due to the newly acquired on-site projects and a $11 million customer settlement, partially offset by a $20 million decrease primarily due to lower volumes associated with the steel business and a $26 million decrease in coal transportation and marketing services business. The 2011 increase is due primarily to a $103 million increase in coal costs, a $93 million increase related to REF projects, of which $91 million represents affiliate transactions, 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, a $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.

Asset (gains) and losses, reserves and impairments, net decreased by $7 million in 2012 and decreased by $2 million in 2011. The 2012 decrease was due to a $3 million loss on the sale of assets associated with our coal transloading terminal and $3 million of impairments related to non-strategic assets. 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.

Other (income) and deductions were higher by $34 million in 2012 and higher by $23 million in 2011. The increase in 2012 and 2011 were due primarily to gains recognized in connection with sale of membership interest in REF facilities (treated as sales of tax credits for financial reporting purposes). The increase in 2011 also included $12 million of gains on the extinguishment of debt related to our landfill gas recovery business.

Production tax credits increased by $38 million in 2012 primarily due to tax credits earned from REF projects. The decrease of $27 million in 2011 was due primarily to the expiration of steel industry fuels credits as of December 31, 2010, partially offset by tax credits earned from REF projects.

Outlook - The Company has constructed and placed in service nine REF facilities including three facilities located at third party owned coal-fired power plants. The Company has sold membership interests in two of the facilities. We continue to optimize these facilities by seeking tax investors for facilities operating at DTE Electric and other utility sites. Additionally, we intend to relocate three underutilized facilities, located at DTE Electric sites, to alternative coal-fired power plants which may provide increased production and emission reduction opportunities in 2013 and future years. One of the underutilized facilities is currently being relocated to a third party owned coal-fired power plant. The proceeds from executed and planned sales of membership interests in the REF facilities are expected to be received by the Company on an installment basis, and the

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Company will recognize the related gains (treated as sales of tax credits for financial reporting purposes) as production tax credits are generated by the respective facilities.

We expect reduced production levels of metallurgical coke and pulverized coal supplied to steel industry customers for 2013. Substantially all of the metallurgical coke margin is maintained under long-term contracts. We have four biomass-fired power generation facilities that were in operation in 2012, and we are converting an additional facility to be placed in service in 2013. Our on-site energy services will continue to be delivered in accordance with the terms of long-term contracts. During 2012, we purchased a portfolio of fourteen on-site energy projects, primarily located in the Midwest. 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.

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ENERGY TRADING

Energy Trading focuses on physical and financial power, gas and coal 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 generating capacity positions. Energy Trading also provides natural gas, power and related services, and the supply or purchase of renewable energy credits to various customers which may include the management of associated storage and transportation contracts on the customers’ behalf.

Energy Trading results are discussed below:

	2012		2011		2010
	(In millions)
Operating Revenues	$	1,109	$	1,276	$	875
Fuel, Purchased Power and Gas	1,011		1,112		786
Gross Margin	98		164		89
Operation and Maintenance	66		63		59
Depreciation and Amortization	2		3		5
Taxes Other Than Income	3		3		2
Operating Income	27		95		23
Other (Income) and Deductions	8		9		12
Income Tax Expense	7		34		5
Net Income Attributable to DTE Energy Company	$	12	$	52	$	6

Gross margin decreased $66 million in 2012 and increased $75 million in 2011. The overall decrease in gross margin in 2012 was the result of decreased economic performance in our power and gas trading and power full requirements services strategies due to fewer market opportunities.

The decrease in 2012 represents a $28 million decrease in realized margins and a $38 million decrease in unrealized margins. The $28 million decrease in realized margins is due to $74 million of unfavorable results, primarily in our power and gas trading and power full requirements services strategies, offset by $46 million of favorable results, primarily in our gas full requirements services, gas structured, and gas transportation strategies. The $38 million decrease in unrealized margins is due to $58 million of unfavorable results, primarily in our power and gas full requirements services, power trading, and gas structured and storage strategies, offset by $20 million of favorable results, primarily in our gas trading strategy.

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

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 generation capacity positions. Energy Trading also provides natural gas, power and related services, which may include the management of associated storage and transportation contracts on the customers' behalf under FERC Asset Management Arrangements, and the supply or purchase of renewable energy credits to various customers. 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, pipeline transportation, renewable energy credits, and storage assets are not derivatives. As a result, we will experience earnings volatility as derivatives are marked-to-market without revaluing the underlying non-derivative contracts and assets. 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.

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CORPORATE AND OTHER

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

The 2012 net loss of $47 million represented a decrease of $70 million from the 2011 net income of $23 million. The decrease resulted primarily from a income tax benefit of $87 million related to the enactment of the MCIT in the second quarter of 2011, partially offset by lower interest costs.

The 2011 net income of $23 million was an improvement of $95 million from the 2010 net loss of $72 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.

DISCONTINUED OPERATIONS

Unconventional Gas Production

In December 2012, the Company sold its 100% equity interest in its Unconventional Gas Production business which consisted of gas and oil production assets in the western Barnett and Marble Falls shale areas of Texas. The properties in the sale included all of the reserves on approximately 88,000 net acres near Dallas, Texas. The sale resulted in gross proceeds of approximately $255 million, which resulted in a pre-tax loss of approximately $83 million ($55 million after tax).

The activity of the discontinued Unconventional Gas Production business is shown below. The amounts exclude general corporate overhead costs, and the related tax effects, and no portion of corporate interest costs were allocated to discontinued operations.

	2012			2011			2010
	(In millions)
Operating Revenues	$	55		$	39		$	32
Operation and Maintenance	24			16			11
Depreciation, Depletion and Amortization	23			18			15
Taxes Other Than Income	4			3			2
Asset (Gains) and Losses, Net	83			—			10
Operating Income (Loss)	(79		)	2			(6		)
Other (Income) and Deductions	6			6			6
Income Tax Benefit	(29		)	(1		)	(4		)
Net Income (Loss) Attributable to DTE Energy Company	$	(56	)	$	(3	)	$	(8	)

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 2013, we expect that cash from operations will be $1.8 billion due to higher working capital requirements. We anticipate base level utility capital investments, environmental, renewable and energy optimization expenditures and expenditures for non-utility businesses in 2013 of approximately $2.2 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.

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	2012			2011			2010
	(In millions)
Cash and Cash Equivalents
Cash Flow From (Used For)
Operating activities:
Net income	$	618		$	720		$	639
Depreciation, depletion and amortization	1,018			995			1,027
Deferred income taxes	47			220			457
Loss on sale of non-utility business	83			—			—
Asset (gains) and losses, reserves and impairments, net	1			(21		)	(5		)
Working capital and other	442			94			(293		)
	2,209			2,008			1,825
Investing activities:
Plant and equipment expenditures — utility	(1,451		)	(1,382		)	(1,011		)
Plant and equipment expenditures — non-utility	(369		)	(102		)	(88		)
Proceeds from sale of non-utility business	255			—			—
Proceeds from sale of assets	38			18			56
Acquisition, net of cash acquired	(198		)	—			—
Other	(44		)	(94		)	(183		)
	(1,769		)	(1,560		)	(1,226		)
Financing activities:
Issuance of long-term debt	759			1,179			614
Redemption of long-term debt	(639		)	(1,455		)	(663		)
Short-term borrowings, net	(179		)	269			(177		)
Issuance of common stock	39			—			36
Repurchase of common stock	—			(18		)	—
Dividends on common stock	(407		)	(389		)	(360		)
Other	(16		)	(31		)	(36		)
	(443		)	(445		)	(586		)
Net Increase (Decrease) in Cash and Cash Equivalents	$	(3	)	$	3		$	13

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 $2.2 billion in 2012 was $201 million higher than the comparable 2011 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, loss on sale of non-utility business and asset (gains) and losses, reserves and impairments, net).

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

The changes in working capital items in both years primarily relate to pension and postretirement obligations and income tax 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.

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.

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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 2012 and 2011 due primarily to increased capital expenditures by our utility and non-utility businesses. The 2012 increase includes higher capital expenditures for the Bluestone Pipeline project and the Power and Industrial Projects acquisition of fourteen on-site energy projects, partially offset by the proceeds from the sale of the Unconventional Gas Production business.

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 $443 million in 2012, compared to net cash used for financing activities of approximately $445 million for the same period in 2011. The change was primarily attributable to lower redemptions of long-term debt, offset by a reduction in short-term borrowings.

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.

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 capital spending to maintain and improve our electric generation and electric and gas distribution infrastructure and to comply with 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 $800 million in long-term debt maturing in the next twelve months. The repayment of the principal amount of the Securitization debt is funded through a surcharge payable by DTE Electric’s customers. The repayment of the other debt is expected to be paid through internally generated funds or the issuance of long-term debt.

DTE Energy has approximately $1.6 billion of available liquidity at December 31, 2012, consisting of cash and amounts available under unsecured revolving credit agreements.

We expect to issue equity of approximately $300 million in 2013 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 $315 million contribution to the pension plans in 2013. In January 2013, the Company contributed $145 million to its postretirement benefit plans. At the discretion of management, the Company may make up to an additional $120 million contribution to its postretirement benefit plans in 2013.

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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. As of December 31, 2012, 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 was approximately $326 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. In addition, the Company maintains adequate credit facilities to meet this obligation should such an occurrence arise.

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, 2012:

	Total		2013		2014-2015		2016-2017		2018 and Beyond
	(In millions)
Long-term debt:
Mortgage bonds, notes and other	$	6,865	$	634	$	1,066	$	474	$	4,691
Securitization bonds	479		177		302		—		—
Junior subordinated debentures	480		—		—		—		480
Capital lease obligations	20		7		10		3		—
Interest	5,890		415		688		577		4,210
Operating leases	233		38		56		41		98
Electric, gas, fuel, transportation and storage purchase obligations (a)	4,229		1,856		1,584		222		567
Other long-term obligations (b)(c)(d)	148		80		39		13		16
Total obligations	$	18,344	$	3,207	$	3,745	$	1,330	$	10,062

_______________________________________

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

(b) Includes liabilities for unrecognized tax benefits of $11 million.

(c) Excludes other long-term liabilities of $179 million not directly derived from contracts or other agreements.

(d) At December 31, 2012, 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 herein 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.

As part of the normal course of business, DTE Electric, DTE Gas 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 DTE Electric and DTE Gas contain similar provisions in the event that the senior unsecured debt rating of the particular utility is downgraded below investment grade.

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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 2012, Fitch Ratings raised DTE Electric's senior secured debt rating from 'A-' to 'A' and raised DTE Gas' senior secured debt rating from 'BBB+' to 'A-'. At the same time, Fitch Ratings revised the outlook for DTE Gas from stable to positive. In January 2013, Fitch raised DTE Gas' senior secured debt rating from 'A-' to 'A' and revised the outlook from positive to stable. In February 2012, Moody's revised the outlook of DTE Energy, DTE Electric and DTE Gas from stable to positive. In February 2013, Moody's raised DTE Energy's senior unsecured debt rating from 'Baa2' to 'Baa1', DTE Electric's senior secured debt rating from 'A2' to 'A1', and DTE Gas' senior secured debt rating from 'A2 to A1'. At the same time, Moody's revised the outlook of DTE Energy, DTE Electric and DTE Gas from positive to stable.

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. DTE Electric and DTE Gas 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.

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 DTE Electric and DTE Gas 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, 2012 and 2011. Management believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

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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 analyses 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. We believe the allowance for doubtful accounts is based on reasonable estimates.

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 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 (“step zero”). The standard is effective for annual and interim goodwill impairments tests for fiscal years beginning after December 15, 2011. We did not apply step zero for the 2012 goodwill impairment test and proceeded directly to step one of the test.

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.

We performed our annual impairment test as of October 1, 2012 and determined that except for the Unconventional Gas Production reporting unit, the estimated fair value of each reporting unit exceeded its carrying value, and no impairment existed. The $2 million of goodwill attributable to the Unconventional Gas Production reporting unit was written off in the fourth quarter of 2012 in connection with its sale. As part of the annual impairment test, 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.

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As of October 1, 2012 Valuation Date:

Reporting Unit	Goodwill		Fair Value Reduction % (a)		Discount Rate		Terminal Multiple (b)	Valuation Methodology (c)
	(In millions)
Electric	$	1,208	31	%	7	%	9.0x	DCF, assuming stock sale
Gas	745		21	%	7	%	10.5x	DCF, assuming stock sale
Power and Industrial Projects (d)	26		70	%	9	%	10.0x	DCF, assuming asset sale (e)
Gas Storage and Pipelines	22		82	%	8	%	11.0x	DCF, assuming asset sale
Energy Trading	17		33	%	15	%	n/a	DCF, assuming asset sale
Unconventional Gas Production (f)	2		n/a		n/a		n/a	Sales Price
	$	2,020

_______________________________________

(a)	Percentage by which the fair value of equity 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 2013-2017 projected cash flows plus a calculated terminal value.
(d)	Power and Industrial Projects excludes Biomass and Coal Services reporting units as these units have no allocated goodwill.
(e)	Asset sales were assumed except for Power and Industrial Projects' reduced emissions fuel projects, which assumed stock sales.
(f)	Goodwill attributable to Unconventional Gas Production was written off in the fourth quarter of 2012 in connection with its sale. Refer to Note 7 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

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.

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 $220 million in 2012, $172 million in 2011, and $112 million in 2010. Postretirement benefits costs were $151 million in 2012, $122 million in 2011 and $164 million in 2010. Pension and postretirement benefits costs for 2012 are calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on our plan assets of 8.25%. 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 2013 expected long-term rate of return on pension plan assets is based on an asset allocation assumption utilizing active investment

41

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 maintaining our long-term rate of return assumption for our pension plans and our postretirement health and life plans at 8.25% for 2013. We believe this rate is a reasonable assumption for the long-term rate of return on our plan assets for 2013 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 2012 contributed to our investment performance resulting in unrecognized net gains. As of December 31, 2012, we had $81 million of cumulative losses that remain to be recognized in the calculation of the MRV of pension assets related to investment performance in 2012, 2011 and 2010. 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 4.15% at December 31, 2012 from 5.0% at December 31, 2011. We estimate that our 2013 total pension costs will approximate $226 million compared to $220 million in 2012 primarily due to a lower discount rate and higher amortization of net actuarial losses, partially offset by 2013 contributions. Our 2013 postretirement benefit costs will approximate $30 million compared to $151 million in 2012 primarily due to plan design changes and favorable retiree medical utilization, partially offset by a lower discount rate, higher amortization of net actuarial losses and updated assumed long-term retiree medical inflation. Our health care trend rate assumes 7.00% for 2013 through 2017, 6.50% in 2018, 6.00% in 2019, 5.50% in 2020 and 5.00% in 2021 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 DTE Gas' negative pension expense. DTE Gas 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 2012 pension costs by approximately $32 million. Lowering the discount rate and the salary increase assumptions by one percentage point would have increased our 2012 pension costs by approximately $14 million. Lowering the expected long-term rate of return on our plan assets by one percentage point would have increased our 2012 postretirement costs by approximately $10 million. Lowering the discount rate assumption by one percentage point would have increased our 2012 postretirement costs by approximately $46 million. Lowering the health care cost trend assumptions by one percentage point would have decreased our postretirement benefit service and interest costs for 2012 by approximately $26 million.

The value of our qualified pension and postretirement benefit plan assets was $4.4 billion at December 31, 2012 and $3.9 billion at December 31, 2011. At December 31, 2012, our qualified pension plans were underfunded by $1.4 billion and our other postretirement benefit plans were underfunded by $1.2 billion. The 2012 and 2011 funding levels were generally similar due to plan sponsor contributions in 2012 and 2011, largely offset by the impact of 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 qualified pension plans of $229 million in 2012 and $200 million in 2011. 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 qualified pension plans of $315 million in 2013 and up to $1.3 billion over the next five years. We made postretirement benefit plan contributions of $140 million and $111 million in 2012 and 2011, 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 $145 million to our postretirement plans in January 2013 and expect to make up to an additional $120 million contribution to our postretirement plans in 2013 and, subject to MPSC funding requirements, up to $622 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.

See Note 20 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

42

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, 2012, this IBNR liability was approximately $37 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 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 believe the resulting tax reserve balances as of December 31, 2012 and December 31, 2011 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, pipeline transportation, renewable energy credits and storage assets. See Notes 3 and 4 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

The tables below do not include the expected earnings impact of non-derivative gas storage, transportation, certain power contracts and renewable energy credits 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

43

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 in Item 8 of this Report.

The following tables provide details on changes in our MTM net asset (or liability) position during 2012:

	Total
	(In millions)
MTM at December 31, 2011	$	49
Reclassify to realized upon settlement	(80		)
Changes in fair value recorded to income	65
Amounts recorded to unrealized income	(15		)
Changes in fair value recorded in regulatory liabilities	15
Change in collateral held by (for) others	(56		)
Option premiums paid and other	3
MTM at December 31, 2012	$	(4	)

The table below shows the maturity of our MTM positions:

Source of Fair Value	2013			2014			2015			2016  and  Beyond		Total Fair Value
	(In millions)
Level 1	$	26		$	9		$	(6	)	$	—	$	29
Level 2	(19		)	(1		)	—			—		(20		)
Level 3	(24		)	9			2			—		(13		)
MTM before collateral adjustments	$	(17	)	$	17		$	(4	)	$	—	(4		)
Collateral adjustments												—
MTM at December 31, 2012												$	(4	)

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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 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 segment. Gas segment 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 exposure to natural gas price fluctuations which impact the pricing for natural gas storage and transportation. The Company manages its exposure through the use of short, medium and long-term storage and transportation contracts.

Our Power and Industrial Projects business segment is subject to electricity and natural gas product price risk. 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, coal, 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 the consolidated financial statements.

Other

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

45

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, 2012:

	Credit Exposure Before Cash Collateral		Cash Collateral			Net Credit Exposure
	(In millions)
Investment Grade (a)
A− and Greater	$	88	$	—		$	88
BBB+ and BBB	259		—			259
BBB−	84		—			84
Total Investment Grade	431		—			431
Non-investment grade (b)	2		—			2
Internally Rated — investment grade (c)	147		(3		)	144
Internally Rated — non-investment grade (d)	26		(1		)	25
Total	$	606	$	(4	)	$	602

_______________________________________

(a) This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s Investors 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 39 percent of the total gross credit exposure.

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

(c) 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 16 percent of the total gross credit exposure.

(d) 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 three 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, 2012, we had a floating rate debt-to-total debt ratio of approximately 7 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 gas and 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 2016.

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, 2012 and 2011 by a hypothetical 10% and calculating the resulting change in the fair values.

46

The results of the sensitivity analysis calculations as of December 31, 2012 and 2011:

	Assuming a 10% Increase in Rates						Assuming a 10% Decrease in Rates
	As of December 31,						As of December 31,
Activity	2012			2011			2012			2011			Change in the Fair Value of
	(In millions)
Coal contracts	$	2		$	(2	)	$	(1	)	$	2		Commodity contracts
Gas contracts	$	(4	)	$	(9	)	$	3		$	13		Commodity contracts
Power contracts	$	4		$	4		$	(5	)	$	(6	)	Commodity contracts
Interest rate risk	$	(247	)	$	(260	)	$	260		$	276		Long-term debt
Foreign currency exchange risk	$	—		$	—		$	—		$	—		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.

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Item 8. Financial Statements and Supplementary Data

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

	Page
Controls and Procedures	49
Report of Independent Registered Public Accounting Firm	50
Consolidated Statements of Operations	51
Consolidated Statements of Comprehensive Income	52
Consolidated Statements of Financial Position	53
Consolidated Statements of Cash Flows	55
Consolidated Statements of Changes in Equity	56
Notes to Consolidated Financial Statements	57
Note 1. Organization and Basis of Presentation	57
Note 2. Significant Accounting Policies	59
Note 3. Fair Value	63
Note 4. Financial and Other Derivative Instruments	68
Note 5. Goodwill	71
Note 6. Acquisition	71
Note 7. Discontinued Operations	72
Note 8. Property, Plant and Equipment	73
Note 9. Jointly Owned Utility Plant	74
Note 10. Asset Retirement Obligations	75
Note 11. Regulatory Matters	76
Note 12. Income Taxes	82
Note 13. Common Stock	84
Note 14. Earnings Per Share	86
Note 15. Long-Term Debt	87
Note 16. Preferred and Preference Securities	88
Note 17. Short-Term Credit Arrangements and Borrowings	88
Note 18. Capital and Operating Leases	89
Note 19. Commitments and Contingencies	90
Note 20. Retirement Benefits and Trusteed Assets	95
Note 21. Stock-based Compensation	105
Note 22. Supplemental Cash Flow Information	107
Note 23. Segment and Related Information	108
Note 24. Supplementary Quarterly Financial Information (Unaudited)	110
Financial Statement Schedule
Schedule II — Valuation and Qualifying Accounts	119

48

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, 2012, 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, 2012. 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, 2012, 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, 2012 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, 2012 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

49

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, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 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, 2012, 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 20, 2013

50

DTE Energy Company

Consolidated Statements of Operations

	Year Ended December 31
	2012			2011			2010
	(In millions, except per share amounts)
Operating Revenues	$	8,791		$	8,858		$	8,525
Operating Expenses
Fuel, purchased power and gas	3,296			3,537			3,190
Operation and maintenance	2,892			2,612			2,567
Depreciation, depletion and amortization	995			977			1,012
Taxes other than income	332			310			306
Other asset (gains) and losses, reserves and impairments, net	(3		)	1			(20		)
	7,512			7,437			7,055
Operating Income	1,279			1,421			1,470
Other (Income) and Deductions
Interest expense	440			488			543
Interest income	(10		)	(10		)	(12		)
Other income	(173		)	(117		)	(78		)
Other expenses	62			69			55
	319			430			508
Income Before Income Taxes	960			991			962
Income Tax Expense	286			268			315
Income from Continuing Operations	674			723			647
Loss from Discontinued Operations, net of tax	(56		)	(3		)	(8		)
Net Income	618			720			639
Less: Net Income Attributable to Noncontrolling Interest	8			9			9
Net Income Attributable to DTE Energy Company	$	610		$	711		$	630
Basic Earnings per Common Share
Income from continuing operations	$	3.89		$	4.21		$	3.79
Loss from discontinued operations, net of tax	(0.33		)	(0.02		)	(0.04		)
Total	$	3.56		$	4.19		$	3.75
Diluted Earnings per Common Share
Income from continuing operations	$	3.88		$	4.20		$	3.78
Loss from discontinued operations, net of tax	(0.33		)	(0.02		)	(0.04		)
Total	$	3.55		$	4.18		$	3.74
Weighted Average Common Shares Outstanding
Basic	171			169			168
Diluted	172			170			169
Dividends Declared per Common Share	$	2.42		$	2.32		$	2.18

See Notes to Consolidated Financial Statements

51

DTE Energy Company

Consolidated Statements of Comprehensive Income

	2012			2011			2010
	(In millions)
Net income	$	618		$	720		$	639
Other comprehensive income (loss), net of tax:
Benefit obligations:
Benefit obligations, net of taxes of $(1), $(5) and $3	(2		)	(9		)	5
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $—, $— and $5	—			—			10
	(2		)	(9		)	15
Net unrealized gains on derivatives:
Gains during the period, net of taxes of $—, $— and $1	—			—			1
Amounts reclassified to income, net of taxes of $—, $— and $1	—			—			1
	—			—			2
Net unrealized gains (losses) on investments:
Gains (losses) during the period, net of taxes of $1, $— and $(6)	1			—			(10		)
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $—, $— and $(5)	—			—			(10		)
	1			—			(20		)
Foreign currency translation, net of taxes of $—, $— and $—	1			—			1
Other comprehensive income	—			(9		)	(2		)
Comprehensive income	618			711			637
Less comprehensive income attributable to noncontrolling interests	8			9			9
Comprehensive income attributable to DTE Energy Company	$	610		$	702		$	628

See Notes to Consolidated Financial Statements

52

DTE Energy Company

Consolidated Statements of Financial Position

	December 31
	2012			2011
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	65		$	68
Restricted cash, principally Securitization	122			147
Accounts receivable (less allowance for doubtful accounts of $62 and $162, respectively)
Customer	1,336			1,317
Other	126			90
Inventories
Fuel and gas	527			572
Materials and supplies	234			219
Deferred income taxes	21			51
Derivative assets	108			222
Regulatory assets	182			314
Other	194			196
	2,915			3,196
Investments
Nuclear decommissioning trust funds	1,037			937
Other	554			525
	1,591			1,462
Property
Property, plant and equipment	23,631			22,541
Less accumulated depreciation, depletion and amortization	(8,947		)	(8,795		)
	14,684			13,746
Other Assets
Goodwill	2,018			2,020
Regulatory assets	4,235			4,539
Securitized regulatory assets	413			577
Intangible assets	135			73
Notes receivable	112			123
Derivative assets	39			74
Other	197			199
	7,149			7,605
Total Assets	$	26,339		$	26,009

See Notes to Consolidated Financial Statements

53

DTE Energy Company

Consolidated Statements of Financial Position — (Continued)

	December 31
	2012			2011
	(In millions, except shares)
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	848		$	782
Accrued interest	93			95
Dividends payable	107			99
Short-term borrowings	240			419
Current portion long-term debt, including capital leases	817			526
Derivative liabilities	125			158
Other	538			549
	2,768			2,628
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	6,220			6,405
Securitization bonds	302			479
Junior subordinated debentures	480			280
Capital lease obligations	12			23
	7,014			7,187
Other Liabilities
Deferred income taxes	3,191			3,116
Regulatory liabilities	1,031			1,019
Asset retirement obligations	1,719			1,591
Unamortized investment tax credit	56			65
Derivative liabilities	26			89
Accrued pension liability	1,498			1,298
Accrued postretirement liability	1,160			1,484
Nuclear decommissioning	159			148
Other	306			331
	9,146			9,141
Commitments and Contingencies (Notes 11 and 19)
Equity
Common stock, without par value, 400,000,000 shares authorized, 172,351,680 and 169,247,282 shares issued and outstanding, respectively	3,587			3,417
Retained earnings	3,944			3,750
Accumulated other comprehensive loss	(158		)	(158		)
Total DTE Energy Company Equity	7,373			7,009
Noncontrolling interests	38			44
Total Equity	7,411			7,053
Total Liabilities and Equity	$	26,339		$	26,009

See Notes to Consolidated Financial Statements

54

DTE Energy Company

Consolidated Statements of Cash Flows

	Year Ended December 31
	2012			2011			2010
	(In millions)
Operating Activities
Net income	$	618		$	720		$	639
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	1,018			995			1,027
Deferred income taxes	47			220			457
Loss on sale of non-utility business	83			—			—
Asset (gains) and losses, reserves and impairments, net	1			(21		)	(5		)
Changes in assets and liabilities, exclusive of changes shown separately (Note 22)	442			94			(293		)
Net cash from operating activities	2,209			2,008			1,825
Investing Activities
Plant and equipment expenditures — utility	(1,451		)	(1,382		)	(1,011		)
Plant and equipment expenditures — non-utility	(369		)	(102		)	(88		)
Proceeds from sale of non-utility business	255			—			—
Proceeds from sale of assets	38			18			56
Restricted cash for debt redemption, principally Securitization	2			(5		)	(32		)
Acquisition, net of cash acquired	(198		)	—			—
Proceeds from sale of nuclear decommissioning trust fund assets	97			80			377
Investment in nuclear decommissioning trust funds	(102		)	(97		)	(410		)
Consolidation of VIEs	—			—			19
Investment in Millennium Pipeline Project	—			(3		)	(49		)
Other	(41		)	(69		)	(88		)
Net cash used for investing activities	(1,769		)	(1,560		)	(1,226		)
Financing Activities
Issuance of long-term debt	759			1,179			614
Redemption of long-term debt	(639		)	(1,455		)	(663		)
Short-term borrowings, net	(179		)	269			(177		)
Issuance of common stock	39			—			36
Repurchase of common stock	—			(18		)	—
Dividends on common stock	(407		)	(389		)	(360		)
Other	(16		)	(31		)	(36		)
Net cash used for financing activities	(443		)	(445		)	(586		)
Net Increase (Decrease) in Cash and Cash Equivalents	(3		)	3			13
Cash and Cash Equivalents at Beginning of Period	68			65			52
Cash and Cash Equivalents at End of Period	$	65		$	68		$	65

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, 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
Net Income	—		—			610			—			8			618
Dividends declared on common stock	—		—			(414		)	—			—			(414		)
Issuance of common stock	684		39			—			—			—			39
Contribution of common stock to pension plan	1,335		80			—			—			—			80
Foreign currency translation, net of tax	—		—			—			1			—			1
Benefit obligations, net of tax	—		—			—			(2		)	—			(2		)
Net change in unrealized losses on investments, net of tax	—		—			—			1			—			1
Stock-based compensation, distributions to noncontrolling interests and other	1,086		51			(2		)	—			(14		)	35
Balance, December 31, 2012	172,352		$	3,587		$	3,944		$	(158	)	$	38		$	7,411

See Notes to Consolidated Financial Statements

56

DTE Energy Company

Notes to Consolidated Financial Statements

NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION

Corporate Structure

DTE Energy owns the following businesses:

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

• DTE Gas, 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) power and industrial projects; and 3) energy marketing and trading operations.

DTE Electric and DTE Gas are regulated by the MPSC. Certain activities of DTE Electric and DTE Gas, 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.

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, which includes arrangements related to entities acquired in 2012. See Note 6. 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.

57

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, 2012, the carrying amount of assets and liabilities in the Consolidated Statements 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, DTE Electric 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. DTE Electric performs servicing activities including billing and collecting surcharge revenue for Securitization. This entity is a VIE, and is consolidated by the Company.

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, 2012 and December 31, 2011. Amounts at December 31, 2012 and 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, 2012								December 31, 2011
	Securitization		Other		Total		Restricted Amounts		Securitization		Other		Total		Restricted Amounts
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	10	$	10	$	8	$	—	$	25	$	25	$	—
Restricted cash	102		7		109		109		107		7		114		114
Accounts receivable	34		7		41		38		34		17		51		36
Inventories	—		141		141		3		—		183		183		—
Other current assets	—		1		1		1		—		1		1		—
Property, plant and equipment	—		93		93		49		—		73		73		23
Securitized regulatory assets	413		—		413		413		577		—		577		577
Other assets	7		11		18		18		10		6		16		16
	$	556	$	270	$	826	$	639	$	728	$	312	$	1,040	$	766
LIABILITIES
Accounts payable and accrued current liabilities	$	11	$	14	$	25	$	12	$	14	$	24	$	38	$	14
Current portion long-term debt, including capital leases	177		8		185		185		164		7		171		171
Other current liabilities	50		4		54		53		55		—		55		55
Mortgage bonds, notes and other	—		25		25		25		—		30		30		30
Securitization bonds	302		—		302		302		479		—		479		479
Capital lease obligations	—		11		11		11		—		14		14		14
Other long-term liabilities	7		2		9		8		7		2		9		8
	$	547	$	64	$	611	$	596	$	719	$	77	$	796	$	771

58

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Amounts for non-consolidated VIEs as of December 31, 2012 and December 31, 2011 are as follows:

	December 31, 2012		December 31, 2011
	(In millions)
Other investments	$	130	$	117
Notes receivable	6		7

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. DTE Electric and DTE Gas record revenues for electricity and gas provided but unbilled at the end of each month. Rates for DTE Electric and DTE Gas 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 subject to reconciliation and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are recorded on the Consolidated Statements of Financial Position and are recovered or returned to customers through adjustments to the billing factors.

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. See Note 4 for discussion of derivative contracts.

Accounting for ISO Transactions

DTE Electric 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. DTE Electric 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 DTE Electric records net purchases in Fuel, purchased power and gas and net sales in Operating revenues on the Consolidated Statements of Operations. DTE Electric 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.

DTE Electric 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, 2012 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.

59

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

	Year Ended December 31, 2012
	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 January 1, 2012	$	(4	)	$	(30	)	$	(125	)	$	1	$	(158	)
Current period change, net of tax	—			1			(2		)	1		—
Ending balances December 31, 2012	$	(4	)	$	(29	)	$	(127	)	$	2	$	(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 DTE Electric and DTE Gas 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. The time period for write-off was changed in 2012 from 365 days to 150 days 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 $686 million and $597 million are included in customer accounts receivable at December 31, 2012 and 2011, 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.

60

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Natural gas inventory of $37 million and $52 million as of December 31, 2012 and 2011, respectively, at DTE Gas is determined using the last-in, first-out (LIFO) method. At December 31, 2012, the replacement cost of gas remaining in storage exceeded the LIFO cost by $113 million. At December 31, 2011, the replacement cost of gas remaining in storage exceeded the LIFO cost by $95 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 is charged to accumulated depreciation. Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2.

Utility property at DTE Electric and DTE Gas 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 the straight-line and units of production methods.

Depreciation, depletion and amortization expense also includes the amortization of certain regulatory assets.

Approximately $12 million and $23 million of expenses related to Fermi 2 refueling outages were accrued at December 31, 2012 and December 31, 2011, respectively. Amounts are accrued on a pro-rata basis, generally 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 Statements of Operations and is recorded 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 discounted 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, 2012 and 2011:

	2012		2011
	(In millions)
Emission allowances	$	6	$	10
Renewable energy credits	44		39
Contract intangible assets	139		65
	189		114
Less accumulated amortization	34		28
Intangible assets, net	155		$	86
Less current intangible assets	20		$	13
	$	135	$	73

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 28 years. Intangible assets amortization expense was $6 million in 2012, $5 million in 2011 and $4 million in 2010. Amortization expense of intangible assets is estimated to be $13 million annually for 2013 through 2017.

61

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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, 2012, the total cash collateral received, net of cash collateral posted, was $20 million. As of December 31, 2011, the total cash collateral posted, net of cash collateral received, was $71 million. There was no collateral related to unrealized positions to net against derivative assets and liabilities as of December 31, 2012. At December 31, 2011, derivative assets and derivative liabilities were shown net of collateral of $19 million and $74 million, respectively. The Company recorded cash collateral paid of $4 million and cash collateral received of $24 million not related to unrealized derivative positions as of December 31, 2012. The Company recorded cash collateral paid of $16 million not related to unrealized derivative positions, as of December 31, 2011. 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.

DTE Energy Foundation

Charitable contributions to the DTE Energy Foundation were $21 million, $21 million, and $14 million for the years ended December 31, 2012, 2011 and 2010, respectively. The DTE Energy Foundation is a non-consolidated not-for-profit private foundation, the purpose of which is to contribute and assist charitable organizations and does not serve a direct business or political purpose of DTE.

62

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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
10	Asset Retirement Obligations
11	Regulatory Matters
12	Income Taxes
20	Retirement Benefits and Trusteed Assets
21	Stock-based Compensation

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, 2012 and December 31, 2011. 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.

63

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, 2012 and 2011:

	December 31, 2012															December 31, 2011
	Level 1			Level 2			Level 3			Netting (a)			Net Balance			Level 1			Level 2			Level 3			Netting (a)			Net Balance
	(In millions)
Assets:
Cash equivalents (b)	$	—		$	123		$	—		$	—		$	123		$	—		$	140		$	—		$	—		$	140
Nuclear decommissioning trusts	694			343			—			—			1,037			577			360			—			—			937
Other investments (c) (d)	66			44			—			—			110			57			38			—			—			95
Derivative assets:
Foreign currency exchange contracts	—			—			—			—			—			—			3			—			(3		)	—
Commodity Contracts:
Natural Gas	555			66			24			(605		)	40			1,926			78			20			(1,991		)	33
Electricity	—			226			134			(258		)	102			—			523			224			(490		)	257
Other	6			3			2			(6		)	5			23			2			6			(25		)	6
Total derivative assets	561			295			160			(869		)	147			1,949			606			250			(2,509		)	296
Total	$	1,321		$	805		$	160		$	(869	)	$	1,417		$	2,583		$	1,144		$	250		$	(2,509	)	$	1,468
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	—		$	—		$	—		$	—		$	—		$	(5	)	$	—		$	3		$	(2	)
Interest rate contracts	—			(1		)	—			—			(1		)	—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(526		)	(73		)	(62		)	605			(56		)	(1,940		)	(126		)	(14		)	1,976			(104		)
Electricity	—			(240		)	(111		)	258			(93		)	—			(513		)	(192		)	565			(140		)
Other	(6		)	(1		)	—			6			(1		)	(19		)	(1		)	—			20			—
Total derivative liabilities	(532		)	(315		)	(173		)	869			(151		)	(1,959		)	(646		)	(206		)	2,564			(247		)
Total	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)	$	(1,959	)	$	(646	)	$	(206	)	$	2,564		$	(247	)
Net Assets at the end of the period	$	789		$	490		$	(13	)	$	—		$	1,266		$	624		$	498		$	44		$	55		$	1,221
Assets:
Current	$	493		$	372		$	120		$	(754	)	$	231		$	1,571		$	660		$	181		$	(2,050	)	$	362
Noncurrent (e)	828			433			40			(115		)	1,186			1,012			484			69			(459		)	1,106
Total Assets	$	1,321		$	805		$	160		$	(869	)	$	1,417		$	2,583		$	1,144		$	250		$	(2,509	)	$	1,468
Liabilities:
Current	$	(466	)	$	(269	)	$	(144	)	$	754		$	(125	)	$	(1,603	)	$	(527	)	$	(152	)	$	2,124		$	(158	)
Noncurrent	(66		)	(46		)	(29		)	115			(26		)	(356		)	(119		)	(54		)	440			(89		)
Total Liabilities	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)	$	(1,959	)	$	(646	)	$	(206	)	$	2,564		$	(247	)
Net Assets at the end of the period	$	789		$	490		$	(13	)	$	—		$	1,266		$	624		$	498		$	44		$	55		$	1,221

_______________________________________

(a) 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.

(b) At December 31, 2012 available for sale securities of $123 million included $109 million and $14 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively. At December 31, 2011 available for sale securities of $140 million, included $124 million and $16 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively.

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

(d) Available for sale equity securities of $5 million at December 31, 2012 and December 31, 2011 are included in Other investments on the Consolidated Statements of Financial Position, respectively.

(e) Includes $110 million and $95 million of Other investments that are included in the Consolidated Statements of Financial Position in Other investments at December 31, 2012 and December 31, 2011, respectively.

Cash Equivalents

Cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value table are comprised of short-term investments and money market funds. The fair values of the shares in these investments are based upon observable market prices for similar securities and, therefore, have been categorized as Level 2 in the fair value hierarchy.

64

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. The Company has established a Risk Management Committee whose responsibilities include directly or indirectly ensuring all valuation methods are applied in accordance with predefined policies. The development and maintenance of our forward price curves has been assigned to our Risk Management Department, which is separate and distinct from the trading functions within the Company.

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, 2012 and 2011:

	Year Ended December 31, 2012												Year Ended December 31, 2011
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets as of January 1	$	6		$	32		$	6		$	44		$	1		$	54		$	4		$	59
Transfers into Level 3	1			—			—			1			—			4			—			4
Transfers out of Level 3	—			—			—			—			1			(25		)	—			(24		)
Total gains (losses):
Included in earnings	(41		)	101			—			60			7			77			3			87
Recorded in regulatory assets/liabilities	—			—			15			15			—			—			2			2
Purchases, issuances and settlements:
Purchases	—			2			—			2			—			3			—			3
Settlements	(4		)	(112		)	(19		)	(135		)	(3		)	(81		)	(3		)	(87		)
Net Assets (Liabilities) as of December 31	$	(38	)	$	23		$	2		$	(13	)	$	6		$	32		$	6		$	44
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, 2012 and 2011and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(33	)	$	91		$	—		$	58		$	8		$	65		$	2		$	75

Derivatives are transferred between levels primarily due to changes in the source data used to construct price curves as a result of changes in market liquidity. Transfers in and transfers out are reflected as if they had occurred at the beginning of the

65

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

period. The following table shows transfers between the levels of the fair value hierarchy for the years ended December 31, 2012 and 2011:

	Year Ended December 31, 2012						Year Ended December 31, 2011
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
	(In millions)
Transfers into Level 1 from	N/A		$	—	$	—	N/A		$	—	$	—
Transfers into Level 2 from	$	—	N/A		—		$	—	N/A		24
Transfers into Level 3 from	—		1		N/A		—		4		N/A

The following table presents the unobservable inputs related to Level 3 assets and liabilities as of December 31, 2012:

	December 31, 2012
Commodity Contracts	Derivative Assets		Derivative Liabilities			Valuation Techniques	Unobservable Input	Range							Weighted Average
(In millions)
Natural Gas	$	24	$	(62	)	Discounted Cash Flow	Forward basis price (per MMBtu)	$	(0.63	)	—	$	1.95	/MMBtu	$	0.03	/MMBtu
Electricity	134		(111		)	Discounted Cash Flow	Forward basis price (per MWh)	$	(2	)	—	$	16	/MWh	$	3	/MWh

The unobservable inputs used in the fair value measurement of the electricity and natural gas commodity types consists of inputs that are less observable due in part to lack of available broker quotes, supported by little, if any, market activity at the measurement date or are based on internally developed models. Certain forward market and/or basis prices (i.e., the difference in pricing between two locations) that were included in the valuation of natural gas and electricity contracts were deemed unobservable.

The inputs listed above would have a direct impact on the fair values of the above security types if they were adjusted. A significant increase (decrease) in the forward market or basis price would result in a higher (lower) fair value for long positions, with offsetting impacts to short positions.

Fair Value of Financial Instruments

The fair value of financial instruments included in the table below is determined by using quoted market prices when available. When quoted prices are not available, pricing services may be used to determine the fair value with reference to observable interest rate indexes. DTE Energy has obtained an understanding of how the fair values are derived. DTE Energy also selectively corroborates the fair value of its transactions by comparison of market-based price sources. Discounted cash flow analyses based upon estimated current borrowing rates are also used to determine fair value when quoted market prices are not available. The fair values of notes receivable, excluding capital leases, are estimated using discounted cash flow techniques that incorporate market interest rates as well assumptions about the remaining life of the loans and credit risk. Depending on the information available, other valuation techniques may be used that rely on internal assumptions and models. Valuation policies and procedures are determined by DTE Energy's Treasury Department which reports to the Company's Vice President and Treasurer.

The following table presents the carrying amount and fair value of financial instruments as of December 31, 2012 and 2011:

	December 31, 2012								December 31, 2011
	Carrying		Fair Value						Carrying		Fair
	Amount		Level 1		Level 2		Level 3		Amount		Value
	(In millions)
Notes receivable, excluding capital leases	$	39	$	—	$	—	$	39	$	48	$	48
Dividends payable	107		107		—		—		99		99
Short-term borrowings	240		—		240		—		419		419
Long-term debt	7,813		507		7,453		933		7,682		8,757

66

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

See Note 4 for further fair value information on financial and derivative instruments.

Nuclear Decommissioning Trust Funds

DTE Electric 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. DTE Electric is continuing to fund FERC jurisdictional amounts for decommissioning even though explicit provisions are not included in FERC rates. See Note 10.

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

	December 31 2012		December 31 2011
	(In millions)
Fermi 2	$	1,021	$	915
Fermi 1	3		3
Low level radioactive waste	13		19
Total	$	1,037	$	937

At December 31, 2012, 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. 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. The debt securities at both December 31, 2012 and December 31, 2011 had an average maturity of approximately 6 and 7 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
	2012			2011			2010
	(In millions)
Realized gains	$	37		$	46		$	192
Realized losses	$	(31	)	$	(38	)	$	(83	)
Proceeds from sales of securities	$	97		$	80		$	377

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:

	December 31, 2012				December 31, 2011
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
	(In millions)
Equity securities	$	631	$	122	$	533	$	80
Debt securities	399		27		385		22
Cash and cash equivalents	7		—		19		—
	$	1,037	$	149	$	937	$	102

Securities held in the nuclear decommissioning trust funds are classified as available-for-sale. As DTE Electric 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. DTE Electric recognized $44 million and $67 million of unrealized losses as Regulatory assets at December 31, 2012 and 2011, respectively. Since the decommissioning of Fermi 1 is funded by DTE Electric 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 2012, 2011 and 2010 for Fermi 1.

67

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Available-for-sale Securities

At December 31, 2012 and 2011, these securities are comprised primarily of money-market and equity securities. During the year ended December 31, 2012 and December 31, 2011no amounts of unrealized losses on available for sale securities were reclassified out of other comprehensive income into net income for the periods. Gains related to trading securities held at December 31, 2012, 2011, and 2010 were $9 million, $3 million and $7 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. 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, pipeline transportation contracts, renewable energy credits and storage assets.

Electric — DTE Electric generates, purchases, distributes and sells electricity. DTE Electric uses forward energy 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 — DTE Gas purchases, stores, transports, distributes and sells natural gas and sells storage and transportation capacity. DTE Gas has fixed-priced contracts for portions of its expected gas supply requirements through 2015. Substantially all of these contracts meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. DTE Gas may also sell forward transportation and storage capacity contracts. Forward transportation and storage contracts are generally 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.

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.

Energy Trading — Commodity Price Risk — Energy Trading markets and trades electricity, coal, 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 natural gas and power purchase and sale contracts and natural gas transportation contracts. The Company enters into these contracts to mitigate price volatility with respect to

68

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 2013, 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, 2012 and 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 gas purchases and sales, gas transportation and storage capacity. Changes in the value of derivatives in this category typically 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 DTE Electric related to FTRs. Changes in the value of derivative contracts at DTE Electric 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.

69

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The following tables present the fair value of derivative instruments as of December 31, 2012 and 2011:

	December 31, 2012					December 31, 2011
	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)	$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	—	$	—		$	3	$	(5	)
Commodity Contracts:
Natural Gas	645		(661		)	2,024		(2,080		)
Electricity	360		(351		)	747		(705		)
Other	11		(7		)	31		(20		)
Total derivatives not designated as hedging instruments:	$	1,016	$	(1,019	)	$	2,805	$	(2,810	)
Total derivatives:
Current	$	862	$	(879	)	$	2,272	$	(2,282	)
Noncurrent	154		(141		)	533		(529		)
Total derivatives	$	1,016	$	(1,020	)	$	2,805	$	(2,811	)

	December 31, 2012												December 31, 2011
	Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent			Current			Noncurrent			Current			Noncurrent
	(In millions)
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	862		$	154		$	(879	)	$	(141	)	$	2,272		$	533		$	(2,282	)	$	(529	)
Counterparty netting	(754		)	(115		)	754			115			(2,050		)	(440		)	2,050			440
Collateral adjustment	—			—			—			—			—			(19		)	74			—
Total derivatives as reported	$	108		$	39		$	(125	)	$	(26	)	$	222		$	74		$	(158	)	$	(89	)

The effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for years ended December 31, 2012 and 2011 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		2012			2011
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	—		$	(2	)
Commodity Contracts:
Natural Gas	Operating Revenue	(29		)	58
Natural Gas	Fuel, purchased power and gas	25			(21		)
Electricity	Operating Revenue	64			115
Other	Operating Revenue	5			9
Total		$	65		$	159

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, and financial non-trading commodity derivatives, are accounted for using the mark-to-market method with unrealized and realized gains and losses recorded in Operating revenues. Non-trading physical commodity sale and purchase derivative contracts are generally accounted for using the mark-to-market method with unrealized and realized gains and losses for sales recorded in Operating revenue and purchases recorded in Fuel, purchased power and gas.

70

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The effects of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position were $15 million in unrealized gains related to FTRs recognized in Regulatory liabilities for the year ended December 31, 2012, and $3 million in unrealized gains related to FTRs recognized in Regulatory liabilities, for the year ended December 31, 2011.

The following represents the cumulative gross volume of derivative contracts outstanding as of December 31, 2012:

Commodity	Number of Units
Natural Gas (MMBtu)	663,194,602
Electricity (MWh)	48,524,412
Foreign Currency Exchange ($ CAD)	10,838,396
FTR (MWh)	11,077,483

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, 2012, 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 $326 million.

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, 2012 and 2011 is as follows:

	2012			2011
	(In millions)
Balance as of January 1	$	2,020		$	2,020
Goodwill attributable to sale of Unconventional Gas Production business	(2		)	—
Balance at December 31	$	2,018		$	2,020

NOTE 6 — ACQUISITION

In July 2012, the Company executed an agreement to purchase a portfolio of fourteen on-site energy projects, primarily located in the Midwest, from subsidiaries of Duke Energy Corporation and GDF Suez Energy North America, Inc. This acquisition provides a growth opportunity for the Company's Power and Industrial Projects segment that will leverage its extensive energy-related operating experience and project management capabilities.

Closing for all of the entities occurred in the fourth quarter 2012. The purchase of equity interests range from 46 percent to 100 percent of the project companies for a total purchase price of approximately $294 million, which consists of $220 million paid in cash and assumption of approximately $74 million of debt. The debt assumed relates to two project companies which have been deemed variable interest entities. DTE, however, is not the primary beneficiary and thus the VIEs' assets and liabilities are not included in the Company's Consolidated Statements of Financial Position. Therefore, the assumed debt is not included in the purchase price allocation table below. There is no exposure to loss related to the debt assumed as the customer of the project companies is obligated to pay the loans in the event of default or termination. See Note 1.

The Company has completed its valuation analysis and calculations in sufficient detail necessary to arrive at the fair value of the project company assets acquired and liabilities assumed, along with the related allocation to intangible assets.

The allocation of the total consideration transferred in the acquisition to the assets acquired and liabilities assumed includes adjustments for the fair value of existing contracts and agreements and property, plant and equipment. The fair value of the assets acquired and liabilities assumed have been determined based on the accounting guidance for fair value measurements in

71

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

accordance with ASC 805, “Business Combinations.” The following is the Company's assignment as of the closing date of the consideration:

	(In millions)
Cash	$	22
Accounts receivable	14
Other current assets	8
Property, plant and equipment	100
Intangible assets	75
Other noncurrent assets	9
Current liabilities	(7		)
Non-controlling interest	(1		)
Total purchase price	$	220

The Company did not record any goodwill due to the acquisition.

The intangible assets recorded as a result of the acquisition pertain to existing contracts and agreements, which were valued at approximately $75 million as of the closing date. The fair value of the intangible assets acquired was estimated by applying the income approach. The income approach is based upon discounted projected future cash flows attributable to the existing contracts and agreements. The fair value measurement is based on significant unobservable inputs, including management estimates and assumptions, and thus represents a Level 3 measurement, pursuant to the applicable accounting guidance. Key estimates and inputs include revenue and expense projections and discount rates based on the risks associated with the projects. The intangible assets are amortized on a straight line basis over a weighted-average amortization period of approximately eight years.

The Company's 2012 results of operations include revenue of $30 million and net income of $2 million associated with the acquired project companies for the approximate three-month period following the closing date. The pro forma results of operations have not been presented for DTE Energy because the effects of the acquisition were not material to our consolidated results of operations.

NOTE 7 — DISCONTINUED OPERATIONS

Sale of Unconventional Gas Production Business

In December 2012, the Company sold its 100% equity interest in its Unconventional Gas Production business which consisted of gas and oil production assets in the western Barnett and Marble Falls shale areas of Texas. The properties in the sale included all of the reserves on approximately 88,000 net acres near Dallas, Texas. The sale resulted in gross proceeds of approximately $255 million, which resulted in a pre-tax loss of approximately $83 million ($55 million after tax). The sale price is subject to customary purchase price adjustments that will be recognized in the first half of 2013.

The activity of the discontinued Unconventional Gas Production business is shown below. The amounts exclude general corporate overhead costs, and related tax effects, and no portion of corporate interest costs were allocated to discontinued operations.

72

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

	Year Ended December 31
	2012			2011			2010
				(In millions)
Operating Revenues	$	55		$	39		$	32
Operation and Maintenance	24			16			11
Depreciation, Depletion and Amortization	23			18			15
Taxes Other than Income	4			3			2
Asset (Gains) and Losses, Net	83			—			10
	134			37			38
Operating Income	(79		)	2			(6		)
Other (Income) and Deductions	6			6			6
Loss Before Income Taxes	(85		)	(4		)	(12		)
Income Tax Benefit	(29		)	(1		)	(4		)
Net Loss	$	(56	)	$	(3	)	$	(8	)

NOTE 8 — PROPERTY, PLANT AND EQUIPMENT

Summary of property by classification as of December 31:

	2012			2011
Property, Plant and Equipment	(In millions)
Electric
Generation	$	10,383		$	9,785
Distribution	7,306			7,003
Total Electric	17,689			16,788
Gas
Distribution	2,735			2,561
Storage	434			406
Other	852			902
Total Gas	4,021			3,869
Non-utility and other	1,921			1,884
Total	23,631			22,541
Less Accumulated Depreciation, Depletion and Amortization
Electric
Generation	(3,880		)	(3,946		)
Distribution	(2,837		)	(2,580		)
Total Electric	(6,717		)	(6,526		)
Gas
Distribution	(1,075		)	(1,041		)
Storage	(133		)	(127		)
Other	(363		)	(413		)
Total Gas	(1,571		)	(1,581		)
Non-utility and other	(659		)	(688		)
Total	(8,947		)	(8,795		)
Net Property, Plant and Equipment	$	14,684		$	13,746

The Allowance for Funds used During Construction (AFUDC) capitalized was approximately $20 million and $10 million during 2012 and 2011, respectively.

The composite depreciation rate for DTE Electric was approximately 3.3% in 2012, 2011 and 2010. The composite depreciation rate for DTE Gas was 2.4% in 2012, 2.3% in 2011 and 2.5% in 2010.

73

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The average estimated useful life for each major class of utility property, plant and equipment as of December 31, 2012 follows:

	Estimated Useful Lives in Years
Utility	Generation	Distribution	Storage
Electric	40	41	N/A
Gas	N/A	50	53

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 15 years.

Capitalized software costs amortization expense was $75 million in 2012 and $65 million in 2011 and 2010. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2012 were $561 million and $295 million, respectively. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2011 were $623 million and $300 million, respectively. Amortization expense of capitalized software costs is estimated to be approximately $46 million annually for 2013 through 2017.

Gross property under capital leases was $32 million and $57 million at December 31, 2012 and December 31, 2011, respectively. Accumulated amortization of property under capital leases was $3 million and $34 million at December 31, 2012 and December 31, 2011, respectively.

NOTE 9 — JOINTLY OWNED UTILITY PLANT

DTE Electric has joint ownership interest in two power plants, Belle River and Ludington Hydroelectric Pumped Storage. DTE Electric’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, 2012 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	(a)			49		%
Investment (in millions)	$	1,661		$	199
Accumulated depreciation (in millions)	$	953		$	164

_______________________________________

(a) DTE Electric'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.

74

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 10 — ASSET RETIREMENT OBLIGATIONS

The Company has a legal retirement obligation for the decommissioning costs for its Fermi 1 and Fermi 2 nuclear plants, dismantlement of facilities located on leased property and various other operations. The Company has conditional retirement obligations for gas pipelines, asbestos and PCB removal at certain of its power plants and various distribution equipment. 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.

If a reasonable estimate of fair value cannot be made in the period in which the retirement obligation is incurred, such as for assets with indeterminate lives, the liability is recognized when a reasonable estimate of fair value can be made. Natural gas storage system assets, substations, manholes and certain other distribution assets have an indeterminate life. Therefore, no liability has been recorded for these assets.

A reconciliation of the asset retirement obligations for 2012 follows:

	(In millions)
Asset retirement obligations at December 31, 2011	$	1,593
Accretion	100
Liabilities incurred	27
Liabilities settled	(11		)
Revision in estimated cash flows	10
Asset retirement obligations at December 31, 2012	1,719

In 2001, DTE Electric 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, DTE Electric accrued an additional $19 million with respect to the decommissioning of Fermi 1. Management has suspended decommissioning activities and placed 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, in 2011, based on updated studies revising the timing and estimate of cash flows, a reduction of approximately $20 million was made to the DTE Electric 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.

In October 2011, the MPSC approved DTE Electric'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. DTE Electric 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 in 2011. It is estimated that the cost of decommissioning Fermi 2 is $1.5 billion in 2012 dollars and $10 billion in 2045 dollars, using a 6% inflation rate. Approximately $1.5 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. DTE Electric 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 returning the site to greenfield. This removal and greenfielding is not considered a legal liability. Therefore, it is not included in the asset retirement obligation, but is reflected as the nuclear

75

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

decommissioning liability. The decommissioning of Fermi 1 is funded by DTE Electric. Contributions to the Fermi 1 trust are discretionary. See Note 3 for additional discussion of Nuclear Decommissioning Trust Fund Assets.

NOTE 11 — REGULATORY MATTERS

Regulation

DTE Electric and DTE Gas 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. DTE Electric 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.

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.

Regulatory Assets and Liabilities

DTE Electric and DTE Gas 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:

	2012			2011
	(In millions)
Assets
Recoverable pension and postretirement costs:
Pension	$	2,420		$	2,208
Postretirement costs	426			778
Asset retirement obligation	424			420
Recoverable Michigan income taxes	304			324
Recoverable income taxes related to securitized regulatory assets	226			316
Cost to achieve Performance Excellence Process	96			116
Accrued PSCR/GCR revenue	87			147
Other recoverable income taxes	76			81
Choice incentive mechanism	66			166
Unamortized loss on reacquired debt	63			64
Deferred environmental costs	58			49
Recoverable restoration expense	49			58
Recoverable revenue decoupling	28			18
Enterprise Business Systems costs	16			18
Other	78			90
	4,417			4,853
Less amount included in current assets	(182		)	(314		)
	$	4,235		$	4,539
Securitized regulatory assets	$	413		$	577

76

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

	2012			2011
	(In millions)
Liabilities
Asset removal costs	$	439		$	419
Renewable energy	230			192
Refundable revenue decoupling/deferred gain	127			127
Negative pension offset	105			120
Refundable income taxes	56			66
Over recovery of Securitization	54			53
Refundable uncollectible expense	37			31
Energy Optimization	34			34
Accrued PSCR/GCR refund	16			26
Fermi 2 refueling outage	12			23
Low Income Energy Efficiency Fund	—			26
Other	10			9
	1,120			1,126
Less amount included in current liabilities	(89		)	(107		)
	$	1,031		$	1,019

As noted below, certain 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 DTE Electric or DTE Gas’s rate base, thereby providing a return on invested costs (except as noted). Certain other regulatory assets are not included in rate base but accrue recoverable carrying charges until surcharges to collect the assets are billed. 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. DTE Electric and DTE Gas 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. (a)

• 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. (a)

• 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. (a)

• 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. (a)

• 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.

77

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

• Accrued PSCR/GCR revenue — Receivable for the temporary under-recovery of and a return on fuel and purchased power costs incurred by DTE Electric which are recoverable through the PSCR mechanism and temporary under-recovery of and return on gas costs incurred by DTE Gas which are recoverable through the GCR mechanism.

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

• Choice incentive mechanism (CIM) — DTE Electric 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 DTE Electric.

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

• Deferred environmental costs — The MPSC approved the deferral of investigation and remediation costs associated with DTE Gas'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. (a)

• 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 DTE Electric.

• Recoverable revenue decoupling — Amounts recoverable from DTE Gas 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. The December 2012 order in DTE Gas' rate case requires the RDM be discontinued effective November 1, 2012. The order provides for a new RDM beginning in November 2013.

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

• 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.

_________________________________

(a) Regulatory assets not earning a return or accruing carrying charges.

LIABILITIES

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

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

• Refundable revenue decoupling / deferred gain — At December 31, 2011, amounts were accrued as refundable to DTE Electric 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. In 2012, the revenue decoupling liability was reversed and a new regulatory liability representing DTE Electric's obligation to refund the resulting gain was accrued. See further discussion below.

• Negative pension offset — DTE Gas’ 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 DTE Gas’ pension expense is positive in future years.

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

78

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

• Over recovery of Securitization — Over recovery of securitization bond expenses.

• Refundable uncollectible expense (UETM )— DTE Electric and DTE Gas 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 for DTE Electric in the October 20, 2011 MPSC rate case order and terminated for DTE Gas in the December 20, 2012 MPSC approval of the partial settlement agreement.

• Energy Optimization (EO) - Amounts collected in rates in excess of energy optimization expenditures.

• Accrued PSCR/GCR refund — Liability for the temporary over-recovery of and a return on power supply costs and transmission costs incurred by DTE Electric which are recoverable through the PSCR mechanism and temporary over-recovery of and a return on gas costs incurred by DTE Gas which are recoverable through the GCR mechanism.

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

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

2009 Electric Rate Case Filing - Court of Appeals Decision/Refundable Deferred Gain

On April 10, 2012, the Michigan Court of Appeals (COA) issued a decision relating to an appeal of the January 2010 MPSC order in DTE Electric's January 2009 rate case filing.

The COA found that the record of evidence in the 2009 rate case order was insufficient to support the MPSC's authorization to recover costs for the pilot advanced metering infrastructure (AMI) program and remanded this matter to the MPSC. The MPSC had approved $37 million of rate base related to the AMI program in the January 2010 order. DTE Electric is currently operating its AMI program pursuant to the MPSC's approval set forth in its October 20, 2011 order, which was not reviewed by or subject to the COA's April 10, 2012 decision. On November 28, 2012, DTE Electric filed the necessary data and evidence to the MPSC supporting the AMI program expenditures. DTE Electric's AMI program expenditures are $110 million as of December 31, 2012, net of Department of Energy matching grant funds of $60 million.

The COA affirmed the use of a number of tracking mechanisms (restoration, line clearance, uncollectibles expense and choice incentive) and the peak demand computations approved in the January 2010 order. The COA also determined that the MPSC only had statutory authority to implement a Revenue Decoupling Mechanism (RDM) for gas providers, but not for electric providers, thereby reversing the MPSC's decision to authorize an RDM for DTE Electric. DTE Electric had accrued a total of $127 million of RDM refund liabilities for the 2010 and 2011 RDM reconciliation periods. No party appealed the COA decision regarding the RDM determination.

On August 1, 2012, DTE Electric filed an application for approval of accounting authority to defer for future amortization the gain resulting from the reversal of the Company's $127 million regulatory liability associated with the operation of the RDM. On August 14, 2012, the MPSC dismissed DTE Electric's initial pilot RDM reconciliation cases. On September 25, 2012, the MPSC issued an order approving the Company's accounting application. As described in the accounting application, DTE Electric will amortize the new regulatory liability to income, at a monthly rate of approximately $10.6 million, beginning January 2014. It is currently anticipated that with this accounting treatment, along with other cost saving measures, DTE Electric will not need to increase base rates until 2015. If DTE Electric's base rates are increased prior to January 1, 2015, the Company will cease amortization and refund to customers the remaining unamortized balance of the new regulatory liability.

Energy Optimization (EO) Plans

The EO plan 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.

In May 2012, DTE Electric and DTE Gas both filed separate applications for approval of their respective reconciliations

79

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

of their 2011 EO plan expenses. On October 31, 2012, the MPSC approved DTE Electric's reconciliation and on November 16, 2012, the MPSC approved DTE Gas' reconciliation. The MPSC orders also approved performance incentive surcharges for DTE Electric of $8.4 million and for DTE Gas of $3.4 million to be applied to customer bills rendered on and after January 1, 2013.

In August 2012, Detroit Edison and MichCon filed amended EO plans with the MPSC. DTE Electric's EO plan application proposed the recovery of EO expenditures for the period 2013-2015 of $224 million and DTE Gas' EO plan application proposed the recovery of EO expenditures for the period 2013-2015 of $66 million. Both applications requested approval of surcharges to recover these costs.

DTE Electric Restoration Expense Tracker Mechanism (RETM) and Line Clearance Tracker (LCT) Reconciliation

In January 2012, DTE Electric 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, DTE Electric requested net recovery of approximately $44 million. An MPSC order is expected in the first quarter of 2013.

DTE Electric Uncollectible Expense True-Up Mechanism (UETM)

In February 2012, DTE Electric filed an application with the MPSC for approval of its UETM for 2011 requesting authority to refund approximately $9 million consisting of costs related to 2011 uncollectible expense. An MPSC order is expected in the first quarter of 2013.

DTE Electric Choice Incentive Mechanism (CIM)

In January 2012, DTE Electric 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. On January 17, 2013, the MPSC approved a settlement agreement authorizing the Company to recover $63 million, plus interest, from its customers through a surcharge to be implemented over a ten-month period beginning March 2013 through December 2013.

Power Supply Cost Recovery Proceedings

The PSCR process is designed to allow DTE Electric to recover all of its power supply costs if incurred under reasonable and prudent policies and practices. DTE Electric'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.

2011 PSCR Year -In March 2012, DTE Electric filed the 2011 PSCR reconciliation calculating a net under-recovery of $148 million that includes an under-recovery of $52.6 million for the 2010 PSCR year. In addition, the 2011 PSCR reconciliation includes an over-refund of $3.8 million for the 2011 refund of the self-implementation rate increase related to the 2009 electric rate case filing and a credit of $10.5 million related to the expiration of a wholesale power sales contract.

2013 Plan Year - In September 2012, DTE Electric filed its 2013 PSCR plan case seeking approval of a levelized PSCR factor of 4.74 mills/kWh above the amount included in base rates for all PSCR customers. The filing supports a total power supply expense forecast of $1.5 billion. The plan also includes approximately $81 million for the recovery of its projected 2012 PSCR under-recovery.

2012 Gas Rate Case Filing

DTE Gas filed a rate case on April 20, 2012 based on a projected test year for the twelve-month period ending October 31, 2013. The filing with the MPSC requested an increase in base rates of approximately $77 million that is required to recover higher costs associated with increased investments in plant, the impact of sales reductions due to customer losses and continuing conservation, and increasing operating costs, primarily pipeline integrity and leak remediation expenses. On October 24, 2012, DTE Gas filed notification with the MPSC indicating that it intended to self-implement $27 million of rate relief beginning in November 2012, suspend the RDM and terminate the monthly credit which was implemented to remove the Vulnerable Household Warmth Fund collections from rates. On December 20, 2012, the MPSC approved a partial settlement agreement and authorized the Company to increase its annual gas revenues by $19.9 million for service rendered on and after

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DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

January 1, 2013. A refund liability of approximately $1 million, representing the difference between the final ordered rate relief and the self- implemented revenue, was accrued as of December 31, 2012.

The case also included a proposal for an infrastructure recovery mechanism (IRM) designed to recover DTE Gas' projected costs related to its gas main renewal and meter move out programs. The approved settlement did not resolve the IRM which will continue to be litigated with an order expected by April 2013.

DTE Gas UETM

In March 2012, DTE Gas filed an application with the MPSC for approval of its UETM for 2011 requesting authority to refund approximately $7 million, consisting of a $19 million over-recovery related to 2011 uncollectible expense, partially offset by $12 million related to the 2010 UETM under-recovery. In September 2012, the MPSC approved a settlement agreement approving the net refund of $7 million and the implementation of credits and surcharges over a twelve-month period beginning in November 2012. The December 2012 order in DTE Gas' rate case requires the UETM be terminated effective November 1, 2012 and the reconciliation to be filed by March 31, 2013. DTE Gas accrued a refund obligation of approximately $20 million for the 2012 over-recovery.

DTE Gas Revenue Decoupling Mechanism (RDM)

In September 2011, DTE Gas filed an application with the MPSC for approval of its RDM reconciliation for the period July 1, 2010 through June 30, 2011. DTE Gas' RDM application proposed the recovery of approximately $20 million. On July 13, 2012, the MPSC approved a settlement agreement approving the RDM reconciliation and the implementation of a surcharge over a twelve-month period beginning in August 2012. As a result of the provisions of the settlement, during the quarter ended June 30, 2012, DTE Gas recognized an additional $5 million of revenue related to the 2010/2011 period and $3 million related to the 2011/2012 period.

In October 2012, DTE Gas filed an application with the MPSC for approval of its RDM reconciliation for the period July 1, 2011 through June 30, 2012. The application requests authority to adjust existing retail gas rates so as to collect a net amount of $8.6 million, plus interest. An order is expected in the first quarter of 2013.

The December 2012 order in DTE Gas' rate case requires the RDM be discontinued effective November 1, 2012 and a reconciliation be filed by October 31, 2013. DTE Gas recognized approximately $5 million for the under-recovery during the July through October 2012 period. The order provides for a new RDM beginning in November 2013 for the period November 1, 2013 through October 31, 2014. The new RDM decouples weather normalized distribution revenue inside caps. The caps are tied to expected conservation targets: 1.125% in the first reconciliation period and 2.25% for the second and future periods.

DTE Gas Depreciation Filing

In June 2012, DTE Gas filed a depreciation study, as ordered by the MPSC, indicating an annual depreciation expense increase of $12.4 million. Pursuant to the December 2012 order in DTE Gas' rate case, the final approved depreciation rates will be implemented in conjunction with the MPSC's order in DTE Gas' next general rate case. Management cannot predict when DTE Gas will file its next rate case.

Gas Cost Recovery Proceedings

The GCR process is designed to allow DTE Gas 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.

2010-2011 GCR Year - An MPSC order was issued on August 14, 2012 approving the GCR reconciliation for the twelve-month period ended March 31, 2011. The MPSC authorized DTE Gas to include in its 2011-2012 GCR reconciliation beginning balance the net over-recovery of approximately $6 million.

2011-2012 GCR Year - In June 2012, DTE Gas filed its GCR reconciliation for the twelve months ending March 31, 2012 calculating a net under-recovery of $6.4 million.

Gas Recovery of Costs to Achieve (CTA) Performance Excellence Process

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DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

DTE Gas incurred CTA restructuring expense during a review of its operations which began in 2005. In September 2006, the MPSC issued an order approving a settlement agreement that allowed DTE Electric and DTE Gas, commencing in 2006, to defer the incremental CTA. Further, the order provided for DTE Electric and DTE Gas to amortize the CTA deferrals over a ten-year period beginning with the year subsequent to the year the CTA was deferred. The September 2006 order did not provide a regulatory recovery mechanism for DTE Gas, therefore DTE Gas expensed CTA incurred during the period 2006 through 2008. A June 2010 MPSC order provided for DTE Gas’ recovery of the regulatory unamortized balance of CTA. DTE Gas deferred and recognized in income approximately $32 million ($20 million after-tax) of previously expensed CTA in 2010.

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:

	2012			2011			2010
	(In millions)
Income before income taxes	$	960		$	991		$	962
Income tax expense at 35% statutory rate	$	336		$	347		$	337
Production tax credits	(49		)	(6		)	(33		)
Investment tax credits	(6		)	(6		)	(6		)
Depreciation	(4		)	(4		)	(4		)
Employee Stock Ownership Plan dividends	(4		)	(4		)	(5		)
Domestic production activities deduction	(14		)	(7		)	(7		)
Settlement of Federal tax audit	—			—			(12		)
State and local income taxes, net of federal benefit	37			37			44
Enactment of Michigan Corporate Income Tax, net of federal expense	—			(87		)	—
Other, net	(10		)	(2		)	1
Income tax expense	$	286		$	268		$	315
Effective income tax rate	29.8		%	27.0		%	32.7		%

Components of income tax expense were as follows:

	2012			2011			2010
Current income tax expense (benefit)	(In millions)
Federal	$	190		$	27		$	(168	)
State and other income tax	49			21			26
Total current income taxes	239			48			(142		)
Deferred income tax expense (benefit)
Federal	39			318			415
State and other income tax	8			(98		)	42
Total deferred income taxes	47			220			457
Total income taxes from continuing operations	286			268			315
Discontinued operations	(29		)	(1		)	(4		)
Total	$	257		$	267		$	311

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:

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DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

	2012			2011
	(In millions)
Property, plant and equipment	$	(3,389	)	$	(3,131	)
Securitized regulatory assets	(256		)	(360		)
Alternative minimum tax credit carry-forwards	254			294
Merger basis differences	42			50
Pension and benefits	(33		)	(39		)
Other comprehensive income	101			99
Derivative assets and liabilities	66			64
State net operating loss and credit carry-forwards	37			30
Other	41			(45		)
	(3,137		)	(3,038		)
Less valuation allowance	(33		)	(27		)
	$	(3,170	)	$	(3,065	)
Current deferred income tax assets	$	21		$	51
Long-term deferred income tax liabilities	(3,191		)	(3,116		)
	$	(3,170	)	$	(3,065	)
Deferred income tax assets	$	1,038		$	1,048
Deferred income tax liabilities	(4,208		)	(4,113		)
	$	(3,170	)	$	(3,065	)

Production tax credits earned in prior years but not utilized totaled $254 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 $37 million and $30 million at December 31, 2012 and 2011, respectively. The state net operating loss and credit carry-forwards expire from 2013 through 2031. The Company has recorded valuation allowances at December 31, 2012 and 2011 of approximately $33 million and $27 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:

	2012			2011			2010
	(In millions)
Balance at January 1	$	48		$	28		$	81
Additions for tax positions of prior years	—			27			4
Reductions for tax positions of prior years	(2		)	(4		)	(4		)
Additions for tax positions of current year	1			1			—
Settlements	(30		)	(3		)	(53		)
Lapse of statute of limitations	(6		)	(1		)	—
Balance at December 31	$	11		$	48		$	28

The Company had $3 million and $4 million of unrecognized tax benefits at December 31, 2012 and at December 31, 2011, 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

83

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Company believes that it is possible that there will be a decrease in unrecognized tax benefits of up to $1 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 $1 million and $2 million at December 31, 2012 and December 31, 2011, respectively. The Company had no accrued penalties pertaining to income taxes. The Company recognized interest expense (income) related to income taxes of $(1) million, $(2) million and $1 million in 2012, 2011 and 2010, respectively.

In 2012, the Company settled a federal tax audit for the 2009 and 2010 tax years, which resulted in the recognition of $30 million of unrecognized tax benefits. The Company's federal income tax returns for 2011 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 Statements of Cash Flows.

NOTE 13 — COMMON STOCK

Common Stock

On June 18, 2012, the Company contributed $80 million of DTE Energy common stock to the DTE Energy Company Affiliates Employee Benefit Plans Master Trust. The common stock was valued using the closing market price of DTE Energy common stock on that date in accordance with fair value measurement and accounting requirements.

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

84

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 was to restrict the payment of approximately $239 million at December 31, 2012 of total retained earnings of approximately $4 billion. There are no other effective limitations with respect to the Company’s ability to pay dividends.

85

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:

	2012		2011		2010
	(In millions, expect per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	610	$	711	$	630
Average number of common shares outstanding	171		169		168
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	413	$	392	$	365
Dividends declared — net restricted shares	1		1		2
Total distributed earnings	$	414	$	393	$	367
Net income less distributed earnings	$	196	$	318	$	263
Distributed (dividends per common share)	$	2.42	$	2.32	$	2.18
Undistributed	1.14		1.87		1.57
Total Basic Earnings per Common Share	$	3.56	$	4.19	$	3.75
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	610	$	711	$	630
Average number of common shares outstanding	171		169		168
Average incremental shares from assumed exercise of options	1		1		1
Common shares for dilutive calculation	172		170		169
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	413	$	392	$	365
Dividends declared — net restricted shares	1		1		2
Total distributed earnings	$	414	$	393	$	367
Net income less distributed earnings	$	196	$	318	$	263
Distributed (dividends per common share)	$	2.42	$	2.32	$	2.18
Undistributed	1.13		1.86		1.56
Total Diluted Earnings per Common Share	$	3.55	$	4.18	$	3.74

Options to purchase approximately 5 million shares of common stock in 2010 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.

86

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 (a) of debt outstanding at December 31 were:

	2012			2011
	(In millions)
Mortgage bonds, notes, and other
DTE Energy Debt, Unsecured
5.4% due 2013 to 2033	$	1,298		$	1,298
DTE Electric Taxable Debt, Principally Secured
5.0% due 2013 to 2042	3,777			3,515
DTE Electric Tax-Exempt Revenue Bonds (b)
5.3% due 2014 to 2038	707			893
DTE Gas Taxable Debt, Principally Secured
5.6% due 2013 to 2042	919			889
Other Long-Term Debt, Including Non-Recourse Debt	153			165
	6,854			6,760
Less amount due within one year	(634		)	(355		)
	$	6,220		$	6,405
Securitization bonds
6.6% due 2013 to 2015	$	479		$	643
Less amount due within one year	(177		)	(164		)
	$	302		$	479
Junior Subordinated Debentures
6.5% due 2061	$	280		$	280
5.25% due 2062	200			—
	$	480		$	280

_______________________________________

(a) Weighted average interest rates as of December 31, 2012 are shown below the description of each category of debt.

(b) DTE Electric Tax-Exempt Revenue Bonds are issued by a public body that loans the proceeds to DTE Electric on terms substantially mirroring the Revenue Bonds.

Debt Issuances

In 2012, the Company issued the following long-term debt:

Company	Month Issued	Type	Interest Rate		Maturity	Amount
	(In millions)
DTE Electric	June	Mortgage Bonds (a)	2.65	%	2022	$	250
DTE Electric	June	Mortgage Bonds (a)	3.95	%	2042	250
DTE Energy	October	Junior Subordinated Debentures (b)	5.25	%	2062	200
DTE Gas	December	Mortgage Bonds (c)	3.92	%	2042	70
						$	770

_______________________________________

(a) Proceeds were used for the early redemption of DTE Electric long-term debt; for the repayment of short-term borrowings; and for general corporate purposes.

(b) Proceeds were used to pay a portion of the purchase price for a portfolio of on-site energy projects; for the repayment of short-term borrowings; and for general corporate purposes.

(c) Proceeds were used for general corporate purposes.

Debt Redemptions

In 2012, the following debt was redeemed:

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DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Company	Month	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March/September	Securitization Bonds	6.42	%	2012	$	164
DTE Electric	April	Mortgage Bonds	7.90	%	2012	10
DTE Electric	April	Mortgage Bonds	8.36	%	2012	3
DTE Gas	May	Secured Medium Term Notes	7.06	%	2012	40
DTE Electric	July	Senior Notes	5.20	%	2012	225
DTE Electric	December	Tax Exempt Revenue Bonds (a)	3.05	%	2024	65
DTE Electric	December	Tax Exempt Revenue Bonds (a)	5.45	%	2032	64
DTE Electric	December	Tax Exempt Revenue Bonds (a)	5.25	%	2032	56
DTE Energy	Various	Other Long-Term Debt	Various		2012	12
						$	639

_______________________________________

(a) DTE Electric Tax Exempt Revenue Bonds are issued by a public body that loans the proceeds to DTE Electric on terms substantially mirroring the Revenue Bonds.

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

	2013		2014		2015		2016		2017		2018 and Thereafter		Total
	(In millions)
Amount to mature	$	811	$	891	$	476	$	465	$	9	$	5,166	$	7,818

Junior Subordinated Debentures

At December 31, 2012, the Company had $280 million of 6.5% Junior Subordinated Debentures due 2061 and $200 million of 5.25% Junior Subordinated Debentures due 2062. 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 associated with the related debt issue.

Cross Default Provisions

Substantially all of the net utility properties of DTE Electric and DTE Gas are subject to the lien of mortgages. Should DTE Electric or DTE Gas 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, 2012, the amount of authorized and unissued stock is as follows:

Company	Type of Stock	Par Value		Shares Authorized
DTE Energy	Preferred	$	—	5,000,000
DTE Electric	Preferred	$	100	6,747,484
DTE Electric	Preference	$	1	30,000,000
DTE Gas	Preferred	$	1	7,000,000
DTE Gas	Preference	$	1	4,000,000

NOTE 17 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

DTE Energy and its wholly owned subsidiaries, DTE Electric and DTE Gas, have 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.

88

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The 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 DTE Gas 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, 2012, the total funded debt to total capitalization ratios for DTE Energy, DTE Electric and DTE Gas are 0.48 to 1, 0.52 to 1 and 0.46 to 1, respectively, and are in compliance with this financial covenant. The availability under these combined facilities at December 31, 2012 is shown in the following table:

	DTE Energy		DTE Electric		DTE Gas		Total
	(In millions)
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, 2012	$	1,275	$	300	$	400	$	1,975
Amounts outstanding at December 31, 2012:
Commercial paper issuances	—		130		110		240
Letters of credit	175		—		—		175
	175		130		110		415
Net availability at December 31, 2012	$	1,100	$	170	$	290	$	1,560

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $73 million which are used for various corporate purposes.

The weighted average interest rate for short-term borrowings was 0.4% and 0.5% at December 31, 2012 and 2011, 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, 2012, a $40 million letter of credit was in place, raising the capacity under this facility to $140 million. The $40 million letter of credit is included in the table above. The amount outstanding under this agreement was $65 million and $56 million at December 31, 2012 and December 31, 2011, 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 Company has also entered into various power purchase agreements which meet the criteria of capital and operating leases. The lease arrangements expire at various dates through 2032. Future minimum lease payments under non-cancelable leases at December 31, 2012 were:

89

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

	Capital Leases		Operating Leases
	(In millions)
2013	$	7	$	38
2014	5		31
2015	5		25
2016	3		21
2017	—		20
Thereafter	—		98
Total minimum lease payments	$	20	$	233
Less imputed interest	2
Present value of net minimum lease payments	18
Less current portion	6
Non-current portion	$	12

Rental expense for operating leases was $36 million in 2012, $40 million in 2011, and $32 million in 2010. Contingent rental payments of $27 million were incurred in 2012 related to power purchase agreements. The contingent payments are based upon delivery of energy and renewable energy credits, which are dependent upon future production.

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, 2012, were as follows:

	(In millions)
2013	$	12
2014	12
2015	12
2016	12
2017	12
Thereafter	31
Total minimum future lease receipts	91
Residual value of leased pipeline	40
Less unearned income	(48		)
Net investment in capital lease	83
Less current portion	(4		)
	$	79

NOTE 19 — COMMITMENTS AND CONTINGENCIES

Environmental

Electric

Air - DTE Electric 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, DTE Electric has spent approximately $1.9 billion through 2012. The Company estimates DTE Electric will make capital expenditures of approximately $335 million in 2013 and up to approximately $1.6 billion of additional capital expenditures through 2020 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 U. S. Court of Appeals for the District of Columbia Circuit granted the motions to stay the rule, leaving DTE Electric temporarily subject to the previously existing Clean Air Interstate Rule (CAIR). On August 21, 2012, the Court issued its decision, vacating CSAPR and leaving

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CAIR in place. The EPA's petition seeking a rehearing of the U.S. Court of Appeals' decision regarding the CSAPR was denied on January 24, 2013. 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 DTE Electric 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 U. S. 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 DTE Electric, 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 DTE Electric 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 DTE Electric 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 DTE Electric'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. Oral arguments took place on November 27, 2012 in the appeal of the August 2011 summary judgment before a three-judge panel of the Sixth Circuit Court of Appeals in Cincinnati, Ohio. A decision in this appeal is expected in early 2013. DTE Energy and DTE Electric 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.

On November 9, 2012, the Sierra Club filed a Notice of Intent to Sue DTE Electric for Violations of the Clean Air Act at the St. Clair, Belle River, and Trenton Channel power plants. The notice cites 1,330 total exceedances of the 6-minute opacity standard at nine electric generating units over a five-year period. The Sierra Club obtained the opacity exceedance data from excess emission reports that are submitted every quarter by DTE Electric to the MDEQ. No enforcement actions have been initiated by the MDEQ over this five-year period as a result of the reported opacity exceedances. The Company will develop a strategy for responding to the petition from the Sierra Club that is expected in early 2013.

Water - In response to an EPA regulation, DTE Electric would be 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, DTE Electric may be required to install technologies to reduce the impacts of the water intake structures. The initial rule published in 2004 was subsequently remanded and a proposed rule published in 2011. The proposed rule specified an eight year compliance timeline. In July 2012, the EPA announced that a notice of its final action on the rule will be issued June 2013. 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. DTE Electric 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, electric generating power plants, 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, 2012 and 2011, the Company had $9 million and $8 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.

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DTE Electric 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. 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

Contaminated Sites — Gas segment, owned 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 segment recognizes a liability and corresponding regulatory asset for estimated investigation and remediation costs at former MGP sites. As of December 31, 2012 and 2011, the Company had $29 million and $36 million, accrued for remediation, respectively.

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 DTE Gas, which allows DTE Gas 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 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 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 and the Pennsylvania Department of Environmental Protection (PADEP) have also alleged certain violations of the Clean Water Act including wastewater discharges and coal pile storm water runoff discussed below. The Company agreed to a Consent Order with the EPA and settled these historic air and water issues by paying a fine of $1.75 million.

The Company received two NOVs from the PADEP 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 PADEP to upgrade its wastewater treatment technology to a biological treatment facility. The Company expects to spend less than $6 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.

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The Company may spend an additional $17 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. Final IBMACT and CISWI were issued by the EPA in December 2012. The Company will assess the financial impact, if any, on current operations for compliance with the applicable new standards.

In 2010, the EPA finalized a new 1-hour sulfur dioxide ambient air quality standard that requires states to submit plans for non-attainment areas to be in compliance by 2017. Michigan's proposed non-attainment area includes DTE Energy facilities in southwest Detroit and areas of Wayne County. Preliminary modeling runs by the MDEQ suggest that emission reductions may be required by significant sources of sulfur dioxide emissions in these areas, including DTE Electric power plants and our Michigan coke battery. The state implementation plan process is in the preliminary stage and any required emission reductions for DTE Energy sources to meet the standard cannot be estimated currently.

Nuclear Operations

Property Insurance

DTE Electric 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.

DTE Electric 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 3-year period.

DTE Electric 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, subject to a $1 million deductible.

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

Public Liability Insurance

As of January 1, 2013, as required by federal law, DTE Electric 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.

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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, DTE Electric has a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. DTE Electric 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. DTE Electric 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 2014. 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.

DTE Electric 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. In July 2012, DTE Electric executed a settlement agreement with the federal government for costs associated with the DOE's delay in acceptance of spent nuclear fuel from Fermi 2 for permanent storage. The settlement provided for a payment of approximately $48 million, received in August 2012, for delay-related costs experienced by DTE Electric through 2010, and a claims process for submittal of delay-related costs from 2011 through 2013. The settlement proceeds reduced the cost of the dry cask storage facility assets. The federal government continues to maintain its legal obligation to accept spent nuclear fuel from Fermi 2 for permanent storage. Issues relating to long-term waste disposal policy and to the disposition of funds contributed by DTE Electric 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, 2012 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, 2012 is approximately $77 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 $50 million at December 31, 2012.

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, 2012, the Company had approximately $41 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.

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Labor Contracts

There are several bargaining units for the Company’s approximately 4,900 represented employees. The majority of represented employees are under contracts that expire in June and October 2013.

Purchase Commitments

As of December 31, 2012, 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 $4.4 billion from 2013 through 2052 as detailed in the following table:

	(In millions)
2013	$	1,937
2014	1,199
2015	424
2016	147
2017	88
2018 — 2052	582
	$	4,377

The Company also estimates that 2013 capital expenditures will be approximately $2.2 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.

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.

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Effective January 1, 2012, the Company 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.

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 $229 million to its pension plans in 2012. At the discretion of management, and depending upon financial market conditions, we anticipate making up to a $315 million contribution to the pension plans in 2013.

Net pension cost includes the following components:

	2012			2011			2010
	(In millions)
Service cost	$	82		$	69		$	64
Interest cost	204			202			202
Expected return on plan assets	(244		)	(246		)	(258		)
Amortization of:
Net loss	176			142			100
Prior service cost	—			3			4
Special termination benefits	2			2			—
Net pension cost	$	220		$	172		$	112

	2012			2011
	(In millions)
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income
Net actuarial loss	$	395		$	619
Amortization of net actuarial loss	(178		)	(142		)
Amortization of prior service cost	—			(3		)
Total recognized Regulatory assets and Other comprehensive income	$	217		$	474
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	437		$	646
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	$	202		$	171

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:

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	2012			2011
	(In millions)
Accumulated benefit obligation, end of year	$	4,349		$	3,881
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	4,195		$	3,785
Service cost	82			69
Interest cost	204			202
Actuarial loss	474			355
Special termination benefits	2			2
Benefits paid	(228		)	(218		)
Projected benefit obligation, end of year	$	4,729		$	4,195
Change in plan assets
Plan assets at fair value, beginning of year	$	2,886		$	2,913
Actual return on plan assets	325			(18		)
Company contributions	240			209
Benefits paid	(228		)	(218		)
Plan assets at fair value, end of year	$	3,223		$	2,886
Funded status of the plans	$	(1,506	)	$	(1,309	)
Amount recorded as:
Current liabilities	$	(8	)	$	(11	)
Noncurrent liabilities	(1,498		)	(1,298		)
	$	(1,506	)	$	(1,309	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	205		$	202
Prior service (credit)	(2		)	(3		)
	$	203		$	199
Amounts recognized in Regulatory assets (see Note 11)
Net actuarial loss	$	2,413		$	2,201
Prior service cost	7			7
	$	2,420		$	2,208

At December 31, 2012, 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)
2013	$	236
2014	242
2015	252
2016	260
2017	269
2018-2022	1,485
	$	2,744

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

	2012		2011		2010
Projected benefit obligation
Discount rate	4.15	%	5.00	%	5.50	%
Rate of compensation increase	4.20	%	4.20	%	4.00	%
Net pension costs
Discount rate	5.00	%	5.50	%	5.90	%
Rate of compensation increase	4.20	%	4.00	%	4.00	%
Expected long-term rate of return on plan assets	8.25	%	8.50	%	8.75	%

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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.

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, 2012 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, 2012 and 2011 (a):

	December 31, 2012								December 31, 2011
	Level 1		Level 2		Level 3		Net Balance		Level 1		Level 2		Level 3		Net Balance
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	24	$	—	$	24	$	—	$	33	$	—	$	33
Equity securities															—
U.S. Large Cap (c)	688		44		—		732		640		40		—		680
U.S. Small/Mid Cap (d)	153		5		—		158		159		5		—		164
Non U.S (e)	530		120		—		650		392		114		—		506
Fixed income securities (f)	87		765		—		852		88		703		—		791
Hedge Funds and Similar Investments (g)	209		80		339		628		190		58		296		544
Private Equity and Other (h)	—		—		179		179		—		—		168		168
Total	$	1,667	$	1,038	$	518	$	3,223	$	1,469	$	953	$	464	$	2,886

_______________________________________

(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.

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(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):

	Year Ended December 31, 2012									Year Ended December 31, 2011
	Hedge Funds and Similar Investments			Private Equity and Other			Total			Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1	$	296		$	168		$	464		$	304		$	174		$	478
Total realized/unrealized gains (losses):
Realized gains (losses)	18			(6		)	12			(4		)	6			2
Unrealized gains (losses)	(5		)	12			7			1			(30		)	(29		)
Purchases, sales and settlements:
Purchases	250			33			283			64			23			87
Sales	(220		)	(28		)	(248		)	(69		)	(5		)	(74		)
Ending Balance at December 31	$	339		$	179		$	518		$	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	$	16		$	6		$	22		$	4		$	(28	)	$	(24	)

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, 2012 and 2011.

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 $37 million, $35 million, and $34 million in each of the years 2012, 2011, and 2010, 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 $140 million to its postretirement medical and life insurance benefit plans during 2012.

99

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 ten 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.

Effective January 1, 2013, the Company replaced sponsored retiree medical, prescription drug and dental coverage for current and future Medicare eligible non-represented retirees, spouses, surviving spouses, or same sex domestic partners with a Retiree Health Care Allowance (RHCA) account of $3,500 or $3,250 per year depending on their date of hire. Local 17 employees hired after September 24, 2012 will receive a $4,000 per year allocation to an account in a tax-exempt trust for each employee, in lieu of offering post-employment health care and life insurance benefits. Current Local 17 employees, spouses, surviving spouse, or same sex domestic partners, who retired after November 6, 2012 will receive a RHCA of $3,250 per year upon becoming eligible for Medicare.

In January 2013, the Company contributed $145 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 2013.

Net postretirement cost includes the following components:

	2012			2011			2010
	(In millions)
Service cost	$	68		$	64		$	61
Interest cost	120			121			125
Expected return on plan assets	(92		)	(94		)	(74		)
Amortization of:
Net loss	80			55			54
Prior service credit	(27		)	(26		)	(4		)
Net transition asset	2			2			2
Net postretirement cost	$	151		$	122		$	164

	2012			2011
	(In millions)
Other changes in plan assets and APBO recognized in Regulatory assets and Other comprehensive income (in millions)
Net actuarial (gain) loss	$	(34	)	$	195
Amortization of net actuarial loss	(80		)	(55		)
Prior service credit	(264		)	(4		)
Amortization of prior service credit	27			26
Amortization of transition asset	(2		)	(2		)
Total recognized in Regulatory assets and Other comprehensive income	$	(353	)	$	160
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	(202	)	$	282
Estimated amounts to be amortized from Regulatory assets and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year (in millions)
Net actuarial loss	$	69		$	78
Prior service credit	$	(91	)	$	(27	)
Net transition obligation	$	—		$	2

100

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:

	2012			2011
	(In millions)
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation, beginning of year	$	2,470		$	2,305
Service cost	68			64
Interest cost	120			121
Plan amendments	(264		)	(4		)
Actuarial loss	5			80
Medicare Part D subsidy	6			6
Benefits paid	(90		)	(102		)
Accumulated postretirement benefit obligation, end of year	$	2,315		$	2,470
Change in plan assets
Plan assets at fair value, beginning of year	$	985		$	1,029
Actual return on plan assets	131			(22		)
Company contributions	140			111
Benefits paid	(103		)	(133		)
Plan assets at fair value, end of year	$	1,153		$	985
Funded status, end of year	$	(1,162	)	$	(1,485	)
Amount recorded as:
Current liabilities	$	(2	)	$	(1	)
Noncurrent liabilities	$	(1,160	)	$	(1,484	)
	$	(1,162	)	$	(1,485	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	40		$	47
Prior service credit	(14		)	(20		)
Net transition asset	(1		)	(1		)
	$	25		$	26
Amounts recognized in Regulatory assets (See Note 11)
Net actuarial loss	$	727		$	835
Prior service cost	(302		)	(60		)
Net transition obligation	1			3
	$	426		$	778

At December 31, 2012, 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)
2013	$	103
2014	109
2015	115
2016	120
2017	127
2018 — 2022	726
	$	1,300

101

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

	2012		2011		2010
Projected benefit obligation
Discount rate	4.15	%	5.00	%	5.50	%
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
Net benefit costs
Discount rate	5.00	%	5.50	%	5.90	%
Expected long-term rate of return on plan assets	8.25	%	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	2020		2019		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 $28 million and increased the accumulated benefit obligation by $279 million at December 31, 2012. 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 $19 million and would have decreased the accumulated benefit obligation by $264 million at December 31, 2012.

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, 2012 are listed below:

U.S. Domestic Equity Securities	21	%
Non U.S. Equity Securities	20
Fixed Income Securities	25
Hedge Funds and Similar Investments	20
Private Equity and Other	14
	100	%

Fair Value Measurements at December 31, 2012 and 2011(a):

	December 31, 2012								December 31, 2011
	Level 1		Level 2		Level 3		Net Balance		Level 1		Level 2		Level 3		Net Balance
Asset Category:	(In millions)
Short-term investments (b)	$	1	$	2	$	—	$	3	$	—	$	13	$	—	$	13
Equity securities:
U.S. Large Cap (c)	189		3		—		192		175		15		—		190
U.S. Small/Mid Cap (d)	105		—		—		105		70		6		—		76
Non U.S (e)	230		7		—		237		176		14		—		190
Fixed income securities (f)	38		247		—		285		24		236		—		260
Hedge Funds and Similar Investments (g)	102		24		119		245		80		21		95		196
Private Equity and Other (h)	—		—		86		86		—		—		60		60
Total	$	665	$	283	$	205	$	1,153	$	525	$	305	$	155	$	985

_______________________________________

(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.

102

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

(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):

	Year Ended December 31, 2012									Year Ended December 31, 2011
	Hedge Funds and Similar Investments			Private Equity and Other			Total			Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1	$	95		$	60		$	155		$	79		$	55		$	134
Total realized/unrealized gains (losses):
Realized gains (losses)	6			(11		)	(5		)	(1		)	2			1
Unrealized gains (losses)	—			14			14			2			(22		)	(20		)
Purchases, sales and settlements:
Purchases	86			36			122			68			48			116
Sales	(68		)	(13		)	(81		)	(53		)	(23		)	(76		)
Ending Balance at December 31	$	119		$	86		$	205		$	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	$	6		$	2		$	8		$	5		$	(16	)	$	(11	)

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, 2012 and 2011.

Healthcare Legislation

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 2012, $6 million in 2011 and $7 million in 2010.

Grantor Trust

DTE Gas 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 DTE Gas can revoke the trust subject to providing the MPSC with prior notification. The Company accounts for its investment at fair value, approximately $14 million at December 31, 2012, with unrealized gains and losses recorded to earnings. The Grantor Trust investment is included in Other investments on the Consolidated Statements of Financial Position.

103

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

104

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 11,500,000 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:

	2012		2011		2010
	(In millions)
Stock-based compensation expense	$	83	$	66	$	52
Tax benefit	33		25		20
Stock-based compensation cost capitalized in property, plant and equipment	5		4		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 3-year period.

Stock option activity was as follows:

	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In millions)
Options outstanding at January 1, 2012	2,764,670		$	41.25
Granted	—		$	—
Exercised	(1,555,227	)	$	40.78
Forfeited or expired	(16,773	)	$	42.02
Options outstanding at December 31, 2012	1,192,670		$	41.86	$	22
Options exercisable at December 31, 2012	991,826		$	41.44	$	19

As of December 31, 2012, the weighted average remaining contractual life for the exercisable shares is 4.30 years. As of December 31, 2012, 200,844 options were non-vested. During 2012, 332,026 options vested.

There were no options granted during 2012 or 2011. The intrinsic value of options exercised for the years ended December 31, 2012, 2011 and 2010 was $25 million, $20 million, and $9 million, respectively. Total option expense recognized during 2012, 2011 and 2010 was $0.7 million, $2 million and $4 million, respectively.

105

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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	142,619	$	27.98	6.15
$	38.01	—	$	42.00	291,982	$	41.14	3.22
$	42.01	—	$	45.00	605,569	$	44.03	5.40
$	45.01	—	$	50.00	152,500	$	47.62	4.03
					1,192,670	$	41.86	4.78

The Company determined the fair value for these options at the date of grant in 2010 using a Black-Scholes based option pricing model and the following assumptions:

	2010
Risk-free interest rate	2.91	%
Dividend yield	5.08	%
Expected volatility	22.96	%
Expected life	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 upon request.

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:

	2012		2011		2010
Fair value of awards vested (in millions)	$	9	$	13	$	19
Restricted common shares awarded	167,320		381,840		238,405
Weighted average market price of shares awarded	$	53.71	$	47.98	$	44.08
Compensation cost charged against income (in millions)	$	12	$	12	$	12

The following table summarizes the Company’s stock awards activity for the period ended December 31, 2012:

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at January 1, 2012	726,224		$	42.25
Grants	167,320		$	53.71
Forfeitures	(37,767	)	$	48.46
Vested and issued	(258,129	)	$	34.41
Balance at December 31, 2012	597,648		$	48.33

106

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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:

	2012		2011		2010
	(In millions)
Compensation expense	$	71	$	53	$	36
Cash settlements (a)	$	4	$	3	$	3
Stock settlements (a)	$	41	$	25	$	23

_______________________________________

(a) 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. Performance shares granted are entitled to dividend equivalent payments before the performance shares granted are earned and vested. During the period beginning on the date the 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, 2012:

	Performance Shares
Balance at January 1, 2012	1,608,733
Grants	590,098
Forfeitures	(59,712	)
Payouts	(504,755	)
Balance at December 31, 2012	1,634,364

Unrecognized Compensation Costs

As of December 31, 2012, there was $58 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 1.37 years.

	Unrecognized Compensation Cost		Weighted Average to be Recognized
	(In millions)		(In years)
Options	$	—	0.15
Stock awards	11		1.02
Performance shares	47		1.46
	$	58	1.37

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:

107

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

	2012			2011			2010
	(In millions)
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	52		$	71		$	79
Inventories	35			(129		)	(133		)
Recoverable pension and postretirement costs	141			(620		)	(32		)
Accrued/prepaid pensions	280			432			67
Accounts payable	40			(23		)	12
Income taxes payable/receivable	30			249			(245		)
Derivative assets and liabilities	53			(94		)	(48		)
Postretirement obligation	(323		)	209			(24		)
Regulatory assets	122			38			(37		)
Other assets	117			(28		)	(15		)
Other liabilities	(105		)	(11		)	83
	$	442		$	94		$	(293	)

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

	2012		2011			2010
	(In millions)
Cash paid (received) for:
Interest (net of interest capitalized)	$	438	$	485		$	551
Income taxes	$	173	$	(205	)	$	93

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

	2012		2011		2010
	(In millions)
Common stock issued for employee benefit plans	$	114	$	1	$	156
Change in capital expenditures not paid	$	23	$	76	$	20

NOTE 23 — SEGMENT AND RELATED INFORMATION

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

Electric segment consists principally of DTE Electric, 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 segment consists of DTE Gas and Citizens.  DTE Gas 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.

Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers; and 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 state and local income tax provisions of the utility subsidiaries is determined on an individual company basis and recognizes the tax benefit of various

108

tax credits and net operating losses if applicable. The subsidiaries record federal, state and local income taxes payable to or receivable from DTE Energy based on the federal, state and local 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 the sale of reduced emissions fuel, power sales, gas sales and coal transportation services in the following segments:

	2012			2011			2010
	(In millions)
Electric	$	29		$	33		$	30
Gas	4			2			—
Gas Storage and Pipelines	6			8			4
Power and Industrial Projects	801			238			161
Energy Trading	43			70			89
Corporate and Other	(37		)	(50		)	(65		)
Discontinued Operations	2			—			—
	$	848		$	301		$	219

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)
2012
Electric	$	5,293		$	827	$	(1	)	$	272		$	280		$	483		$	17,755		$	1,208	$	1,230
Gas	1,315			92		(7		)	59			50			115			4,059			745		220
Gas Storage and Pipelines	96			8		(8		)	8			39			61			668			22		233
Power and Industrial Projects	1,823			65		(7		)	37			(44		)	42			991			26		83
Energy Trading	1,109			2		—			8			7			12			629			17		1
Corporate and Other	3			1		(52		)	121			(46		)	(47		)	3,074			—		3
Reclassifications and Eliminations	(848		)	—		65			(65		)	—			—			(837		)	—		—
Total from Continuing Operations	$	8,791		$	995	$	(10	)	$	440		$	286		666			26,339			2,018		1,770
Discontinued Operations (Note 7)															(56		)	—			—		49
Total															$	610		$	26,339		$	2,018	$	1,819

	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	$	5,154		$	818	$	(1	)	$	289		$	265		$	434		$	17,567		$	1,208	$	1,203
Gas	1,505			89		(7		)	64			60			110			4,065			745		179
Gas Storage and Pipelines	91			6		(5		)	7			35			57			538			22		16
Power and Industrial Projects	1,129			60		(8		)	32			11			38			789			26		56
Energy Trading	1,276			3		—			9			34			52			612			17		1
Corporate and Other	4			1		(47		)	145			(136		)	23			2,605			—		—
Reclassifications and Eliminations	(301		)	—		58			(58		)	(1		)	—			(485		)	—		—
Total from Continuing Operations	$	8,858		$	977	$	(10	)	$	488		$	268		$	714		$	25,691		$	2,018	$	1,455
Discontinued Operations (Note 7)															(3		)	318			2		29
Total															$	711		$	26,009		$	2,020	$	1,484

109

	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	$	4,993		$	849	$	(1	)	$	313		$	270		$	441		$	16,611		$	1,206	$	864
Gas	1,648			92		(9		)	66			67			127			3,925			759		147
Gas Storage and Pipelines	83			5		(1		)	6			32			51			446			9		5
Power and Industrial Projects	1,144			60		(3		)	33			3			85			872			27		53
Energy Trading	875			5		—			13			5			6			513			17		1
Corporate & Other	1			1		(47		)	160			(62		)	(72		)	2,616			—		—
Reclassifications and Eliminations	(219		)	—		49			(48		)	—			—			(413		)	—		—
Total from Continuing Operations	$	8,525		$	1,012	$	(12	)	$	543		$	315		$	638		$	24,570		$	2,018	$	1,070
Discontinued Operations (Note 7)															(8		)	326			2		27
Total															$	630		$	24,896		$	2,020	$	1,097

NOTE 24 — SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly earnings per share may not equal full year totals, 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)
2012
Operating Revenues	$	2,239	$	2,013		$	2,190	$	2,349		$	8,791
Operating Income	$	312	$	294		$	406	$	267		$	1,279
Net Income Attributable to DTE Energy Company
Continuing Operations	$	156	$	147		$	226	$	137		$	666
Discontinued Operations	—		(1		)	1		(56		)	(56		)
Net Income Attributable to DTE Energy Company	$	156	$	146		$	227	$	81		$	610
Basic Earnings per Share
Continuing Operations	$	0.91	$	0.87		$	1.31	$	0.79		$	3.89
Discontinued Operations	—		(0.01		)	0.01		(0.32		)	(0.33		)
Total	$	0.91	$	0.86		$	1.32	$	0.47		$	3.56
Diluted Earnings per Share
Continuing Operations	$	0.91	$	0.87		$	1.30	$	0.79		$	3.88
Discontinued Operations	—		(0.01		)	0.01		(0.32		)	(0.33		)
Total	$	0.91	$	0.86		$	1.31	$	0.47		$	3.55

2011
Operating Revenues	$	2,423		$	2,018		$	2,254	$	2,163		$	8,858
Operating Income	$	389		$	288		$	398	$	346		$	1,421
Net Income Attributable to DTE Energy Company
Continuing Operations (a)	$	177		$	203		$	183	$	151		$	714
Discontinued Operations	(1		)	(1		)	—		(1		)	(3		)
Net Income Attributable to DTE Energy Company	$	176		$	202		$	183	$	150		$	711
Basic Earnings per Share
Continuing Operations	$	1.05		$	1.19		$	1.08	$	0.88		$	4.21
Discontinued Operations	(0.01		)	—			—		—			(0.02		)
Total	$	1.04		$	1.19		$	1.08	$	0.88		$	4.19
Diluted Earnings per Share
Continuing Operations	$	1.05		$	1.19		$	1.07	$	0.88		$	4.20
Discontinued Operations	(0.01		)	—			—		—			(0.02		)
Total	$	1.04		$	1.19		$	1.07	$	0.88		$	4.18

_______________________________________

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

110

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 2013 Annual Meeting of Shareholders to be held May 2, 2013. 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:
4-279	Forty-Third Supplemental Indenture, dated as of December 1, 2012 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee. (2012 Series D Collateral Bonds)
10-81	Second Amendment to the DTE Energy Supplemental Savings Plan dated as of November 13, 2012.
12-52	Computation of Ratio of Earnings to Fixed Charges.
21-8	Subsidiaries of the Company.
23-26	Consent of PricewaterhouseCoopers LLP.
31-79	Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report.
31-80	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

111

	(ii) Exhibits incorporated herein by reference:
	Certain exhibits listed below refer to "The Detroit Edison Company" and "Michigan Consolidated Gas Company" and were effective prior to the change to DTE Electric Company and DTE Gas Company, respectively, effective January 1, 2013.
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).
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).
	Supplemental Indenture, dated as of September 1, 2012, to the Amended and Restated Indenture, dated as of April 9, 2001, between DTE Energy Company and The Bank of New York Mellon Trust Company,, N.A., as successor trustee (Exhibit 4-275 to Form 8-K dated October 1, 2012) (2012 Series C 5.25% Junior Subordinated Debentures due 2062).
4(b)	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)

112

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)

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 and C)

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 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)

113

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 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, 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, 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, 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)

Supplemental Indenture, dated as of August 15, 2011, 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 4-277 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2011). (2011 Series D, 2011 Series E, 2011 Series F)

114

Supplemental Indenture, dated as of September 1, 2011, 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 4-278 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2011). (2011 Series H)

Supplemental Indenture dated as of June 20, 2012, 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 4-279 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2012). (2012 Series A and B)

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). (6.35% 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)

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)

115

	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)
	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(d)	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)
	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(e)	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:

116

	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., 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 Gerard M. Anderson with The Detroit Edison Company, dated October 6, 1993 (Exhibit 10-48 to The Detroit Edison Company's Form 10-K for the year ended December 31, 1993).
10(c)	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(d)	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(e)	DTE Energy Company Annual Incentive Plan (Exhibit 10-44 to Form 10-Q for the quarter ended March 31, 2001).
10(f)	Amended and Restated DTE Energy Company 2006 Long-Term Incentive Plan (as Amended and Restated effective as of May 6, 2010 and as Amended May 3, 2012) (Exhibit A to DTE Energy's Definitive Proxy Statement dated March 15, 2012).
10(g)	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(h)	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(i)	Description of Executive Life Insurance Plan (Exhibit 10-47 to Form 10-Q for the quarter ended June 30, 2002).
10(j)	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(k)	Form of Director Restricted Stock Agreement (Exhibit 10.1 to Form 8-K dated June 23, 2005).

117

10(l)	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(m)	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).
	Second Amendment to the DTE Energy Company Executive Supplemental Retirement Plan (Amended and Restated Effective January 1, 2005) dated as of May 5, 2011 (Exhibit 10.80 to Form 10-Q for the quarter ended March 31, 2012.
10(n)	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(o)	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(p)	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(q)	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(r)	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(s)	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(t)	Form of Amended and Restated Michigan Consolidated Gas Company 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(u)	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:
32-79	Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report.
32-80	Chief Financial Officer Section 906 Form 10-K Certification of Periodic Report.

118

DTE Energy Company

Schedule II — Valuation and Qualifying Accounts

	Year Ending December 31,
	2012			2011			2010
	(In millions)
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statements of Financial Position)
Balance at Beginning of Period	$	162		$	196		$	262
Additions:
Charged to costs and expenses	79			94			113
Charged to other accounts (a)	16			18			20
Deductions (b)	(195		)	(146		)	(199		)
Balance at End of Period	$	62		$	162		$	196

_______________________________________

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

119

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 20, 2013

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/  DAVID E. MEADOR
	Gerard M. Anderson Chairman of the Board, President and Chief Executive Officer and Director (Principal Executive Officer)		David E. Meador Executive Vice President and Chief Financial Officer (Principal Financial Officer)
By	/s/  DONNA M. ENGLAND	By	/s/  EUGENE A. MILLER
	Donna M. England Chief Accounting Officer (Principal Accounting Officer)		Eugene A. Miller, Director
By	/s/  LILLIAN BAUDER	By	/s/  MARK A. MURRAY
	Lillian Bauder, Director		Mark A. Murray, Director
By	/s/  DAVID A. BRANDON	By	/s/  JAMES B. NICHOLSON
	David A. Brandon, Director		James B. Nicholson, 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/  CHARLES G. MCCLURE JR.	By	/s/  RUTH G. SHAW
	Charles G. McClure Jr., Director		Ruth G. Shaw, Director
By	/s/  GAIL J. MCGOVERN	By	/s/  JAMES H. VANDENBERGHE
	Gail J. McGovern, Director		James H. Vandenberghe, Director

Date: February 20, 2013

120

EX-4.279

Exhibit 4-279

FORTY-THIRD

SUPPLEMENTAL INDENTURE

TO

INDENTURE OF MORTGAGE AND

DEED OF TRUST

DATED AS OF MARCH 1, 1944

AS RESTATED IN

PART II OF THE TWENTY-NINTH

SUPPLEMENTAL INDENTURE DATED AS OF JULY 15, 1989

WHICH BECAME EFFECTIVE ON APRIL 1, 1994

MICHIGAN CONSOLIDATED GAS COMPANY

TO

CITIBANK, N.A.,

TRUSTEE

DATED AS OF DECEMBER 1, 2012

CREATING AN ISSUE OF FIRST MORTGAGE BONDS,

DESIGNATED AS

2012 Series D BONDS

MICHIGAN CONSOLIDATED GAS COMPANY

FORTY-THIRD SUPPLEMENTAL INDENTURE

DATED AS OF DECEMBER 1, 2012

SUPPLEMENTAL TO INDENTURE OF MORTGAGE

AND DEED OF TRUST

DATED AS OF MARCH 1, 1944

TABLE OF CONTENTS

PAGE

ARTICLE I AMENDMENT OF INDENTURE.................................................................................................................3

ARTICLE II ESTABLISHMENT OF AN ISSUE OF FIRST MORTGAGE BONDS, OF THE SERIES DESIGNATED AND DISTINGUISHED AS “2012 SERIES D BONDS”................................................................................................4

SECTION 1..............................................................................................................................................................4

SECTION 2..............................................................................................................................................................5

SECTION 3..............................................................................................................................................................5

SECTION 4..............................................................................................................................................................9

SECTION 5..............................................................................................................................................................9

ARTICLE III ISSUE OF BONDS.................................................................................................................................10

ARTICLE IV THE TRUSTEE......................................................................................................................................10

ARTICLE V RECORDING AND FILING OF SUPPLEMENTAL INDENTURE DATED AS OF DECEMBER 1, 2008..............................................................................................................................................................................................10

ARTICLE VI MISCELLANEOUS PROVISIONS.........................................................................................................11

1

THIS FORTY-THIRD SUPPLEMENTAL INDENTURE, dated as of the 1st day of December, 2012, between MICHIGAN CONSOLIDATED GAS COMPANY, a corporation duly organized and existing under and by virtue of the laws of the State of Michigan (hereinafter called the “Company”), having its principal place of business at One Energy Plaza, Detroit, Michigan, and CITIBANK, N.A., a national banking association incorporated and existing under and by virtue of the laws of the United States of America, having an office at 388 Greenwich Street in the Borough of Manhattan, the City of New York, New York, as successor trustee (hereinafter with its predecessors as trustee called the “Mortgage Trustee” or the “Trustee”):

WHEREAS, the Company has heretofore executed and delivered to the Trustee an Indenture of Mortgage and Deed of Trust (the “Original Indenture”), dated as of March 1, 1944;

WHEREAS, the Company has heretofore executed and delivered to the Trustee the Twenty-ninth Supplemental Indenture, which became effective April 1, 1994, to provide for the modification and restatement of the Original Indenture as previously amended (as so amended, supplemented and modified the “Indenture”), and to secure the Company's First Mortgage Bonds, unlimited in aggregate principal amount except as therein otherwise provided, issued pursuant to the:

Thirtieth Supplemental Indenture, dated as of September 1, 1991;

Thirty-first Supplemental Indenture, dated as of December 15, 1991;

Thirty-second Supplemental Indenture, dated as of January 5, 1993;

Thirty-third Supplemental Indenture, dated as of May 1, 1995;

Thirty-fourth Supplemental Indenture, dated as of November 1, 1996;

Thirty-fifth Supplemental Indenture, dated as of June 18, 1998;

Thirty-sixth Supplemental Indenture, dated as of August 15, 2001;

Thirty-seventh Supplemental Indenture, dated as of February 15, 2003;

Thirty-eighth Supplemental Indenture, dated as of October 1, 2004;

Thirty-ninth Supplemental Indenture, dated as of April 1, 2008;

Fortieth Supplemental Indenture, dated as of June 1, 2008;

Forty-first Supplemental Indenture, dated as of August 1, 2008; and

Forty-second Supplemental Indenture, dated as of December 1, 2008;

WHEREAS, at the date hereof there were outstanding First Mortgage Bonds of the Company issued under the Indenture, of 9 series in the principal amounts set forth below (including Collateral Bonds):

2

Designation of Series	Amount Initially Issued		Amount Outstanding
First Mortgage Bonds
(Secured Term Notes, Series B)
8¼% Series due 2014	$	80,000,000	$	80,000,000
Collateral Bonds
(Senior Notes)
5.70% Collateral Bonds due 2033	$	200,000,000	$	200,000,000
2004 Series E Collateral Bonds	$	120,000,000	$	120,000,000
2008 Series A Collateral Bonds	$	60,000,000	$	60,000,000
2008 Series B Collateral Bonds	$	100,000,000	$	100,000,000
2008 Series C Collateral Bonds	$	25,000,000	$	25,000,000
2008 Series F Collateral Bonds	$	75,000,000	$	75,000,000
2008 Series H Collateral Bonds	$	140,000,000	$	140,000,000
2008 Series I Collateral Bonds	$	50,000,000	$	50,000,000

WHEREAS, the Company desires in and by this Supplemental Indenture to establish a series of bonds to be issued under the Indenture, to designate the terms thereof, to specify the particulars necessary to describe and define the same and to specify such other provisions and agreements in respect thereof as are in the Indenture provided or permitted; and

WHEREAS, all the conditions and requirements necessary to make this Supplemental Indenture, when duly executed and delivered, a valid, binding and legal instrument in accordance with its terms and for the purposes herein expressed, have been done, performed and fulfilled, and the execution and delivery of thisSupplemental Indenture in the form and with the terms hereof have been in all respects duly authorized;

NOW, THEREFORE, in consideration of the premises and in further consideration of the sum of One Dollar in lawful money of the United States of America paid to the Company by the Trustee at or before the execution and delivery of this Forty-third Supplemental Indenture, the receipt whereof is hereby acknowledged, and of other good and valuable consideration, it is agreed by and between the Company and the Trustee as follows:

ARTICLE I

AMENDMENT OF INDENTURE

SECTION 1.Amendment of Granting Clause. The Granting Clause of the Indenture is hereby amended to insert the words “including, without limitation, covenants of the Company to pay any premium (including any make-whole amount) due and payable on any bonds at any time issued and outstanding hereunder,” immediately following the words “performance and observance of all the covenants and conditions therein and herein contained.”

SECTION 2. Amendment of Section 9.01 of the Indenture. Section 9.01 of the Indenture is hereby amended to include the following additional “event of default”:

I. Default shall be made in the due and punctual payment of any premium (including any make-whole amount) on any of the bonds issued hereunder when and as the same shall become due and payable as expressed in such bonds or in this Indenture or in any indenture supplemental hereto;

3

ARTICLE II

ESTABLISHMENT OF AN ISSUE OF

SECTION 1. There is hereby established a series of bonds to be issued under and secured by the Indenture, to be known as “First Mortgage Bonds,” designated and distinguished as “2012 Series D Bonds” of the Company (herein collectively sometimes called the “Bonds”). The Bonds shall be limited in aggregate principal amount to $70,000,000 except as provided in Article II of the Indenture and in this Supplemental Indenture with respect to transfers, exchanges and replacements of Bonds. The Bonds shall be registered bonds without coupons and shall be dated as of the date of the authentication thereof by the Trustee.

The Bonds shall mature on the 15th day of December, 2042 (subject to earlier redemption, as provided herein), shall bear interest at the rate of 3.92% per annum, payable semi-annually on the fifteenth day of June and December of each year and at maturity (each an “Interest Payment Date”), beginning on June 15, 2013. The principal, Make-Whole Amount (as defined below), if any, and interest on the Bonds shall be payable in lawful money of the United States of America; the place where such principal and Make-Whole Amount, if any, shall be payable shall be the corporate trust office of the Trustee in the Borough of Manhattan, the City of New York, New York, and the place where such interest shall be payable shall be the office or agency of the Company in said Borough of Manhattan, the City of New York, New York. The Bonds shall have such other terms as set forth in the form of Bond provided in Section 3.

SECTION 2. The Bonds shall be subject to redemption at the option of the Company, in whole at any time or in part from time to time (any such date of redemption, a “Redemption Date”), at a redemption price (any such price, a “Redemption Price”) equal to 100% of the principal amount of the Bonds to be redeemed on the Redemption Date together with the Make-Whole Amount (as defined in the form of Bond provided in Section 3), if any, plus, in each case, accrued and unpaid interest thereon to the Redemption Date.

Notwithstanding the foregoing, installments of interest on the Bonds that are due and payable on Interest Payment Dates falling on or prior to a Redemption Date will be payable on the Interest Payment Date to the registered holders as of the close of business on the relevant Record Date.

Notice of redemption shall be given to the holders of the Bonds to be redeemed not more than 60 nor less than 30 days prior to the Redemption Date, as provided in Section 4.05 of the Indenture. Each such notice shall specify such optional Redemption Date, the aggregate principal amount of the Bonds to be redeemed on such date, the principal amount of each Bond held by such holder to be redeemed, and the interest to be paid on the Redemption Date with respect to such principal amount being prepaid, and shall be accompanied by a certificate of a senior financial officer of the Company as to the estimated Make-Whole Amount due in connection with such redemption (calculated as if the date of such notice were the date of the redemption), setting forth the details of such computation. The Make-Whole Amount shall be determined by the Company two Business Days prior to the applicable Redemption Date and the Company shall deliver to holders of the Bonds and to the Trustee a certificate of a senior financial officer specifying the calculation of such Make-Whole Amount as of the Redemption Date.

Subject to the limitations of Section 4.07 of the Indenture, the notice of redemption may state that it is subject to the receipt of the redemption moneys by the Trustee on or before the Redemption Date, and that such notice shall be of no effect unless such moneys are so received on or before such date.

If the Bonds are only partially redeemed by the Company, the Trustee shall select which Bonds are to be redeemed pro rata among all of the Bonds at the time outstanding in proportion, as nearly as practicable, to the respective unpaid principal amounts thereof and otherwise in accordance with the terms of the Indenture. In the event of redemption of the Bonds in part only, a new Bond or Bonds for the unredeemed portion will be issued in the name or names of the holders thereof upon the surrender or cancellation thereof.

If money sufficient to pay the applicable Redemption Price with respect to the Bonds to be redeemed on the applicable Redemption Date, together with accrued interest to the Redemption Date, is deposited with the Trustee on or before the related Redemption Date and certain other conditions are satisfied, then the Bonds to be redeemed shall no longer be secured by, or entitled to any lien or benefit of, the Indenture as provided by Section 4.04 of the Indenture.

The Bonds will not have a sinking fund.

4

SECTION 3. The Bonds shall be registered bonds without coupons. The Trustee shall be the registrar and paying agent for the Bonds, which duties it hereby accepts. Bonds may be issued in minimum denominations of $100,000 or any integral multiple of $1,000 in excess thereof.

The forms of Bonds shall be substantially as follows:

[FORM OF MICHIGAN CONSOLIDATED GAS COMPANY 3.92% FIRST MORTGAGE BONDS 2012 SERIES D DUE 2042]

PPN:

No. R-___$_________________

THE SECURITIES EVIDENCED HEREBY HAVE NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED (THE “SECURITIES ACT”) AND MAY NOT BE OFFERED, SOLD, PLEDGED OR OTHERWISE TRANSFERRED EXCEPT (A) PURSUANT TO AN EXEMPTION FROM REGISTRATION UNDER THE SECURITIES ACT AND (B) IN ACCORDANCE WITH ALL APPLICABLE SECURITIES LAWS OF THE STATES OF THE UNITED STATES. IN CONNECTION WITH ANY TRANSFER, THE HOLDER WILL DELIVER TO THE COMPANY AND THE TRUSTEE SUCH CERTIFICATES AND OTHER INFORMATION AS THE TRUSTEE MAY REASONABLY REQUIRE TO CONFIRM THAT THE TRANSFER COMPLIES WITH THE FOREGOING RESTRICTIONS.

MICHIGAN CONSOLIDATED GAS COMPANY

3.92% MORTGAGE BONDS

2012 SERIES D DUE 2042

Principal Amount: $____________

Authorized Denomination: $100,000 or any integral multiple of $1,000 in excess thereof.

Regular Record Date: close of business on the 15th calendar day (whether or not a Business Day) prior to the relevant Interest Payment Date

Original Issue Date: December 12, 2012

Stated Maturity: December 15, 2042

Interest Payment Dates: June 15 and December 15 of each year, beginning June 15, 2013.

Interest Rate: 3.92% per annum

MICHIGAN CONSOLIDATED GAS COMPANY (hereinafter called the “Company”), a corporation of the State of Michigan, for value received, hereby promises to pay to ___________, or registered assigns, the sum of _________ Dollars ($_________) on the Stated Maturity specified above, in the coin or currency of the United States of America, and to pay interest thereon from the Original Issue Date specified above, or from the most recent Interest Payment Date to which interest has been paid or duly provided for, semi-annually in arrears on each Interest Payment Date as specified above, commencing on June 15, 2013 and on the Stated Maturity at the Interest Rate per annum specified above until the principal hereof is paid or made available for payment, and on any overdue principal and Make-Whole Amount (defined below) and, to the extent lawful, on any overdue installment of interest. The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will, as provided in the Indenture, be paid to the person in whose name this bond is registered at the close of business on the Regular Record Date as specified above next preceding such Interest Payment Date; provided that any interest payable at Stated Maturity or on a Redemption Date (defined below) will be paid to the person to whom principal is payable. Except as otherwise provided in the Indenture, any such interest not so punctually paid or duly provided for will forthwith cease to be payable to the holder on such Regular Record Date and may either be paid to the person in whose name this bond is registered at the close of business on a special record date for the payment of such defaulted interest to be fixed by the Trustee, notice whereof shall be given to holders of bonds of this series not less than 10 days prior to such special record date, or be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange, if any,

5

on which the bonds of this series shall be listed, and upon such notice as may be required by any such exchange, all as more fully provided in the Indenture.

Payments of interest on this bond will include interest accrued to but excluding the respective Interest Payment Dates. Interest payments for this bond shall be computed and paid on the basis of a 360-day year consisting of twelve 30-day months. The Company shall pay interest on overdue principal and Make-Whole Amount, if any, and, to the extent lawful, on overdue installments of interest at the rate per annum borne by this bond. In the event that any Interest Payment Date, Redemption Date or Stated Maturity is not a Business Day, then the required payment of principal, Make-Whole Amount, if any, and interest will be made on the next succeeding day that is a Business Day (and without any interest or other payment in respect of any such delay). “Business Day” means any day other than a day on which banking institutions in the State of New York or the State of Michigan are authorized or obligated pursuant to law or executive order to close.

Payment of principal of, Make-Whole Amount, if any, and interest on the bonds of this series shall be made in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts. Payments of principal, Make-Whole Amount, if any, and interest due at the Stated Maturity or earlier redemption of such bonds shall be made at the office of the Trustee upon surrender of such bonds to the Trustee, and (ii) payments of interest shall be made, at the option of the Company, subject to such surrender where applicable, (A) by check mailed to the address of the person entitled thereto as such address shall appear in the bond register of the Trustee maintained for such purpose or (B) by wire transfer at such place and to such account at a banking institution in the United States as may be designated in writing to the Trustee at least fourteen (14) days prior to the date for payment by the person entitled thereto. Notwithstanding the foregoing, so long as any bond is held by an Institutional Investor (as defined in the Bond Purchase Agreement referenced below), payment of principal, Make-Whole Amount, if any, and interest on the bonds held by such holder shall be made in the manner specified in the Bond Purchase Agreement dated as of [November 29], 2012 among the Company and the purchasers party thereto.

The bonds represented by this certificate, of the series hereinafter specified, are bonds of the Company (herein called the “bonds”) known as its “First Mortgage Bonds,” issued and to be issued in one or more series under, and all equally and ratably secured by, an Indenture of Mortgage and Deed of Trust dated as of March 1, 1944, duly executed by the Company to Citibank, N.A., successor trustee (“Trustee”) as restated in Part II of the Twenty-ninth Supplemental Indenture dated as of July 15, 1989, which became effective on April 1, 1994, to which indenture and all indentures supplemental thereto executed on and after July 15, 1989 reference is hereby made for a description of the property mortgaged and pledged, the nature and extent of the security, the terms and conditions upon which the bonds are, and are to be, issued and secured, and the rights of the holders of the bonds and of the Trustee in respect of such security (which indenture and all indentures supplemental thereto, including the Forty-third Supplemental Indenture dated as of December 1, 2012 referred to below, are hereinafter collectively called the “Indenture”). As provided in the Indenture, the bonds may be issued thereunder for various principal sums and are issuable in series, which may mature at different times, may bear interest at different rates and may otherwise vary as therein provided. The bonds represented by this certificate are part of a series designated “3.92% First Mortgage Bonds 2012 Series D,” (herein called the “Bonds”) created by the Forty-third Supplemental Indenture dated as of December 1, 2012 as provided for in said Indenture.

With the consent of the Company and to the extent permitted by and as provided in the Indenture, the rights and obligations of the Company, the rights and obligations of the holders of the Bonds, and the terms and provisions of the Indenture may be modified or altered by such affirmative vote or votes of the holders of the Bonds then outstanding as are specified in the Indenture.

In case an Event of Default as defined in the Indenture shall occur, the principal of the Bonds may become or be declared due and payable in the manner, with the effect, and subject to the conditions provided in the Indenture. Upon any such declaration, the Company shall also pay to the holders of the Bonds the Make-Whole Amount on the Bonds, if any, determined as of the date the Bonds shall have been declared due and payable.

No recourse shall be had for the payment of the principal of, Make-Whole Amount, if any, or the interest on, the Bonds, or for any claim based hereon or otherwise in respect of the Bonds or the Indenture, against any incorporator, stockholder, director or officer, past, present or future, of the Company, as such, or any predecessor or successor corporation, either directly or through the Company or any such predecessor or successor corporation, whether by virtue of any constitution, statute or rule of law, or by the enforcement of any assessment or penalty or otherwise, all such liability, whether at common law, in equity, by any constitution, statute or otherwise, of incorporators, stockholders, directors or officers being waived and released by the owner hereof by the acceptance of the Bonds, and as part of

6

the consideration for the issue thereof, and being likewise waived and released pursuant to the Indenture and the Senior Indenture.

This Bond shall be subject to redemption at the option of the Company, in whole at any time or in part from time to time (any such date of optional redemption, a “Redemption Date”), at an optional redemption price (any such price, a “Redemption Price”) equal to 100% of the principal amount of the Bonds to be redeemed on the Redemption Date together with the Make-Whole Amount (as defined below), if any, plus, in each case, accrued and unpaid interest thereon to the Redemption Date.

Notwithstanding the foregoing, installments of interest on the Bonds that are due and payable on Interest Payment Dates falling on or prior to a Redemption Date will be payable on the Interest Payment Date to the registered Holders as of the close of business on the relevant Record Date.

“Make-Whole Amount” means, with respect to any Bond, an amount equal to the excess, if any, of the Discounted Value of the Remaining Scheduled Payments with respect to the Called Principal of such Bond over the amount of such Called Principal, provided that the Make-Whole Amount may in no event be less than zero. For the purposes of determining the Make-Whole Amount, the following terms have the following meanings:

“Called Principal” means, with respect to a Bond, the principal of the Bond that is to be redeemed on an optional Redemption Date or has become or is declared to be immediately due and payable pursuant to Section 9.01 of the Indenture, as the context requires.

“Discounted Value” means, with respect to the Called Principal of a Bond, the amount obtained by discounting all Remaining Scheduled Payments with respect to such Called Principal from their respective scheduled due dates to the Settlement Date with respect to such Called Principal, in accordance with accepted financial practice and at a discount factor (applied on the same periodic basis as that on which interest on the Bond is payable) equal to the Reinvestment Yield with respect to such Called Principal.

“Reinvestment Yield” means, with respect to the Called Principal of a Bond, 50 basis points plus the yield to maturity implied by (i) the yields reported, as of 10:00 a.m. (New York City time) on the second Business Day preceding the Settlement Date with respect to such Called Principal, on the display designated as “PX-1” (or such other display as may replace Page PX-1), on Bloomberg Financial Markets for the most recently issued, actively traded on-the-run, benchmark U.S. Treasury securities having a maturity equal to the Remaining Average Life of such Called Principal as of such Settlement Date, or (ii) if such yields are not reported as of such time or the yields reported as of such time are not ascertainable (including by way of interpolation), the Treasury Constant Maturity Series Yields reported, for the latest day for which such yields have been so reported as of the second Business Day preceding the Settlement Date with respect to such Called Principal, in Federal Reserve Statistical Release H.15 (519) (or any comparable successor publication) for actively traded U.S. Treasury securities having a constant maturity equal to the Remaining Average Life of such Called Principal as of such Settlement Date. Such implied yield will be determined, if necessary, by (a) converting U.S. Treasury bill quotations to bond-equivalent yields in accordance with accepted financial practice and (b) interpolating linearly on a straight line basis between (1) the most recently issued, actively traded on-the-run, benchmark U.S. Treasury security with the maturity closest to and greater than the Remaining Average Life and (2) the most recently issued, actively traded on-the-run, benchmark U.S. Treasury security with the maturity closest to and less than the Remaining Average Life. The Reinvestment Yield shall be rounded to the number of decimal places as appears in the interest rate of the applicable Bond.

“Remaining Average Life” means, with respect to any Called Principal, the number of years (calculated to the nearest one-twelfth year) obtained by dividing (i) such Called Principal into (ii) the sum of the products obtained by multiplying (a) the principal component of each Remaining Scheduled Payment with respect to such Called Principal by (b) the number of years (calculated to the nearest one-twelfth year) that will elapse between the Settlement Date with respect to such Called Principal and the Stated Maturity of such Remaining Scheduled Payment.

“Remaining Scheduled Payments” means, with respect to the Called Principal of a Bond, all payments of such Called Principal and interest thereon that would be due after the Settlement Date with respect to such Called Principal if no payment of such Called Principal were made prior to its Stated Maturity, provided that if such Settlement Date is not a date on which interest payments are due to be made under the terms of the Senior Note, then the amount of the next succeeding scheduled interest payment will be reduced by the amount of interest accrued to such Settlement Date and required to be paid on such Settlement Date.

7

“Settlement Date” means, with respect to the Called Principal of a Bond, the optional Redemption Date on which such Called Principal is to be redeemed or has become or is declared to be immediately due and payable pursuant to Section 9.01 of the Indenture as the context requires.

Notice of redemption shall be given to the holders of the Bonds to be redeemed not more than 60 nor less than 30 days prior to the Redemption Date, as provided in Section 4.05 of the Indenture. Each such notice shall specify such optional Redemption Date, the aggregate principal amount of the Bonds to be redeemed on such date, the principal amount of each Bond held by such holder to be redeemed, and the interest to be paid on the Redemption Date with respect to such principal amount being prepaid, and shall be accompanied by a certificate of a senior financial officer of the Company as to the estimated Make-Whole Amount due in connection with such redemption (calculated as if the date of such notice were the date of the redemption), setting forth the details of such computation. The Make-Whole Amount shall be determined by the Company two Business Days prior to the applicable Redemption Date and the Company shall deliver to holders of the Bonds and to the Trustee a certificate of a senior financial officer specifying the calculation of such Make-Whole Amount as of the Redemption Date.

Subject to the limitations of Section 4.07 of the Indenture, the notice of redemption may state that it is subject to the receipt of the redemption moneys by the Trustee on or before the Redemption Date, and that such notice shall be of no effect unless such moneys are so received on or before such date; a notice of redemption so conditioned shall be of no force or effect if such money is not so received and, in such event, the Company shall not be required to redeem this Bond.

If the Bonds are only partially redeemed by the Company, the Trustee shall select which Bonds are to be redeemed pro rata among all of the Bonds at the time outstanding in proportion, as nearly as practicable, to the respective unpaid principal amounts thereof and otherwise in accordance with the terms of the Indenture. In the event of redemption of the Bonds in part only, a new Bond or Bonds for the unredeemed portion will be issued in the name or names of the holders thereof upon the surrender or cancellation thereof.

If money sufficient to pay the applicable Redemption Price with respect to the Bonds to be redeemed on the applicable Redemption Date, together with accrued interest to the Redemption Date, is deposited with the Trustee on or before the related Redemption Date and certain other conditions are satisfied, then the Bonds to be redeemed shall no longer be secured by, or entitled to any lien or benefit of, the Indenture as provided by Section 4.04 of the Indenture.

The Indenture contains terms, provisions and conditions relating to the consolidation or merger of the Company with or into, and the conveyance, or other transfer or lease, subject to the lien of the Indenture, of the trust estate to, another corporation, to the assumption by such other corporation, in certain circumstances, of the obligations of the Company under the Indenture and on the Bonds and to the succession of such other corporation in certain circumstances, to the powers and rights of the Company under the Indenture.

The Indenture contains provisions for defeasance at any time of the entire indebtedness of the Bonds or certain covenants with respect thereto upon compliance by the Company with certain conditions set forth therein.

This Bond shall not be valid or become obligatory for any purpose unless and until the certificate of authentication hereon shall have been manually executed by the Trustee or its successor in trust under the Indenture.

IN WITNESS WHEREOF, MICHIGAN CONSOLIDATED GAS COMPANY has caused this certificate to be executed under its name with the signature of its duly authorized Officer, under its corporate seal, which may be a facsimile, attested with the signature of its Corporate Secretary.

Dated:

MICHIGAN CONSOLIDATED GAS COMPANY

By:______________________________

Attest:

By:______________________________________

8

The bonds represented by this certificate constitute Bonds of the series designated and described in the within-mentioned Indenture.

CITIBANK, N.A., as Trustee

By:_________________________________

Authorized Officer

[End of Bond Form]

SECTION 4. Each certificate evidencing the Bonds (and all Bonds issued in exchange therefor or in substitution thereof) shall bear a legend in substantially the following form (each defined term in the legend being defined as such for purposes of the legend only):

THE SECURITIES EVIDENCED HEREBY HAVE NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED (THE “SECURITIES ACT”) AND MAY NOT BE OFFERED, SOLD, PLEDGED OR OTHERWISE TRANSFERRED EXCEPT (A) PURSUANT TO AN EXEMPTION FROM REGISTRATION UNDER THE SECURITIES ACT AND (B) IN ACCORDANCE WITH ALL APPLICABLE SECURITIES LAWS OF THE STATES OF THE UNITED STATES. IN CONNECTION WITH ANY TRANSFER, THE HOLDER WILL DELIVER TO THE COMPANY AND THE TRUSTEE SUCH CERTIFICATES AND OTHER INFORMATION AS THE TRUSTEE MAY REASONABLY REQUIRE TO CONFIRM THAT THE TRANSFER COMPLIES WITH THE FOREGOING RESTRICTIONS.

The Bonds shall be exchangeable upon surrender thereof at the corporate trust office of the Trustee in the Borough of Manhattan, the City of New York, New York, for registered bonds of the same aggregate principal amount and other terms, but of different authorized denomination or denominations, such exchanges to be made without service charge (except for any stamp tax or other governmental charge).

When Bonds are presented to the Trustee with a request (i) to register the transfer of such Bonds; or (ii) to exchange such Bonds for Bonds of the same series of any authorized denominations of the same aggregate principal amount and Stated Maturity, the Trustee shall register the transfer or make the exchange as requested if its reasonable requirements for such transaction are met; provided, however, that the Bonds surrendered for transfer or exchange: (A) shall be duly endorsed or be accompanied by a written instrument of transfer in form reasonably satisfactory to the Company and the Trustee, duly executed by the holder thereof or his attorney duly authorized in writing; and (B) are accompanied by the following additional information and documents, as applicable: (x) if such Bonds are being delivered to the Company by a holder for registration in the name of such holder, without transfer, a certification from such holder to that effect; or (y) if such Bonds are being transferred to the Company, a certification to that effect; or (z) if such Bonds are being transferred pursuant to an exemption from registration in accordance with Rule 144 under the Securities Act or in reliance upon another exemption from the registration requirements of the Securities Act, (i) a certification to that effect and (ii) if the Company so requests, other evidence reasonably satisfactory to it as to the compliance with the restrictions set forth in the legend set forth above.

Every Bond so surrendered shall be accompanied by a proper transfer power duly executed by the registered owner or by a duly authorized attorney transferring such Bond to the Company, and the signature to such transfer power shall be guaranteed to the satisfaction of the Trustee. All Bonds so surrendered shall be forthwith canceled and delivered to or upon the order of the Company. All Bonds executed, authenticated and delivered in exchange for Bonds so surrendered shall be valid obligations of the Company, evidencing the same debt as the Bonds surrendered, and shall be secured by the same lien and be entitled to the same benefits and protection as the Bonds in exchange for which they are executed, authenticated and delivered.

The Company shall not be required to make any such exchange or any registration of transfer after the Bond so presented for exchange or registration of transfer, or any portion thereof, has been called for redemption and notice thereof given to the registered owner.

SECTION 5. Pending the preparation of definitive Bonds, the Company may from time to time execute, and upon its written order, the Trustee shall authenticate and deliver, in lieu of such definitive Bonds and subject to the same provisions, limitations and conditions, one or more temporary Bonds, in registered form, of any denomination specified in the written order of the Company for the authentication and delivery thereof, and with such omissions, insertions and variations as may be determined by the Board of Directors of the Company. Such temporary Bonds shall be substantially of the tenor of the Bonds to be issued as herein before recited.

9

If any such temporary Bonds shall at any time be so authenticated and delivered in lieu of definitive Bonds, the Company shall upon request at its own expense prepare, execute and deliver to the Trustee and thereupon, upon the presentation and surrender of temporary Bonds, the Trustee shall authenticate and deliver in exchange therefor, without charge to the holder, definitive Bonds of the same series and other terms, if any, and for the same principal sum in the aggregate as the temporary Bonds surrendered. All temporary Bonds so surrendered shall be forthwith canceled by the Trustee and delivered to or upon the order of the Company. Until exchanged for definitive Bonds the temporary Bonds shall in all respects be entitled to the lien and security of the Indenture and all supplemental indentures.

ARTICLE III

ISSUE OF BONDS

Bonds in the aggregate principal amount of $70,000,000 may be executed, authenticated and delivered from time to time as permitted by the provisions of the Indenture, including with respect to exchange and replacement of bonds.

ARTICLE IV

THE TRUSTEE

The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or the due execution hereof by the Company, or for or in respect of the recitals and statements contained herein, all of which recitals and statements are made solely by the Company.

Except as herein otherwise provided, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this Supplemental Indenture other than as set forth in the Indenture and this Supplemental Indenture is executed and accepted on behalf of the Trustee, subject to all the terms and conditions set forth in the Indenture, as fully to all intents as if the same were herein set forth at length.

ARTICLE V

RECORDING AND FILING OF SUPPLEMENTAL INDENTURE

DATED AS OF DECEMBER 1, 2008

Pursuant to the terms and provisions of the Original Indenture, a Supplemental Indenture dated as of December 1, 2008 providing for the terms of Collateral Bonds to be issued thereunder designated as 2008 Series M Collateral Bonds has heretofore been entered into between the Company and the Trustee and has been filed in the Office of the Secretary of State of Michigan as a financing statement on December 18, 2008 (Filing No. 2008192835-8) and has been recorded as a real estate mortgage in the offices of the respective Register of Deeds of certain counties in the State of Michigan, as follows:

County	Recorded	Liber/ Instrument no.	Page
Alcona	12/18/2008	457	1,179
Alger	12/19/2008	200,802,530	N/A
Alpena	12/18/2008	468	752
Antrim	12/18/2008	787	161
Arenac	12/19/2008	541	397
Barry	12/18/2008	20081218-0011905	N/A
Benzie	12/19/2008	2008R-06000	N/A
Charlevoix	12/18/2008	870	108
Cheboygan	12/18/2008	1,113	319
Chippewa	12/18/2008	1,061	1,104
Clare	12/18/2008	1,098	421
Clinton	12/18/2008	5,138,324	N/A
Crawford	12/18/2008	694	163
Delta	12/18/2008	934	639
Dickinson	12/18/2008	666	298
Emmet	12/19/2008	1,108	229

10

Gladwin	12/18/2008	884	149
Grand Traverse	12/18/2008	2008R-20772	N/A
Gratiot	12/18/2008	859	325
Ionia	12/18/2008	610	4,870
Iosco	12/18/2008	964	831
Iron	12/22/2008	527	381
Isabella	12/18/2008	1,458	934
Jackson	12/18/2008	1,911	985
Kalkaska	12/18/2008	3,088,554	N/A
Kent	12/18/2008	20081218-0107096	N/A
Lake	12/18/2008	330	428
Leelanau	12/18/2008	994	42
Lenawee	12/18/2008	2,375	787
Livingston	12/18/2008	2008R-034272	N/A
Macomb	12/22/2008	19,596	321
Manistee	12/18/2008	2008R007308	N/A
Marquette	12/18/2008	2008R-13188	N/A
Mason	12/18/2008	2008R06709	N/A
Mecosta	12/18/2008	783	116
Menominee	12/18/2008	645	953
Missaukee	12/18/2008	2008-04411	N/A
Monroe	12/18/2008	2008R22568	N/A
Montcalm	12/18/2008	1,426	1,019
Montmorency	12/18/2008	305	636
Muskegon	12/18/2008	3,798	74
Newaygo	12/18/2008	433	3,732
Oakland	12/22/2008	40,780	854
Oceana	12/18/2008	GR 2008	24,720
Ogemaw	12/18/2008	3,083,443	N/A
Osceola	12/18/2008	868	262
Oscoda	12/18/2008	208-0305417	N/A
Otsego	12/18/2008	1,187	289
Ottawa	1/13/2009	5,766	282
Presque Isle	12/18/2008	470	86
Roscommon	12/19/2008	1,079	343
St. Clair	12/18/2008	3,899	806
Saginaw	12/18/2008	2,517	565
Shiawassee	12/18/2008	1,130	861
Washtenaw	12/18/2008	4,710	676
Wayne	2/19/2009	47,721	959
Wexford	12/18/2008	616	1,643

ARTICLE VI

MISCELLANEOUS PROVISIONS

Except insofar as herein otherwise expressly provided, all the provisions, terms and conditions of the Indenture shall be deemed to be incorporated in, and made a part of, this Forty-third Supplemental Indenture, and the Twenty-ninth Supplemental Indenture dated as of July 15, 1989, as supplemented by the Thirtieth Supplemental Indenture dated as of September 1, 1991, by the Thirty-first Supplemental Indenture dated as of December 15, 1991, by the Thirty-second Supplemental Indenture dated as of January 5, 1993, by the Thirty-third Supplemental Indenture dated

11

as of May 1, 1995, by the Thirty-fourth Supplemental Indenture dated as of November 1, 1996, by the Thirty-fifth Supplemental Indenture dated as of June 18, 1998, by the Thirty-sixth Supplemental Indenture dated as of August 15, 2001, by the Thirty-seventh Supplemental Indenture dated as of February 15, 2003, by the Thirty-eighth Supplemental Indenture dated as of October 1, 2004, by the Thirty-ninth Supplemental Indenture dated as of April 1, 2008, by the Fortieth Supplemental Indenture dated as of June 1, 2008, by the Forty-first Supplemental Indenture dated as of August 1, 2008, by the Forty-second Supplemental Indenture dated as of December 1, 2008 and by this Supplemental Indenture is in all respects ratified and confirmed; and the Indenture and said Supplemental Indentures shall be read, taken and construed as one and the same instrument.

Except to the extent specifically provided therein, no provision of this Supplemental Indenture or any future supplemental indenture is intended to modify, and the parties do hereby adopt and confirm, the provisions of Section 318(c) of the Trust Indenture Act, which amend and supersede provisions of the Indenture in effect prior to November 15, 1990.

Nothing in this Supplemental Indenture is intended, or shall be construed, to give to any person or corporation, other than the parties hereto and the holders of Bonds issued and to be issued under and secured by the Indenture, any legal or equitable right, remedy or claim under or in respect of this Supplemental Indenture, or under any covenant, condition or provision herein contained, all the covenants, conditions and provisions of this Supplemental Indenture being intended to be, and being, for the sole and exclusive benefit of the parties hereto and of the holders of bonds issued and to be issued under the Indenture and secured thereby.

All covenants, promises and agreements in this Supplemental Indenture contained by or on behalf of the Company shall bind its successors and assigns whether so expressed or not.

This Supplemental Indenturemay be executed in any number of counterparts, and each of such counterparts when so executed shall be deemed to be an original; but all such counterparts shall together constitute but one and the same instrument.

IN WITNESS WHEREOF, MICHIGAN CONSOLIDATED GAS COMPANY has caused this Supplemental Indenture to be executed by its duly authorized Officer, and its corporate seal to be hereunto affixed, and Citibank, N.A., as Trustee as aforesaid, has caused the same to be executed by one of its authorized signatories and its corporate seal to be hereunto affixed, on the respective dates of their acknowledgments hereinafter set forth, as of the date and year first above written.

MICHIGAN CONSOLIDATED GAS COMPANY

By:/s/Donald J. Goshorn

Donald J. Goshorn

Assistant Treasurer

Signed, sealed, acknowledged and

delivered by MICHIGAN CONSOLIDATED

GAS COMPANY in the presence of:

/s/ Daniel T. Richards

Daniel T. Richards

/s/ Kathleen Hier

Kathleen Hier

State of Michigan}

} ss.

County of Wayne}

The foregoing instrument was acknowledged before me this 6th day of December, 2012, by Donald J. Goshorn, as Assistant Treasurer, of Michigan Consolidated Gas Company, a Michigan corporation, on behalf of the corporation.

12

/s/Jennifer Evans

Jennifer Evans

Notary Public, Wayne County, MI

Acting in Wayne County, MI

My Commission Expires: December 28, 2016

Citibank, N.A., as Trustee

By:/s/ Wafaa Orfy

Wafaa Orfy

Vice President

Signed, sealed, acknowledged and

delivered by CITIBANK, N.A.

in the presence of:

/s/ Louis Piscitelli

Name: Louis Piscitelli

Vice President

/s/ Cirino Emanuele

Name: Cirino Emanuele

Vice President

State of New York}

} ss.

County of New York}

The foregoing instrument was acknowledged before me this 6th day of December, 2012, by Wafaa Orfy, as Vice President of Citibank, N.A., a national banking association, on behalf of the association, as Trustee, as in said instrument described.

Noreen Iris Santos

Notary Public, State of New York

No. 01SA6228750

Qualified in Kings County

Acting in New York County

Commission Expires: September 27, 2014

This instrument was drafted by:

Daniel T. Richards

One Energy Plaza, 688WCB

Detroit, MI 48226

When recorded return to:

Jennifer Evans

One Energy Plaza, 688WCB

Detroit, MI 48226

13

EX-10.81

Exhibit 10-81

First Amendment to DTE Supplemental Savings Plan Restated Effective January 1, 2005 - Page 3 of 3

FIRST AMENDMENT TO THE

DTE ENERGY COMPANY

SUPPLEMENTAL SAVINGS PLAN

(Amended and Restated Effective January 1, 2005)

Recitals

As authorized by resolutions adopted by the DTE Energy Benefit Plan Administration Committee on November 13, 2012, the DTE Energy Company Supplemental Savings Plan (Amended and Restated Effective January 1, 2005), is amended as follows:

1.    Effective January 1, 2012, Section 2.1 is amended to read as follows:

2.1    Post-2004 Account. “Post-2004 Account” means the portion of a Participant's Account attributable to credits and debits made to the Participant's Account under Sections 4.2(a), (b), and (c) after December 31, 2004, and earnings credited or losses debited to the Participant's Account under Section 4.2 attributable to these Section 4.2(a), (b), and (c) credits and debits.

2.    Effective January 1, 2012, Sections 3.1 and 3.2 are amended to read as follows:

3.1.    Eligibility to Participate.

(a)    Only the following individuals are eligible to participate in the Plan:

(1)    any Executive or

(2)    other management or highly compensated Employees as shall be approved by the Chief Executive Officer of an Employer that has adopted the Plan

whose Before-Tax Contributions, Matching Contributions, or Employer Contributions under the Qualified Plan are limited because of the limitation on compensation under Section 401(a)(17) of the Code, the limitation on elective deferrals under Section 402(g) of the Code, the limitation on benefits and contributions under Section 415 of the Code, or any other provision of the Code or other law that the Committee hereafter designates.

(b)    Effective Date for Participation. Each employee of the Company and Participating Affiliated Companies who is employed at the level of Director or above (or equivalent) and who is designated as an Executive shall be eligible to participate in the Plan effective as of the later of (i) the date determined by the Vice President, Human Resources, or (ii) the date on which the employee is formally notified of his or her eligibility to participate.

(c)    Determination of Executive Status. The Vice President, Human Resources shall designate employees as Executives. The Vice President, Human Resources may revoke such designation prior to any Plan Year with respect to the Executive's ability to defer future compensation payable by the Company or Participating Affiliated Company or to receive Employer Contributions. However, no revocation can adversely affect any amounts previously electively deferred by the Executive under the Plan or otherwise credited to the Executive's Account under the Plan.

(d)    Mid-Year Participation. An employee who is designated as an Executive and wishes to defer compensation under the Plan for the Plan Year in which the employee is so designated must file a written election with the Committee within 30 days of the date the employee is formally notified of his or her eligibility to participate. Failure to file a written election before the end of this 30-day period precludes the Executive from deferring compensation under the Plan until the beginning of the next Plan Year.

3.2.    Election to Participate.

(a)    Compensation Deferral. An Executive who is eligible to defer compensation may make compensation deferrals under the Plan by filing a written election with the Committee on a form approved by the Committee. The Executive's election must authorize the Employer to defer the designated amount of the Executive's Compensation under Section 4.2(a) and evidence the Executive's acceptance of and agreement to all the provisions of the Plan.

The Executive's election must be made no later than December 31 of the year that immediately precedes the year for which it applies. However, the first election by any Executive to participate in this Plan shall be effective for any Compensation earned after the election is received by the Committee and after contributions to the Qualified Plan are limited in accordance with Section 3.1 above. An election shall be irrevocable for the current calendar year. An election shall be irrevocable for future calendar years unless a written revocation is filed with the Committee prior to the first day of the calendar year for which the revocation is desired.

(b)    Employer Contributions. An Executive is not required to file a written election in order to participate in the Plan with respect to amounts credited to the Executive's Account under Section 4.2(c). Credits will be made to the Executive's Account under Section 4.2(c) automatically.

3.    Effective January 1, 2012, Sections 4.1, 4.2, and 4.3are amended to read as follows:

4.1.    Establishment of Accounts. The Employer will establish accounts for each of its Executives who is a Participant in the Plan. Separate hypothetical bookkeeping accounts corresponding in name to the separate funds under the Qualified Plan shall be maintained for each Participant. Credits under Sections 4.2(a), (b), and (c) will also be maintained in separate accounts. The hypothetical bookkeeping accounts will be maintained as unfunded general bookkeeping accounts and all amounts represented by the accounts remain a part of the general funds of the Employer of the Participant, subject to the claims of the Employer's general creditors. Nothing in the Plan and no action taken under the Plan is deemed to create a trust or fund of any kind or to create any fiduciary relationship. The obligation to make payments under this Plan is and remains an unsecured, unfunded general obligation of the Employer of the particular Participant. Each Executive who is a Participant in the Plan will be provided a quarterly statement of the unfunded accounts maintained for the Participant.

4.2.    Credits and Debits to Participants' Accounts. As of the end of a pay period, the following credits will be made to the hypothetical bookkeeping accounts maintained for a Participant:

(a)    An amount equal to the difference between (1) and (2) below:

(1)    the amount that the Participant would have contributed to the Qualified Plan as Before-Tax Contributions for the pay period if the Before-Tax Contributions by the Participant under the Qualified Plan were not limited by any of the restrictions in Section 3.1(a) or any provision of the Qualified Plan relating to the limitations in Section 3.1(a); and

(2)    the amount the Participant actually contributed to the Qualified Plan as Before-Tax Contributions for the pay period.

(b)    An amount equal to the difference between (1) and (2) below:

(1)    the amount that the Employer of the Participant would have contributed to the Qualified Plan as Matching Contributions on behalf of the Participant for the pay period if the Participant had contributed to the Qualified Plan the amount set forth in Section 4.2(a)(1) during the pay period; and

(2)    the amount that the Employer actually contributed to the Qualified Plan as Matching Contributions on behalf of the Participant for the pay period.

(c)    An amount equal to the difference between (1) and (2) below:

(1)    the amount that the Employer of the Participant would have contributed to the Qualified Plan as Employer Contributions on behalf of the Participant for the pay period if the Employer Contributions under the Qualified Plan were not limited by any of the restrictions in Section 3.1(a) or any provision of the Qualified Plan relating to the limitations in Section 3.1(a); and

(2)    the amount the Employer actually contributed to the Qualified Plan as Employer Contributions on behalf of the Participant for the pay period.

The total credits under Sections 4.2(a), (b), and (c) will be allocated to the specific investment accounts elected by the Participant under Section 4.3. Each hypothetical bookkeeping investment account will be credited with an amount representing earnings or debited with an amount representing losses on a daily basis. Earnings or losses will be calculated using the same valuation methodology employed by the recordkeeper for each corresponding investment option under the Qualified Plan.

4.3.    Election of Investment Accounts. Subject to the sole discretion of the Committee, each Participant will, by filing an election with the Committee in a form approved by the Committee, elect the investment accounts which are to be used for recording credits under Sections 4.2(a), (b), and (c).

A Participant may direct that credits under Sections 4.2(a), (b), and (c) be made to any investment account corresponding in name to the investment options under the Qualified Plan that are available to accept contributions or allotments. However, the Committee may change available investment accounts or override a Participant's investment account election at any time.

4.    Effective January 1, 2012, Section 6.1(b) is amended by replacing the second paragraph following Subsection (b)(2)(C)(ii) with the following:

A Participant may elect to have the Participant's Post-2004 Account paid in annual payments over a period of not less than two years and not more than 15 years, or in one lump sum, by making an election within 30 days of the date the Participant is first formally notified of his or her eligibility to participate in the Plan and receive credits under either Section 4.2(a) or Section 4.2(c). If a Participant does not elect a form of payment for the Participant's Post-2004 Account within 30 days of the Participant's initial eligibility, the Participant's entire Post-2004 Account will be paid in one lump sum. Any election by a Participant after December 31, 2008 regarding the form in which the Participant's Post-2004 Account will be distributed will apply to the Participant's entire Post-2004 Account and is subject to the restrictions imposed by Section 6.2 on changes to elections of timing or form of distributions.

5.    Effective January 1, 2013, Section 4.2(b) is amended to read as follows:

(b)    An amount equal to the difference between (1) and (2) below:

(1)    the amount that the Employer of the Participant would have contributed to the Qualified Plan as Matching Contributions on behalf of the Participant for the pay period if the Participant had contributed to the Qualified Plan the amount set forth in Section 4.2(a)(1) during the pay period plus any After-Tax Contributions and Roth Contributions actually contributed to the Qualified Plan by the Participant during the pay period; and

(2)    the amount that the Employer actually contributed to the Qualified Plan as Matching Contributions on behalf of the Participant for the pay period.

This Amendment is executed on behalf of the Committee by its Chairperson, as authorized by the Committee's resolution.

Dated: November 13, 2012

__________________________________________

Larry E. Steward

Vice President, Human Resources

Committee Chairperson

EX-12.52

Exhibit 12-52

DTE ENERGY COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
	Twelve Months Ended December 31
(Millions of Dollars)	2012		2011	2010	2009	2008
Earnings:
Pretax earnings	1,035		989	968	778	518
Adjustments	(4	)	6	1	4	(3	)
Fixed Charges	463		520	567	572	540
Net earnings	1,494		1,515	1,536	1,354	1,055
Fixed Charges:
Interest expense	441		490	543	545	503
Adjustments	22		30	24	27	37
Fixed Charges	463		520	567	572	540
Ratio of earnings to fixed charges	3.23		2.91	2.71	2.37	1.95

EX-21.8

Exhibit 21-8

SUBSIDIARIES OF DTE ENERGY COMPANY

DTE Energy Company’s principal subsidiaries as of December 31, 2012 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. DTE Electric Company	Michigan
2. DTE Enterprises, Inc.	Michigan
3. DTE Gas Holdings, Inc.	Michigan
4. DTE Gas Company	Michigan

EX-23.26

Exhibit 23-26

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S‑3 (Nos. 333-183442 and 333-157769) and Form S‑8 (Nos. 333-183440, 333-133645, 333-157768, 333-109623 and 333-47247) of DTE Energy Company of our report dated February 20, 2013 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 20, 2013

EX-31.79

Exhibit 31-79

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 20, 2013
Gerard M. Anderson Chairman of the Board, President and Chief Executive Officer of DTE Energy Company

EX-31.80

Exhibit 31-80

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 20, 2013
David E. Meador Executive Vice President and Chief Financial Officer of DTE Energy Company

EX-32.79

Exhibit 32-79

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, 2012, 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 20, 2013	/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-32.80

Exhibit 32-80

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, 2012, 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 20, 2013	/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.

XML

Goodwill (Tables)

12 Months Ended

Dec. 31, 2012

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill [Table Text Block]

	2012			2011
	(In millions)
Balance as of January 1	$	2,020		$	2,020
Goodwill attributable to sale of Unconventional Gas Production business	(2		)	—
Balance at December 31	$	2,018		$	2,020

XML

Segment Information (Details Textuals)	Dec. 31, 2012 customers
Entity Information [Line Items]
Number of Electric Customers	2,100,000
Number of Gas Customers	1,200,000
Number of Citizens Gas Customers	17,000

XML

Retirement Benefits and Trusteed Assets (Details) (Pension Plans, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 82	$ 69	$ 64
Interest cost	204	202	202
Expected return on plan assets	(244)	(246)	(258)
Amortization of: [Abstract]
Net actuarial loss	176	142	100
Prior service cost	0	3	4
Special termination benefits	2	2	0
Net pension cost	$ 220	$ 172	$ 112

XML

Stock-Based Compensation (Tables)

3 Months Ended

12 Months Ended

Dec. 31, 2011

Dec. 31, 2012

Share-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:

	2012		2011		2010
	(In millions)
Stock-based compensation expense	$	83	$	66	$	52
Tax benefit	33		25		20
Stock-based compensation cost capitalized in property, plant and equipment	5		4		3

Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]

Stock option activity was as follows:

	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In millions)
Options outstanding at January 1, 2012	2,764,670		$	41.25
Granted	—		$	—
Exercised	(1,555,227	)	$	40.78
Forfeited or expired	(16,773	)	$	42.02
Options outstanding at December 31, 2012	1,192,670		$	41.86	$	22
Options exercisable at December 31, 2012	991,826		$	41.44	$	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	142,619	$	27.98	6.15
$	38.01	—	$	42.00	291,982	$	41.14	3.22
$	42.01	—	$	45.00	605,569	$	44.03	5.40
$	45.01	—	$	50.00	152,500	$	47.62	4.03
					1,192,670	$	41.86	4.78

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]

	2010
Risk-free interest rate	2.91	%
Dividend yield	5.08	%
Expected volatility	22.96	%
Expected life	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:

	2012		2011		2010
Fair value of awards vested (in millions)	$	9	$	13	$	19
Restricted common shares awarded	167,320		381,840		238,405
Weighted average market price of shares awarded	$	53.71	$	47.98	$	44.08
Compensation cost charged against income (in millions)	$	12	$	12	$	12

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, 2012:

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at January 1, 2012	726,224		$	42.25
Grants	167,320		$	53.71
Forfeitures	(37,767	)	$	48.46
Vested and issued	(258,129	)	$	34.41
Balance at December 31, 2012	597,648		$	48.33

Share Based Compensation Expense [Table Text Block]

The Company recorded compensation expense as follows:

	2012		2011		2010
	(In millions)
Compensation expense	$	71	$	53	$	36
Cash settlements (a)	$	4	$	3	$	3
Stock settlements (a)	$	41	$	25	$	23

Summary of Performance Share Activity [Table Text Block]

The following table summarizes the Company’s performance share activity for the period ended December 31, 2012:

	Performance Shares
Balance at January 1, 2012	1,608,733
Grants	590,098
Forfeitures	(59,712	)
Payouts	(504,755	)
Balance at December 31, 2012	1,634,364

Schedule of Unrecognized Compensation Cost, Nonvested Awards [Table Text Block]

	Unrecognized Compensation Cost		Weighted Average to be Recognized
	(In millions)		(In years)
Options	$	—	0.15
Stock awards	11		1.02
Performance shares	47		1.46
	$	58	1.37

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2012

Long-term Debt, Unclassified [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]

	2012			2011
	(In millions)
Mortgage bonds, notes, and other
DTE Energy Debt, Unsecured
5.4% due 2013 to 2033	$	1,298		$	1,298
DTE Electric Taxable Debt, Principally Secured
5.0% due 2013 to 2042	3,777			3,515
DTE Electric Tax-Exempt Revenue Bonds (b)
5.3% due 2014 to 2038	707			893
DTE Gas Taxable Debt, Principally Secured
5.6% due 2013 to 2042	919			889
Other Long-Term Debt, Including Non-Recourse Debt	153			165
	6,854			6,760
Less amount due within one year	(634		)	(355		)
	$	6,220		$	6,405
Securitization bonds
6.6% due 2013 to 2015	$	479		$	643
Less amount due within one year	(177		)	(164		)
	$	302		$	479
Junior Subordinated Debentures
6.5% due 2061	$	280		$	280
5.25% due 2062	200			—
	$	480		$	280

Schedule of Issued Debt [Table Text Block]

Company	Month Issued	Type	Interest Rate		Maturity	Amount
	(In millions)
DTE Electric	June	Mortgage Bonds (a)	2.65	%	2022	$	250
DTE Electric	June	Mortgage Bonds (a)	3.95	%	2042	250
DTE Energy	October	Junior Subordinated Debentures (b)	5.25	%	2062	200
DTE Gas	December	Mortgage Bonds (c)	3.92	%	2042	70
						$	770

Schedule of Extinguishment of Debt [Table Text Block]

Company	Month	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March/September	Securitization Bonds	6.42	%	2012	$	164
DTE Electric	April	Mortgage Bonds	7.90	%	2012	10
DTE Electric	April	Mortgage Bonds	8.36	%	2012	3
DTE Gas	May	Secured Medium Term Notes	7.06	%	2012	40
DTE Electric	July	Senior Notes	5.20	%	2012	225
DTE Electric	December	Tax Exempt Revenue Bonds (a)	3.05	%	2024	65
DTE Electric	December	Tax Exempt Revenue Bonds (a)	5.45	%	2032	64
DTE Electric	December	Tax Exempt Revenue Bonds (a)	5.25	%	2032	56
DTE Energy	Various	Other Long-Term Debt	Various		2012	12
						$	639

_______________________________________

Schedule of Maturities of Long-term Debt [Table Text Block]

	2013		2014		2015		2016		2017		2018 and Thereafter		Total
	(In millions)
Amount to mature	$	811	$	891	$	476	$	465	$	9	$	5,166	$	7,818

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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, 2012	Dec. 31, 2011
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Defined Benefit Plans, Liabilities	$ (1,162)	$ (1,485)
Net actuarial loss	(34)	195
Amortization of net actuarial loss	(80)	(55)
Prior service credit	(264)	(4)
Amortization of prior service cost	27	26
Amortization of transition asset	(2)	(2)
Total recognized Regulatory assets and Other comprehensive income	(353)	160
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive icnome	(202)	282
Net actuarial loss	69	78
Prior service credit	(91)	(27)
Net transition obligation	$ 0	$ 2

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Fair Value (Details 5) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	$ 1,037	$ 937
Fermi 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	1,021	915
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	$ 13	$ 19

XML

Retirement Benefits and Trusteed Assets (Details 12) (Other Postretirement Benefit Plans, Defined Benefit [Member])	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Other Postretirement Benefit Plans, Defined Benefit [Member]
Assumptions Used to Determine Projected Benefit Obligation and Benefit Costs [Line Items]
Discount rate	4.15%	5.00%	5.50%
Discount Rate	5.00%	5.50%	5.90%
Expected long-term rate of return on plan assets	8.25%	8.75%	8.75%
Health care trend rate pre and post 65	7.00%	7.00%	7.00%	7.00%
Ultimate health care trend rate	5.00%	5.00%	5.00%	5.00%

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2012

Supplemental Cash Flow Elements [Abstract]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

	2012			2011			2010
	(In millions)
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	52		$	71		$	79
Inventories	35			(129		)	(133		)
Recoverable pension and postretirement costs	141			(620		)	(32		)
Accrued/prepaid pensions	280			432			67
Accounts payable	40			(23		)	12
Income taxes payable/receivable	30			249			(245		)
Derivative assets and liabilities	53			(94		)	(48		)
Postretirement obligation	(323		)	209			(24		)
Regulatory assets	122			38			(37		)
Other assets	117			(28		)	(15		)
Other liabilities	(105		)	(11		)	83
	$	442		$	94		$	(293	)

Additional Supplementary Cash Flow Information [Table Text Block]

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

	2012		2011			2010
	(In millions)
Cash paid (received) for:
Interest (net of interest capitalized)	$	438	$	485		$	551
Income taxes	$	173	$	(205	)	$	93

Schedule of Other Significant Noncash Transactions [Table Text Block]

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

	2012		2011		2010
	(In millions)
Common stock issued for employee benefit plans	$	114	$	1	$	156
Change in capital expenditures not paid	$	23	$	76	$	20

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Goodwill (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Goodwill [Line Items]
Balance as of January 1	$ 2,020	$ 2,020
Goodwill attributable to sale of subsidiary in Power and Industrial Projects segment	(2)	0
Balance as of December 31	$ 2,018	$ 2,020

XML

Preferred and Preferenced Securities (Details) (USD $)	Dec. 31, 2012
DTE Energy [Member]
Preferred and Preferenced Securities [Line Items]
Preferred	$ 0
Preferred	5,000,000
DTE Electric [Member]
Preferred and Preferenced Securities [Line Items]
Preferred	$ 100
Preferred	6,747,484
Preference	$ 1
Preference	30,000,000
DTE Gas [Member]
Preferred and Preferenced Securities [Line Items]
Preferred	$ 1
Preferred	7,000,000
Preference	$ 1
Preference	4,000,000

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

	2012			2011			2010
	(In millions)
Income before income taxes	$	960		$	991		$	962
Income tax expense at 35% statutory rate	$	336		$	347		$	337
Production tax credits	(49		)	(6		)	(33		)
Investment tax credits	(6		)	(6		)	(6		)
Depreciation	(4		)	(4		)	(4		)
Employee Stock Ownership Plan dividends	(4		)	(4		)	(5		)
Domestic production activities deduction	(14		)	(7		)	(7		)
Settlement of Federal tax audit	—			—			(12		)
State and local income taxes, net of federal benefit	37			37			44
Enactment of Michigan Corporate Income Tax, net of federal expense	—			(87		)	—
Other, net	(10		)	(2		)	1
Income tax expense	$	286		$	268		$	315
Effective income tax rate	29.8		%	27.0		%	32.7		%

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

Components of income tax expense were as follows:

	2012			2011			2010
Current income tax expense (benefit)	(In millions)
Federal	$	190		$	27		$	(168	)
State and other income tax	49			21			26
Total current income taxes	239			48			(142		)
Deferred income tax expense (benefit)
Federal	39			318			415
State and other income tax	8			(98		)	42
Total deferred income taxes	47			220			457
Total income taxes from continuing operations	286			268			315
Discontinued operations	(29		)	(1		)	(4		)
Total	$	257		$	267		$	311

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

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

	2012			2011
	(In millions)
Property, plant and equipment	$	(3,389	)	$	(3,131	)
Securitized regulatory assets	(256		)	(360		)
Alternative minimum tax credit carry-forwards	254			294
Merger basis differences	42			50
Pension and benefits	(33		)	(39		)
Other comprehensive income	101			99
Derivative assets and liabilities	66			64
State net operating loss and credit carry-forwards	37			30
Other	41			(45		)
	(3,137		)	(3,038		)
Less valuation allowance	(33		)	(27		)
	$	(3,170	)	$	(3,065	)
Current deferred income tax assets	$	21		$	51
Long-term deferred income tax liabilities	(3,191		)	(3,116		)
	$	(3,170	)	$	(3,065	)
Deferred income tax assets	$	1,038		$	1,048
Deferred income tax liabilities	(4,208		)	(4,113		)
	$	(3,170	)	$	(3,065	)

Unrecognized Tax Benefits [Table Text Block]

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

	2012			2011			2010
	(In millions)
Balance at January 1	$	48		$	28		$	81
Additions for tax positions of prior years	—			27			4
Reductions for tax positions of prior years	(2		)	(4		)	(4		)
Additions for tax positions of current year	1			1			—
Settlements	(30		)	(3		)	(53		)
Lapse of statute of limitations	(6		)	(1		)	—
Balance at December 31	$	11		$	48		$	28

XML

Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2012

Valuation and Qualifying Accounts [Abstract]

Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]

Valuation and Qualifying Accounts

	Year Ending December 31,
	2012			2011			2010
	(In millions)
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statements of Financial Position)
Balance at Beginning of Period	$	162		$	196		$	262
Additions:
Charged to costs and expenses	79			94			113
Charged to other accounts (a)	16			18			20
Deductions (b)	(195		)	(146		)	(199		)
Balance at End of Period	$	62		$	162		$	196

_______________________________________

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

XML

Acquisition Acquisition (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2012 facilities
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Number of Businesses Acquired	14
Business Acquisition, Cost of Acquired Entity, Cash Paid	$ 220,000,000
Business Acquisition, Purchase Price Allocation, Liabilities Assumed	74,000,000
Business Acquisition, Cost of Acquired Entity, Purchase Price	294,000,000
Number of Acquired Business's are VIEs - Parent is not Primary Beneficiary	2
Exposure Loss Related to the Debt Assumed	0
Business Acquisition, Purchase Price Allocation, Amortizable Intangible Assets	75,000,000
Amortization Years for Intangible Assets Acquired in a Business Combination	8 years
Revenues of Acquired Business Included in the Company's Consolidated Statement of Operations	30,000,000
Earnings of Acquired Business Included in the Company's Consolidated Statements of Operations	$ 2,000,000
The Period of the Acquired Project Companies Following the Colsing	3 months
Maximum [Member]
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Equity Method Investment, Ownership Percentage	100.00%
Minimum [Member]
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Equity Method Investment, Ownership Percentage	46.00%

XML

Retirement Benefits and Trusteed Assets (Details 6) (Pension Plans, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 3,223	$ 2,886	$ 2,913
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	1,667	1,469
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	1,038	953
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	518	464
Short-term investments [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	24	33
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	24	33
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	732	680
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	688	640
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	44	40
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	158	164
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	153	159
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	5
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	650	506
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	530	392
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	120	114
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	852	791
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	87	88
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	765	703
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	628	544
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	209	190
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	80	58
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	339	296
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	179	168
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	$ 179	$ 168

XML

Retirement Benefits and Trusteed Assets Retirement Benefits and Trusteed Assets (Details 15) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	$ 44	$ 59
Realized gains (losses)	60	87
Purchases	2	3
Ending Balance	(13)	44
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	58	75
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	155	134
Realized gains (losses)	(5)	1
Unrealized gains (losses)	14	(20)
Purchases	122	116
Sales	(81)	(76)
Ending Balance	205	155
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	(11)
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	95	79
Realized gains (losses)	6	(1)
Unrealized gains (losses)	0	2
Purchases	86	68
Sales	(68)	(53)
Ending Balance	119	95
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	6	5
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	60	55
Realized gains (losses)	(11)	2
Unrealized gains (losses)	14	(22)
Purchases	36	48
Sales	(13)	(23)
Ending Balance	86	60
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	(16)
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	464	478
Realized gains (losses)	12	2
Unrealized gains (losses)	7	(29)
Purchases	283	87
Sales	(248)	(74)
Ending Balance	518	464
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	22	(24)
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	296	304
Realized gains (losses)	18	(4)
Unrealized gains (losses)	(5)	1
Purchases	250	64
Sales	(220)	(69)
Ending Balance	339	296
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	4
Pension Plans, Defined Benefit [Member] | Private Equity and Other [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	168	174
Realized gains (losses)	(6)	6
Unrealized gains (losses)	12	(30)
Purchases	33	23
Sales	(28)	(5)
Ending Balance	179	168
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	$ 6	$ (28)

XML

Stock-Based Compensation (Details 4) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Stock Award Activity [Line Items]
Restricted common shares awarded	590,098
Compensation cost charged against income (in millions)	$ 83	$ 66	$ 52
Restricted Stock [Member]
Stock Award Activity [Line Items]
Fair value of awards vested (in millions)	9	13	19
Restricted common shares awarded	167,320	381,840	238,405
Weighted average market price of shares awarded	$ 53.71	$ 47.98	$ 44.08
Compensation cost charged against income (in millions)	$ 12	$ 12	$ 12

XML

Fair Value (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2012 dte_instances	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Cash Equivalents Included in Restricted Cash	$ 109,000,000	$ 124,000,000
Fair Value of Cash Equivalents Included in Other Investments	14,000,000	16,000,000
Other investments	110,000,000	95,000,000
Maturity in Years for Cash and Cash Equivalents	3 months
Number of Certain Forward Market and Basis Prices Used	2
Average Maturity of Debt Securities	6 years	7 years
Unrealized losses recognized as regulatory assets	44,000,000	67,000,000
Fermi I Corresponding Regulatory Asset Treatment	0
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
Trading Securities, Change in Unrealized Holding Gain (Loss)	9,000,000	3,000,000	7,000,000
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, before Tax		0
Publicly Traded Equity Securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Nuclear Decommissioning Trust Fund Investments	61.00%	57.00%
Fixed Income Securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Nuclear Decommissioning Trust Fund Investments	38.00%	41.00%
Cash Equivalents [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Available-for-sale Securities, Fair Value Disclosure	123,000,000	140,000,000
Nuclear Decommissioning Trust Fund Investments	1.00%	2.00%
Equity [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Available-for-sale Securities, Fair Value Disclosure	$ 5,000,000	$ 5,000,000

XML

Regulatory Matters (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Regulatory Asset and Liability [Line Items]
Regulatory Assets	$ 4,417	$ 4,853
Regulatory Assets, Current	(182)	(314)
Regulatory Assets, Noncurrent	4,235	4,539
Securitized Regulatory Assets, Noncurrent	413	577
Regulatory Liabilities	1,120	1,126
Regulatory Liability, Current	(89)	(107)
Regulatory Liability, Noncurrent	1,031	1,019
Asset Removal Costs [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	439	419
Renewable Energy [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	230	192
Refundable Revenue Decoupling [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	127	127
Pension Cost [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	105	120
Refundable Income Taxes [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	56	66
Over Recovery of Securitization [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	54	53
Refundable Uncollectible Expense [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	37	31
Energy Optimization [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	34	34
Accrued PSCR GCR Refund [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	16	26
Refueling Outage [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	12	23
Low Income Energy Efficiency Fund [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	0	26
Other Liabilities [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	10	9
Pension [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	2,420	2,208
Postretirment costs [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	426	778
Asset retirement obligation [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	424	420
Recoverable Michigan income taxes [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	304	324
Recoverable income taxes related to securitized regulatory assets [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	226	316
Cost to Achieve Performance Excellence Process [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	96	116
Accrued PSCR/GCR revenue [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	87	147
Other recoverabe income taxes [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	76	81
Choice Incentive Mechanism [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	66	166
Loss on Reacquired Debt [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	63	64
Deferred environmental costs [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	58	49
Recoverable restoration expense [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	49	58
Recoverable revenue decoupling [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	28	18
Enterprise Business Systems Costs [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	16	18
Other [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	$ 78	$ 90

XML

Supplementary Quarterly Financial Information (Unaudited ) (Tables)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information [Table Text Block]

Quarterly earnings per share may not equal full year totals, 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)
2012
Operating Revenues	$	2,239	$	2,013		$	2,190	$	2,349		$	8,791
Operating Income	$	312	$	294		$	406	$	267		$	1,279
Net Income Attributable to DTE Energy Company
Continuing Operations	$	156	$	147		$	226	$	137		$	666
Discontinued Operations	—		(1		)	1		(56		)	(56		)
Net Income Attributable to DTE Energy Company	$	156	$	146		$	227	$	81		$	610
Basic Earnings per Share
Continuing Operations	$	0.91	$	0.87		$	1.31	$	0.79		$	3.89
Discontinued Operations	—		(0.01		)	0.01		(0.32		)	(0.33		)
Total	$	0.91	$	0.86		$	1.32	$	0.47		$	3.56
Diluted Earnings per Share
Continuing Operations	$	0.91	$	0.87		$	1.30	$	0.79		$	3.88
Discontinued Operations	—		(0.01		)	0.01		(0.32		)	(0.33		)
Total	$	0.91	$	0.86		$	1.31	$	0.47		$	3.55

2011
Operating Revenues	$	2,423		$	2,018		$	2,254	$	2,163		$	8,858
Operating Income	$	389		$	288		$	398	$	346		$	1,421
Net Income Attributable to DTE Energy Company
Continuing Operations (a)	$	177		$	203		$	183	$	151		$	714
Discontinued Operations	(1		)	(1		)	—		(1		)	(3		)
Net Income Attributable to DTE Energy Company	$	176		$	202		$	183	$	150		$	711
Basic Earnings per Share
Continuing Operations	$	1.05		$	1.19		$	1.08	$	0.88		$	4.21
Discontinued Operations	(0.01		)	—			—		—			(0.02		)
Total	$	1.04		$	1.19		$	1.08	$	0.88		$	4.19
Diluted Earnings per Share
Continuing Operations	$	1.05		$	1.19		$	1.07	$	0.88		$	4.20
Discontinued Operations	(0.01		)	—			—		—			(0.02		)
Total	$	1.04		$	1.19		$	1.07	$	0.88		$	4.18

XML

Capital and Operating Leases (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule of Leased Assets [Line Items]
Operating Leases, Rent Expense	$ 36	$ 40	$ 32
Capital Leases, Contingent Rental Payments Due	$ 27
Period For Extension of Renewal Options of Capital Lease Contract	5 years
Ownership Interest with Lessee	40.00%
Period For Extenstion of Renewal Options of Capital Lease Contract 1	3 years
Period For Extension of Renewal Options of Capital Lease Contract 2	5 years

XML

Stock Based-Compensation (Details 5) (USD $)	12 Months Ended
	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at January 1, 2012	726,224
Grants	167,320
Forfeitures	(37,767)
Vested and Issued	(258,129)
Balance at December 31, 2012	597,648
Weighted Average Grant Date Fair Value Per Share - Balance at January 1, 2012	$ 42.25
Weighted Average Grant Date Fair Value Per Share - Grants	$ 53.71
Weighted Average Grant Date Fair Value Per Share - Foreitures	$ 48.46
Weighted Average Grant Date Fair Value Per Share - Vested and issued	$ 34.41
Weighted Average Grant Date Fair Value Per Share - Balance at December 31, 2012	$ 48.33

XML

Financial and Other Derivative Instruments (Details 2)	Dec. 31, 2012 dte.volumes
Natural Gas [Member]
Derivative [Line Items]
Volume of Commodity Contracts	663,194,602
Electricity [Member]
Derivative [Line Items]
Volume of Commodity Contracts	48,524,412
Foreign currency exchange contracts [Member]
Derivative [Line Items]
Volume of Commodity Contracts	10,838,396
FTR [Member]
Derivative [Line Items]
Volume of Commodity Contracts	11,077,483

XML

Jointly Owned Utility Plant (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 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)	1,661
Accumulated depreciation (in millions)	953
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)	164
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%

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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, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Quarterly Information [Line Items]
Operating Revenues	$ 2,349	$ 2,190	$ 2,013	$ 2,239	$ 2,163	$ 2,254	$ 2,018	$ 2,423	$ 8,791	$ 8,858	$ 8,525
Operating Income (Loss)	267	406	294	312	346	398	288	389	1,279	1,421	1,470
Income (Loss) from Continuing Operations Attributable to Parent	137	226	147	156	151	183	203	177	666	714
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	(56.00)	1.00	(1.00)	0	(1.00)	0	(1.00)	(1.00)	(56.00)	(3.00)	(8.00)
Net Income Attributable to DTE Energy Company	81	227	146	156	150	183	202	176	610	711	630
Income (Loss) from Continuing Operations, Per Basic Share	$ 0.79	$ 1.31	$ 0.87	$ 0.91	$ 0.88	$ 1.08	$ 1.19	$ 1.05	$ 3.89	$ 4.21	$ 3.79
Income (Loss) from Discontinued Operations, Net of Tax, Per Basic Share	$ (0.32)	$ 0.01	$ (0.01)	$ 0.00	$ 0.00	$ 0.00	$ 0.00	$ (0.01)	$ (0.33)	$ (0.02)	$ (0.04)
Basic Earnings per Share	$ 0.47	$ 1.32	$ 0.86	$ 0.91	$ 0.88	$ 1.08	$ 1.19	$ 1.04	$ 3.56	$ 4.19	$ 3.75
Income (Loss) from Continuing Operations, Per Diluted Share	$ 0.79	$ 1.30	$ 0.87	$ 0.91	$ 0.88	$ 1.07	$ 1.19	$ 1.05	$ 3.88	$ 4.20	$ 3.78
Income (Loss) from Discontinued Operations, Net of Tax, Per Diluted Share	$ (0.32)	$ 0.01	$ (0.01)	$ 0	$ 0	$ 0	$ 0	$ (0.01)	$ (0.33)	$ (0.02)	$ (0.04)
Diluted Earnings per Share	$ 0	$ 1.31	$ 0.86	$ 0.91	$ 0.88	$ 1.07	$ 1.19	$ 1.04	$ 3.55	$ 4.18	$ 3.74
Income Tax Benefit							$ 87

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Disposals and Discontinued Operations (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 acre	Dec. 31, 2011	Dec. 31, 2010
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal of Equity Interest In Segment Percentage	100.00%
Number of Acres Included in the Sale of the Segment	88,000
Proceeds from Divestiture of Businesses	$ 255	$ 0	$ 0
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax	83
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax	55
Allocation of Corporate Interest Costs	$ 0

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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, 2012	Dec. 31, 2011
Asset Retirement Obligations [Line Items]
Asset retirement obligations at January 1, 2012			$ 1,593
Accretion			100
Liabilities incurred			27
Liabilities settled			(11)
Revision in estimated cash flows	19	20	10	22
Asset retirement obligations at December 31, 2012			$ 1,719	$ 1,593

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Financial and Other Derivative Instruments (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
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	326
Number of Categories of Activities Represented by their Operating Characteristics and Key Risks	4
FTR [Member]
Derivative [Line Items]
Derivative Instruments Recoverable Through PSCR Mechanism	$ 15	$ 3

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Fair Value (Details 6) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Option, Quantitative Disclosures [Line Items]
Realized gains	$ 37	$ 46	$ 192
Realized losses	(31)	(38)	(83)
Proceeds from sales of securities	$ 97	$ 80	$ 377

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Short-Term Credit Arrangements and Borrowings (Notes)

12 Months Ended

Dec. 31, 2012

Short-term Debt [Abstract]

SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

DTE Energy and its wholly owned subsidiaries, DTE Electric and DTE Gas, have 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.

The 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 DTE Gas 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, 2012, the total funded debt to total capitalization ratios for DTE Energy, DTE Electric and DTE Gas are 0.48 to 1, 0.52 to 1 and 0.46 to 1, respectively, and are in compliance with this financial covenant. The availability under these combined facilities at December 31, 2012 is shown in the following table:

	DTE Energy		DTE Electric		DTE Gas		Total
	(In millions)
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, 2012	$	1,275	$	300	$	400	$	1,975
Amounts outstanding at December 31, 2012:
Commercial paper issuances	—		130		110		240
Letters of credit	175		—		—		175
	175		130		110		415
Net availability at December 31, 2012	$	1,100	$	170	$	290	$	1,560

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $73 million which are used for various corporate purposes.

The weighted average interest rate for short-term borrowings was 0.4% and 0.5% at December 31, 2012 and 2011, 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, 2012, a $40 million letter of credit was in place, raising the capacity under this facility to $140 million. The $40 million letter of credit is included in the table above. The amount outstanding under this agreement was $65 million and $56 million at December 31, 2012 and December 31, 2011, respectively.

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Supplemental Cash Flow Information Supplemental Cash Flow Information (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Other Significant Noncash Transactions [Line Items]
Common stock issued for employee benefit plans	$ 114	$ 1	$ 156
Change in capital expenditures not paid	$ 23	$ 76	$ 20

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Short-Term Credit Arrangements and Borrowings (Tables)

12 Months Ended

Dec. 31, 2012

Short-term Debt [Abstract]

Schedule of Short-term Debt [Table Text Block]

	DTE Energy		DTE Electric		DTE Gas		Total
	(In millions)
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, 2012	$	1,275	$	300	$	400	$	1,975
Amounts outstanding at December 31, 2012:
Commercial paper issuances	—		130		110		240
Letters of credit	175		—		—		175
	175		130		110		415
Net availability at December 31, 2012	$	1,100	$	170	$	290	$	1,560

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Table Text Block]

	2012			2011
Property, Plant and Equipment	(In millions)
Electric
Generation	$	10,383		$	9,785
Distribution	7,306			7,003
Total Electric	17,689			16,788
Gas
Distribution	2,735			2,561
Storage	434			406
Other	852			902
Total Gas	4,021			3,869
Non-utility and other	1,921			1,884
Total	23,631			22,541
Less Accumulated Depreciation, Depletion and Amortization
Electric
Generation	(3,880		)	(3,946		)
Distribution	(2,837		)	(2,580		)
Total Electric	(6,717		)	(6,526		)
Gas
Distribution	(1,075		)	(1,041		)
Storage	(133		)	(127		)
Other	(363		)	(413		)
Total Gas	(1,571		)	(1,581		)
Non-utility and other	(659		)	(688		)
Total	(8,947		)	(8,795		)
Net Property, Plant and Equipment	$	14,684		$	13,746

Useful Life [Table Text Block]

	Estimated Useful Lives in Years
Utility	Generation	Distribution	Storage
Electric	40	41	N/A
Gas	N/A	50	53

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Financial and Other Derivative Instruments (Details 1) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 65	$ 159
Foreign currency exchange contracts [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	(2)
Natural Gas [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(29)	58
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	25	(21)
Electricity [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	64	115
Other [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 5	$ 9

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Earnings Per Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Basic Earnings per Share
Net Income Attributable to DTE Energy Company	$ 81	$ 227	$ 146	$ 156	$ 150	$ 183	$ 202	$ 176	$ 610	$ 711	$ 630
Average number of common shares outstanding									171	169	168
Weighted average net restricted shares outstanding									1	1	1
Dividends declared - common shares									413	392	365
Dividends declared - net restricted shares									1	1	2
Total distributed earnings									414	393	367
Net income less distributed earnings									196	318	263
Distributed (dividends per common share)									$ 2.42	$ 2.32	$ 2.18
Undistributed									$ 1.14	$ 1.87	$ 1.57
Total Basic Earnings per Common Share	$ 0.47	$ 1.32	$ 0.86	$ 0.91	$ 0.88	$ 1.08	$ 1.19	$ 1.04	$ 3.56	$ 4.19	$ 3.75
Diluted Earnings per Share
Net Income Attributable to DTE Energy Company	81	227	146	156	150	183	202	176	610	711	630
Average number of common shares outstanding									171	169	168
Average incremental shares from assumed exercise of options									1	1	1
Common shares for dilutive calculation									172	170	169
Weighted average net restricted shares outstanding									1	1	1
Dividends declared - common shares									413	392	365
Dividends declared - net restricted shares									1	1	2
Total distributed earnings									414	393	367
Net income less distributed earnings									$ 196	$ 318	$ 263
Distributed (dividends per common share)									$ 2.42	$ 2.32	$ 2.18
Earnings Per Share, Diluted, Undistributed									$ 1.13	$ 1.86	$ 1.56
Total Diluted Earnings per Common Share	$ 0	$ 1.31	$ 0.86	$ 0.91	$ 0.88	$ 1.07	$ 1.19	$ 1.04	$ 3.55	$ 4.18	$ 3.74

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Fair Value (Tables)

12 Months Ended

Dec. 31, 2012

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, 2012 and 2011:

	December 31, 2012															December 31, 2011
	Level 1			Level 2			Level 3			Netting (a)			Net Balance			Level 1			Level 2			Level 3			Netting (a)			Net Balance
	(In millions)
Assets:
Cash equivalents (b)	$	—		$	123		$	—		$	—		$	123		$	—		$	140		$	—		$	—		$	140
Nuclear decommissioning trusts	694			343			—			—			1,037			577			360			—			—			937
Other investments (c) (d)	66			44			—			—			110			57			38			—			—			95
Derivative assets:
Foreign currency exchange contracts	—			—			—			—			—			—			3			—			(3		)	—
Commodity Contracts:
Natural Gas	555			66			24			(605		)	40			1,926			78			20			(1,991		)	33
Electricity	—			226			134			(258		)	102			—			523			224			(490		)	257
Other	6			3			2			(6		)	5			23			2			6			(25		)	6
Total derivative assets	561			295			160			(869		)	147			1,949			606			250			(2,509		)	296
Total	$	1,321		$	805		$	160		$	(869	)	$	1,417		$	2,583		$	1,144		$	250		$	(2,509	)	$	1,468
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	—		$	—		$	—		$	—		$	—		$	(5	)	$	—		$	3		$	(2	)
Interest rate contracts	—			(1		)	—			—			(1		)	—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(526		)	(73		)	(62		)	605			(56		)	(1,940		)	(126		)	(14		)	1,976			(104		)
Electricity	—			(240		)	(111		)	258			(93		)	—			(513		)	(192		)	565			(140		)
Other	(6		)	(1		)	—			6			(1		)	(19		)	(1		)	—			20			—
Total derivative liabilities	(532		)	(315		)	(173		)	869			(151		)	(1,959		)	(646		)	(206		)	2,564			(247		)
Total	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)	$	(1,959	)	$	(646	)	$	(206	)	$	2,564		$	(247	)
Net Assets at the end of the period	$	789		$	490		$	(13	)	$	—		$	1,266		$	624		$	498		$	44		$	55		$	1,221
Assets:
Current	$	493		$	372		$	120		$	(754	)	$	231		$	1,571		$	660		$	181		$	(2,050	)	$	362
Noncurrent (e)	828			433			40			(115		)	1,186			1,012			484			69			(459		)	1,106
Total Assets	$	1,321		$	805		$	160		$	(869	)	$	1,417		$	2,583		$	1,144		$	250		$	(2,509	)	$	1,468
Liabilities:
Current	$	(466	)	$	(269	)	$	(144	)	$	754		$	(125	)	$	(1,603	)	$	(527	)	$	(152	)	$	2,124		$	(158	)
Noncurrent	(66		)	(46		)	(29		)	115			(26		)	(356		)	(119		)	(54		)	440			(89		)
Total Liabilities	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)	$	(1,959	)	$	(646	)	$	(206	)	$	2,564		$	(247	)
Net Assets at the end of the period	$	789		$	490		$	(13	)	$	—		$	1,266		$	624		$	498		$	44		$	55		$	1,221

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, 2012 and 2011:

	Year Ended December 31, 2012												Year Ended December 31, 2011
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets as of January 1	$	6		$	32		$	6		$	44		$	1		$	54		$	4		$	59
Transfers into Level 3	1			—			—			1			—			4			—			4
Transfers out of Level 3	—			—			—			—			1			(25		)	—			(24		)
Total gains (losses):
Included in earnings	(41		)	101			—			60			7			77			3			87
Recorded in regulatory assets/liabilities	—			—			15			15			—			—			2			2
Purchases, issuances and settlements:
Purchases	—			2			—			2			—			3			—			3
Settlements	(4		)	(112		)	(19		)	(135		)	(3		)	(81		)	(3		)	(87		)
Net Assets (Liabilities) as of December 31	$	(38	)	$	23		$	2		$	(13	)	$	6		$	32		$	6		$	44
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, 2012 and 2011and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(33	)	$	91		$	—		$	58		$	8		$	65		$	2		$	75

Transfers Between Level 1 Level 2 and Level 3 [Table Text Block]

The following table shows transfers between the levels of the fair value hierarchy for the years ended December 31, 2012 and 2011:

	Year Ended December 31, 2012						Year Ended December 31, 2011
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
	(In millions)
Transfers into Level 1 from	N/A		$	—	$	—	N/A		$	—	$	—
Transfers into Level 2 from	$	—	N/A		—		$	—	N/A		24
Transfers into Level 3 from	—		1		N/A		—		4		N/A

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Table Text Block]

The following table presents the unobservable inputs related to Level 3 assets and liabilities as of December 31, 2012:

	December 31, 2012
Commodity Contracts	Derivative Assets		Derivative Liabilities			Valuation Techniques	Unobservable Input	Range							Weighted Average
(In millions)
Natural Gas	$	24	$	(62	)	Discounted Cash Flow	Forward basis price (per MMBtu)	$	(0.63	)	—	$	1.95	/MMBtu	$	0.03	/MMBtu
Electricity	134		(111		)	Discounted Cash Flow	Forward basis price (per MWh)	$	(2	)	—	$	16	/MWh	$	3	/MWh

Fair Value of Financial Instruments [Table Text Block]

The following table presents the carrying amount and fair value of financial instruments as of December 31, 2012 and 2011:

	December 31, 2012								December 31, 2011
	Carrying		Fair Value						Carrying		Fair
	Amount		Level 1		Level 2		Level 3		Amount		Value
	(In millions)
Notes receivable, excluding capital leases	$	39	$	—	$	—	$	39	$	48	$	48
Dividends payable	107		107		—		—		99		99
Short-term borrowings	240		—		240		—		419		419
Long-term debt	7,813		507		7,453		933		7,682		8,757

Fair Value of Nuclear Decommissioning Trust Fund Assets Text Block [Table]

	December 31 2012		December 31 2011
	(In millions)
Fermi 2	$	1,021	$	915
Fermi 1	3		3
Low level radioactive waste	13		19
Total	$	1,037	$	937

Schedule of Realized Gain (Loss) [Table Text Block]

	Year Ended December 31
	2012			2011			2010
	(In millions)
Realized gains	$	37		$	46		$	192
Realized losses	$	(31	)	$	(38	)	$	(83	)
Proceeds from sales of securities	$	97		$	80		$	377

Fair Value and Unrealized Gains for Nuclear Decommissioning Trust Fund Table [Table] [Table Text Block]

	December 31, 2012				December 31, 2011
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
	(In millions)
Equity securities	$	631	$	122	$	533	$	80
Debt securities	399		27		385		22
Cash and cash equivalents	7		—		19		—
	$	1,037	$	149	$	937	$	102

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies [Abstract]

Long-term Purchase Commitment [Table Text Block]

	(In millions)
2013	$	1,937
2014	1,199
2015	424
2016	147
2017	88
2018 — 2052	582
	$	4,377

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Fair Value Fair Value (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Inputs, Level 1 [Member]
Fair Value Transfers Between Level 1, Level 2 and Level 3 [Line Items]
Transfers into Level 2	$ 0	$ 0
Transfers into Level 3	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value Transfers Between Level 1, Level 2 and Level 3 [Line Items]
Transfers into Level 1	0	0
Transfers into Level 3	1	4
Fair Value, Inputs, Level 3 [Member]
Fair Value Transfers Between Level 1, Level 2 and Level 3 [Line Items]
Transfers into Level 1	0	0
Transfers into Level 2	$ 0	$ 24

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Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	$ 4,400
2013 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	1,937
2014 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	1,199
2015 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	424
2016 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	147
2017 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	88
2018 - 2052 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	582
Total [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	$ 4,377

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Organization and Basis of Presentation (Details 1) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Unconsolidated Variable Interest Entity [Member]	Dec. 31, 2010 Unconsolidated Variable Interest Entity [Member]
Variable Interest Entity [Line Items]
Other investments			$ 130	$ 117
Notes receivable	$ 112	$ 123	$ 6	$ 7

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2012

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

	2012		2011		2010
	(In millions, expect per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	610	$	711	$	630
Average number of common shares outstanding	171		169		168
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	413	$	392	$	365
Dividends declared — net restricted shares	1		1		2
Total distributed earnings	$	414	$	393	$	367
Net income less distributed earnings	$	196	$	318	$	263
Distributed (dividends per common share)	$	2.42	$	2.32	$	2.18
Undistributed	1.14		1.87		1.57
Total Basic Earnings per Common Share	$	3.56	$	4.19	$	3.75
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	610	$	711	$	630
Average number of common shares outstanding	171		169		168
Average incremental shares from assumed exercise of options	1		1		1
Common shares for dilutive calculation	172		170		169
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	413	$	392	$	365
Dividends declared — net restricted shares	1		1		2
Total distributed earnings	$	414	$	393	$	367
Net income less distributed earnings	$	196	$	318	$	263
Distributed (dividends per common share)	$	2.42	$	2.32	$	2.18
Undistributed	1.13		1.86		1.56
Total Diluted Earnings per Common Share	$	3.55	$	4.18	$	3.74

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Organization and Basis of Presentation (Notes)

12 Months Ended

Dec. 31, 2012

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:

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

• DTE Gas, 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) power and industrial projects; and 3) energy marketing and trading operations.

DTE Electric and DTE Gas are regulated by the MPSC. Certain activities of DTE Electric and DTE Gas, 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.

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, which includes arrangements related to entities acquired in 2012. See Note 6. 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, 2012, the carrying amount of assets and liabilities in the Consolidated Statements 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, DTE Electric 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. DTE Electric performs servicing activities including billing and collecting surcharge revenue for Securitization. This entity is a VIE, and is consolidated by the Company.

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, 2012 and December 31, 2011. Amounts at December 31, 2012 and 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, 2012								December 31, 2011
	Securitization		Other		Total		Restricted Amounts		Securitization		Other		Total		Restricted Amounts
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	10	$	10	$	8	$	—	$	25	$	25	$	—
Restricted cash	102		7		109		109		107		7		114		114
Accounts receivable	34		7		41		38		34		17		51		36
Inventories	—		141		141		3		—		183		183		—
Other current assets	—		1		1		1		—		1		1		—
Property, plant and equipment	—		93		93		49		—		73		73		23
Securitized regulatory assets	413		—		413		413		577		—		577		577
Other assets	7		11		18		18		10		6		16		16
	$	556	$	270	$	826	$	639	$	728	$	312	$	1,040	$	766
LIABILITIES
Accounts payable and accrued current liabilities	$	11	$	14	$	25	$	12	$	14	$	24	$	38	$	14
Current portion long-term debt, including capital leases	177		8		185		185		164		7		171		171
Other current liabilities	50		4		54		53		55		—		55		55
Mortgage bonds, notes and other	—		25		25		25		—		30		30		30
Securitization bonds	302		—		302		302		479		—		479		479
Capital lease obligations	—		11		11		11		—		14		14		14
Other long-term liabilities	7		2		9		8		7		2		9		8
	$	547	$	64	$	611	$	596	$	719	$	77	$	796	$	771

Amounts for non-consolidated VIEs as of December 31, 2012 and December 31, 2011 are as follows:

	December 31, 2012		December 31, 2011
	(In millions)
Other investments	$	130	$	117
Notes receivable	6		7

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Supplemental Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$ 52	$ 71	$ 79
Inventories	35	(129)	(133)
Recoverable pension and postretirement costs	141	(620)	(32)
Accrued/prepaid pension costs	280	432	67
Accounts payable	40	(23)	12
Income taxes payable/receivable	30	249	(245)
Derivative assets and liabilities	53	(94)	(48)
Postretirement obligation	(323)	209	(24)
Increase (Decrease) in Regulatory Assets and Liabilities	122	38	(37)
Other assets	117	(28)	(15)
Other liabilities	(105)	(11)	83
Total Changes in Assets and Liabilities, Exclusive of Changes Shown Separately	$ 442	$ 94	$ (293)

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Retirement Benefits and Trusteed Assets (Details 4) (Pension Plans, Defined Benefit [Member])	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Plans, Defined Benefit [Member]
Assumptions Used to Determin Projected Benefit Obligations and Net Pension Costs [Line Items]
Discount rate	4.15%	5.00%	5.50%
Rate of compensation increase	4.20%	4.20%	4.00%
Discount Rate	5.00%	5.50%	5.90%
Rate of compensation increase	4.20%	4.00%	4.00%
Expected long-term rate of return on plan assets	8.25%	8.50%	8.75%

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Significant Accounting Policies (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Significant Accounting Policies [Line Items]
Maturities on Temporary Investments	3 months
Receivables Due Date	21 days
Number of Days in a Year	365 days
Time Period Customer Accounts are Written off After Service Termination	150 days
Specific Review of Probable Future Collections Based on Receivable Balances in Excess of 90 Days	30 days
Unbilled Contracts Receivable	$ 686,000,000	$ 597,000,000
Notes Receivable Considered Delinquent Minimum Due Date	60 days
Notes Receivable Considered Delinquent Maximum Due Date	120 days
LIFO Inventory Amount	37,000,000	52,000,000
Excess of Replacement or Current Costs over Stated LIFO Value	113,000,000	95,000,000
Expense Related to Refueling Outages	12,000,000	23,000,000
Period Expenses Related To Refueling Outages Are Accrued	18 months
Amortization of Intangible Assets	6,000,000	5,000,000	4,000,000
Estimated Amount of Amortization	13,000,000
Excise Sales Tax Net Impact on Statement of Operations	0
Collateral Already Posted, Aggregate Fair Value	20,000,000	71,000,000
Cash Collateral Paid or Received for Derivative Assets or Derivative Liabilities	0
Cash Collateral Paid or Received for Derivative Assets		19,000,000
Cash Collateral Paid or Received for Derivative Liabilities		74,000,000
Cash Collateral Paid	4,000,000	16,000,000
Cash Collateral Received	24,000,000
Charitable Contributions to a Foundation	$ 21,000,000	$ 21,000,000	$ 14,000,000
Restricted Cash Time Period to be Classified as Current	1 year
Minimum [Member]
Significant Accounting Policies [Line Items]
Finite Lived Asset Useful Life	3 years
Maximum [Member]
Significant Accounting Policies [Line Items]
Finite Lived Asset Useful Life	15 years
Finite Lived Intangible Asset, Useful Life 1	28 years

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Retirement Benefits and Trusteed Assets (Details Textuals) (USD $)	12 Months Ended			1 Months Ended		12 Months Ended		1 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Jan. 31, 2012 Pension Plans, Defined Benefit [Member]	Jan. 31, 2011 Pension Plans, Defined Benefit [Member]	Dec. 31, 2012 Pension Plans, Defined Benefit [Member]	Dec. 31, 2011 Pension Plans, Defined Benefit [Member]	Jan. 31, 2012 Other Postretirement Benefit Plans, Defined Benefit [Member]	Dec. 31, 2012 Other Postretirement Benefit Plans, Defined Benefit [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Company contributions				$ 315,000,000	$ 229,000,000	$ 240,000,000	$ 209,000,000	$ 145,000,000	$ 140,000,000	$ 111,000,000
Allocation of Company Contributions in Lieu of Post-Employment Health Care Benefits	4,000
Time Period for Vesting of Allocation of Company Contributions in Lieu of Post-Employment Health Care Benefits	10 years
Company Retiree New Coverage Maximum	3,500
Company Retiree New Coverage Minimum	3,250
Company Retiree New Coverage after a Certain Date Maximum	4,000
Company Contribution to Employee Savings Plan	4.00%
Time period to pay benefit payments for qualified and unqualified plans						5 years			5 years
Time period for aggregate benefit payments for qualified and non qualtified benefit plans						5 years			5 years
Transfers between Level 2 and Level 3						0	0		0	0
Transfers between Level 1 and Level 2						0	0		0	0
Defined Contribution Plan, Cost Recognized	37,000,000	35,000,000	34,000,000
Health Care Trend Increase in Percentage Point	0.00%
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	264,000,000
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year									120,000,000
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components	28,000,000
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	279,000,000
Health Care Trend Decrease in Percentage Point	0.00%
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components	19,000,000
Prescription Drug Benefit, Effect of Subsidy on Net Periodic Postretirement Benefit Cost	6,000,000	6,000,000	7,000,000
Grantor Trust Balance	$ 14,000,000

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Stock-Based Compensation (Details 7)	12 Months Ended
	Dec. 31, 2012
Performance Share Awards [Line Items]
Performance Shares - Balance at January 1, 2012	1,608,733
Performance Shares - Grants	590,098
Performance Shares - Forfeitures	(59,712)
Performance Shares - Payouts	(504,755)
Performance Shares - Balance at December 31, 2012	1,634,364

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Jointly Owned Utility Plant (Tables)

12 Months Ended

Dec. 31, 2012

Jointly Owned Utility Plant, Net Ownership Amount [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	(a)			49		%
Investment (in millions)	$	1,661		$	199
Accumulated depreciation (in millions)	$	953		$	164

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Stock-Based Compensation (Notes)

12 Months Ended

Dec. 31, 2012

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 11,500,000 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:

	2012		2011		2010
	(In millions)
Stock-based compensation expense	$	83	$	66	$	52
Tax benefit	33		25		20
Stock-based compensation cost capitalized in property, plant and equipment	5		4		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 3-year period.

Stock option activity was as follows:

	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In millions)
Options outstanding at January 1, 2012	2,764,670		$	41.25
Granted	—		$	—
Exercised	(1,555,227	)	$	40.78
Forfeited or expired	(16,773	)	$	42.02
Options outstanding at December 31, 2012	1,192,670		$	41.86	$	22
Options exercisable at December 31, 2012	991,826		$	41.44	$	19

As of December 31, 2012, the weighted average remaining contractual life for the exercisable shares is 4.30 years. As of December 31, 2012, 200,844 options were non-vested. During 2012, 332,026 options vested.

There were no options granted during 2012 or 2011. The intrinsic value of options exercised for the years ended December 31, 2012, 2011 and 2010 was $25 million, $20 million, and $9 million, respectively. Total option expense recognized during 2012, 2011 and 2010 was $0.7 million, $2 million and $4 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	142,619	$	27.98	6.15
$	38.01	—	$	42.00	291,982	$	41.14	3.22
$	42.01	—	$	45.00	605,569	$	44.03	5.40
$	45.01	—	$	50.00	152,500	$	47.62	4.03
					1,192,670	$	41.86	4.78

The Company determined the fair value for these options at the date of grant in 2010 using a Black-Scholes based option pricing model and the following assumptions:

	2010
Risk-free interest rate	2.91	%
Dividend yield	5.08	%
Expected volatility	22.96	%
Expected life	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 upon request.

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:

	2012		2011		2010
Fair value of awards vested (in millions)	$	9	$	13	$	19
Restricted common shares awarded	167,320		381,840		238,405
Weighted average market price of shares awarded	$	53.71	$	47.98	$	44.08
Compensation cost charged against income (in millions)	$	12	$	12	$	12

The following table summarizes the Company’s stock awards activity for the period ended December 31, 2012:

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at January 1, 2012	726,224		$	42.25
Grants	167,320		$	53.71
Forfeitures	(37,767	)	$	48.46
Vested and issued	(258,129	)	$	34.41
Balance at December 31, 2012	597,648		$	48.33

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:

	2012		2011		2010
	(In millions)
Compensation expense	$	71	$	53	$	36
Cash settlements (a)	$	4	$	3	$	3
Stock settlements (a)	$	41	$	25	$	23

_______________________________________

(a) 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. Performance shares granted are entitled to dividend equivalent payments before the performance shares granted are earned and vested. During the period beginning on the date the 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, 2012:

	Performance Shares
Balance at January 1, 2012	1,608,733
Grants	590,098
Forfeitures	(59,712	)
Payouts	(504,755	)
Balance at December 31, 2012	1,634,364

Unrecognized Compensation Costs

As of December 31, 2012, there was $58 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 1.37 years.

	Unrecognized Compensation Cost		Weighted Average to be Recognized
	(In millions)		(In years)
Options	$	—	0.15
Stock awards	11		1.02
Performance shares	47		1.46
	$	58	1.37

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Retirement Benefits and Trusteed Assets (Notes)

12 Months Ended

Dec. 31, 2012

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.

Effective January 1, 2012, the Company 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.

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 $229 million to its pension plans in 2012. At the discretion of management, and depending upon financial market conditions, we anticipate making up to a $315 million contribution to the pension plans in 2013.

Net pension cost includes the following components:

	2012			2011			2010
	(In millions)
Service cost	$	82		$	69		$	64
Interest cost	204			202			202
Expected return on plan assets	(244		)	(246		)	(258		)
Amortization of:
Net loss	176			142			100
Prior service cost	—			3			4
Special termination benefits	2			2			—
Net pension cost	$	220		$	172		$	112

	2012			2011
	(In millions)
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income
Net actuarial loss	$	395		$	619
Amortization of net actuarial loss	(178		)	(142		)
Amortization of prior service cost	—			(3		)
Total recognized Regulatory assets and Other comprehensive income	$	217		$	474
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	437		$	646
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	$	202		$	171

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:

	2012			2011
	(In millions)
Accumulated benefit obligation, end of year	$	4,349		$	3,881
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	4,195		$	3,785
Service cost	82			69
Interest cost	204			202
Actuarial loss	474			355
Special termination benefits	2			2
Benefits paid	(228		)	(218		)
Projected benefit obligation, end of year	$	4,729		$	4,195
Change in plan assets
Plan assets at fair value, beginning of year	$	2,886		$	2,913
Actual return on plan assets	325			(18		)
Company contributions	240			209
Benefits paid	(228		)	(218		)
Plan assets at fair value, end of year	$	3,223		$	2,886
Funded status of the plans	$	(1,506	)	$	(1,309	)
Amount recorded as:
Current liabilities	$	(8	)	$	(11	)
Noncurrent liabilities	(1,498		)	(1,298		)
	$	(1,506	)	$	(1,309	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	205		$	202
Prior service (credit)	(2		)	(3		)
	$	203		$	199
Amounts recognized in Regulatory assets (see Note 11)
Net actuarial loss	$	2,413		$	2,201
Prior service cost	7			7
	$	2,420		$	2,208

At December 31, 2012, 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)
2013	$	236
2014	242
2015	252
2016	260
2017	269
2018-2022	1,485
	$	2,744

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

	2012		2011		2010
Projected benefit obligation
Discount rate	4.15	%	5.00	%	5.50	%
Rate of compensation increase	4.20	%	4.20	%	4.00	%
Net pension costs
Discount rate	5.00	%	5.50	%	5.90	%
Rate of compensation increase	4.20	%	4.00	%	4.00	%
Expected long-term rate of return on plan assets	8.25	%	8.50	%	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.

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, 2012 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, 2012 and 2011 (a):

	December 31, 2012								December 31, 2011
	Level 1		Level 2		Level 3		Net Balance		Level 1		Level 2		Level 3		Net Balance
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	24	$	—	$	24	$	—	$	33	$	—	$	33
Equity securities															—
U.S. Large Cap (c)	688		44		—		732		640		40		—		680
U.S. Small/Mid Cap (d)	153		5		—		158		159		5		—		164
Non U.S (e)	530		120		—		650		392		114		—		506
Fixed income securities (f)	87		765		—		852		88		703		—		791
Hedge Funds and Similar Investments (g)	209		80		339		628		190		58		296		544
Private Equity and Other (h)	—		—		179		179		—		—		168		168
Total	$	1,667	$	1,038	$	518	$	3,223	$	1,469	$	953	$	464	$	2,886

_______________________________________

(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):

	Year Ended December 31, 2012									Year Ended December 31, 2011
	Hedge Funds and Similar Investments			Private Equity and Other			Total			Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1	$	296		$	168		$	464		$	304		$	174		$	478
Total realized/unrealized gains (losses):
Realized gains (losses)	18			(6		)	12			(4		)	6			2
Unrealized gains (losses)	(5		)	12			7			1			(30		)	(29		)
Purchases, sales and settlements:
Purchases	250			33			283			64			23			87
Sales	(220		)	(28		)	(248		)	(69		)	(5		)	(74		)
Ending Balance at December 31	$	339		$	179		$	518		$	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	$	16		$	6		$	22		$	4		$	(28	)	$	(24	)

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, 2012 and 2011.

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 $37 million, $35 million, and $34 million in each of the years 2012, 2011, and 2010, 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 $140 million to its postretirement medical and life insurance benefit plans during 2012.

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 ten 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.

Effective January 1, 2013, the Company replaced sponsored retiree medical, prescription drug and dental coverage for current and future Medicare eligible non-represented retirees, spouses, surviving spouses, or same sex domestic partners with a Retiree Health Care Allowance (RHCA) account of $3,500 or $3,250 per year depending on their date of hire. Local 17 employees hired after September 24, 2012 will receive a $4,000 per year allocation to an account in a tax-exempt trust for each employee, in lieu of offering post-employment health care and life insurance benefits. Current Local 17 employees, spouses, surviving spouse, or same sex domestic partners, who retired after November 6, 2012 will receive a RHCA of $3,250 per year upon becoming eligible for Medicare.

In January 2013, the Company contributed $145 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 2013.

Net postretirement cost includes the following components:

	2012			2011			2010
	(In millions)
Service cost	$	68		$	64		$	61
Interest cost	120			121			125
Expected return on plan assets	(92		)	(94		)	(74		)
Amortization of:
Net loss	80			55			54
Prior service credit	(27		)	(26		)	(4		)
Net transition asset	2			2			2
Net postretirement cost	$	151		$	122		$	164

	2012			2011
	(In millions)
Other changes in plan assets and APBO recognized in Regulatory assets and Other comprehensive income (in millions)
Net actuarial (gain) loss	$	(34	)	$	195
Amortization of net actuarial loss	(80		)	(55		)
Prior service credit	(264		)	(4		)
Amortization of prior service credit	27			26
Amortization of transition asset	(2		)	(2		)
Total recognized in Regulatory assets and Other comprehensive income	$	(353	)	$	160
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	(202	)	$	282
Estimated amounts to be amortized from Regulatory assets and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year (in millions)
Net actuarial loss	$	69		$	78
Prior service credit	$	(91	)	$	(27	)
Net transition obligation	$	—		$	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:

	2012			2011
	(In millions)
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation, beginning of year	$	2,470		$	2,305
Service cost	68			64
Interest cost	120			121
Plan amendments	(264		)	(4		)
Actuarial loss	5			80
Medicare Part D subsidy	6			6
Benefits paid	(90		)	(102		)
Accumulated postretirement benefit obligation, end of year	$	2,315		$	2,470
Change in plan assets
Plan assets at fair value, beginning of year	$	985		$	1,029
Actual return on plan assets	131			(22		)
Company contributions	140			111
Benefits paid	(103		)	(133		)
Plan assets at fair value, end of year	$	1,153		$	985
Funded status, end of year	$	(1,162	)	$	(1,485	)
Amount recorded as:
Current liabilities	$	(2	)	$	(1	)
Noncurrent liabilities	$	(1,160	)	$	(1,484	)
	$	(1,162	)	$	(1,485	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	40		$	47
Prior service credit	(14		)	(20		)
Net transition asset	(1		)	(1		)
	$	25		$	26
Amounts recognized in Regulatory assets (See Note 11)
Net actuarial loss	$	727		$	835
Prior service cost	(302		)	(60		)
Net transition obligation	1			3
	$	426		$	778

At December 31, 2012, 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)
2013	$	103
2014	109
2015	115
2016	120
2017	127
2018 — 2022	726
	$	1,300

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

	2012		2011		2010
Projected benefit obligation
Discount rate	4.15	%	5.00	%	5.50	%
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
Net benefit costs
Discount rate	5.00	%	5.50	%	5.90	%
Expected long-term rate of return on plan assets	8.25	%	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	2020		2019		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 $28 million and increased the accumulated benefit obligation by $279 million at December 31, 2012. 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 $19 million and would have decreased the accumulated benefit obligation by $264 million at December 31, 2012.

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, 2012 are listed below:

U.S. Domestic Equity Securities	21	%
Non U.S. Equity Securities	20
Fixed Income Securities	25
Hedge Funds and Similar Investments	20
Private Equity and Other	14
	100	%

Fair Value Measurements at December 31, 2012 and 2011(a):

	December 31, 2012								December 31, 2011
	Level 1		Level 2		Level 3		Net Balance		Level 1		Level 2		Level 3		Net Balance
Asset Category:	(In millions)
Short-term investments (b)	$	1	$	2	$	—	$	3	$	—	$	13	$	—	$	13
Equity securities:
U.S. Large Cap (c)	189		3		—		192		175		15		—		190
U.S. Small/Mid Cap (d)	105		—		—		105		70		6		—		76
Non U.S (e)	230		7		—		237		176		14		—		190
Fixed income securities (f)	38		247		—		285		24		236		—		260
Hedge Funds and Similar Investments (g)	102		24		119		245		80		21		95		196
Private Equity and Other (h)	—		—		86		86		—		—		60		60
Total	$	665	$	283	$	205	$	1,153	$	525	$	305	$	155	$	985

_______________________________________

(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):

	Year Ended December 31, 2012									Year Ended December 31, 2011
	Hedge Funds and Similar Investments			Private Equity and Other			Total			Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1	$	95		$	60		$	155		$	79		$	55		$	134
Total realized/unrealized gains (losses):
Realized gains (losses)	6			(11		)	(5		)	(1		)	2			1
Unrealized gains (losses)	—			14			14			2			(22		)	(20		)
Purchases, sales and settlements:
Purchases	86			36			122			68			48			116
Sales	(68		)	(13		)	(81		)	(53		)	(23		)	(76		)
Ending Balance at December 31	$	119		$	86		$	205		$	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	$	6		$	2		$	8		$	5		$	(16	)	$	(11	)

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, 2012 and 2011.

Healthcare Legislation

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 2012, $6 million in 2011 and $7 million in 2010.

Grantor Trust

DTE Gas 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 DTE Gas can revoke the trust subject to providing the MPSC with prior notification. The Company accounts for its investment at fair value, approximately $14 million at December 31, 2012, with unrealized gains and losses recorded to earnings. The Grantor Trust investment is included in Other investments on the Consolidated Statements of Financial Position.

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Long-Term Debt (Details 1) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 770
Mortgages [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.65%
Debt Instrument, Face Amount	250
Mortgages 1 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.95%
Debt Instrument, Face Amount	250
Junior Subordinated Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.25%
Debt Instrument, Face Amount	200
Mortgages 2 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.92%
Debt Instrument, Face Amount	$ 70

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2012

Segment Reporting [Abstract]

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

	2012			2011			2010
	(In millions)
Electric	$	29		$	33		$	30
Gas	4			2			—
Gas Storage and Pipelines	6			8			4
Power and Industrial Projects	801			238			161
Energy Trading	43			70			89
Corporate and Other	(37		)	(50		)	(65		)
Discontinued Operations	2			—			—
	$	848		$	301		$	219

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)
2012
Electric	$	5,293		$	827	$	(1	)	$	272		$	280		$	483		$	17,755		$	1,208	$	1,230
Gas	1,315			92		(7		)	59			50			115			4,059			745		220
Gas Storage and Pipelines	96			8		(8		)	8			39			61			668			22		233
Power and Industrial Projects	1,823			65		(7		)	37			(44		)	42			991			26		83
Energy Trading	1,109			2		—			8			7			12			629			17		1
Corporate and Other	3			1		(52		)	121			(46		)	(47		)	3,074			—		3
Reclassifications and Eliminations	(848		)	—		65			(65		)	—			—			(837		)	—		—
Total from Continuing Operations	$	8,791		$	995	$	(10	)	$	440		$	286		666			26,339			2,018		1,770
Discontinued Operations (Note 7)															(56		)	—			—		49
Total															$	610		$	26,339		$	2,018	$	1,819

	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	$	5,154		$	818	$	(1	)	$	289		$	265		$	434		$	17,567		$	1,208	$	1,203
Gas	1,505			89		(7		)	64			60			110			4,065			745		179
Gas Storage and Pipelines	91			6		(5		)	7			35			57			538			22		16
Power and Industrial Projects	1,129			60		(8		)	32			11			38			789			26		56
Energy Trading	1,276			3		—			9			34			52			612			17		1
Corporate and Other	4			1		(47		)	145			(136		)	23			2,605			—		—
Reclassifications and Eliminations	(301		)	—		58			(58		)	(1		)	—			(485		)	—		—
Total from Continuing Operations	$	8,858		$	977	$	(10	)	$	488		$	268		$	714		$	25,691		$	2,018	$	1,455
Discontinued Operations (Note 7)															(3		)	318			2		29
Total															$	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	$	4,993		$	849	$	(1	)	$	313		$	270		$	441		$	16,611		$	1,206	$	864
Gas	1,648			92		(9		)	66			67			127			3,925			759		147
Gas Storage and Pipelines	83			5		(1		)	6			32			51			446			9		5
Power and Industrial Projects	1,144			60		(3		)	33			3			85			872			27		53
Energy Trading	875			5		—			13			5			6			513			17		1
Corporate & Other	1			1		(47		)	160			(62		)	(72		)	2,616			—		—
Reclassifications and Eliminations	(219		)	—		49			(48		)	—			—			(413		)	—		—
Total from Continuing Operations	$	8,525		$	1,012	$	(12	)	$	543		$	315		$	638		$	24,570		$	2,018	$	1,070
Discontinued Operations (Note 7)															(8		)	326			2		27
Total															$	630		$	24,896		$	2,020	$	1,097

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

A reconciliation of the asset retirement obligations for 2012 follows:

	(In millions)
Asset retirement obligations at December 31, 2011	$	1,593
Accretion	100
Liabilities incurred	27
Liabilities settled	(11		)
Revision in estimated cash flows	10
Asset retirement obligations at December 31, 2012	1,719

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Supplemental Cash Flow Information (Notes)

12 Months Ended

Dec. 31, 2012

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:

	2012			2011			2010
	(In millions)
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	52		$	71		$	79
Inventories	35			(129		)	(133		)
Recoverable pension and postretirement costs	141			(620		)	(32		)
Accrued/prepaid pensions	280			432			67
Accounts payable	40			(23		)	12
Income taxes payable/receivable	30			249			(245		)
Derivative assets and liabilities	53			(94		)	(48		)
Postretirement obligation	(323		)	209			(24		)
Regulatory assets	122			38			(37		)
Other assets	117			(28		)	(15		)
Other liabilities	(105		)	(11		)	83
	$	442		$	94		$	(293	)

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

	2012		2011			2010
	(In millions)
Cash paid (received) for:
Interest (net of interest capitalized)	$	438	$	485		$	551
Income taxes	$	173	$	(205	)	$	93

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

	2012		2011		2010
	(In millions)
Common stock issued for employee benefit plans	$	114	$	1	$	156
Change in capital expenditures not paid	$	23	$	76	$	20

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Segment Information (Notes)

12 Months Ended

Dec. 31, 2012

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 segment consists principally of DTE Electric, 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 segment consists of DTE Gas and Citizens.  DTE Gas 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.

Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers; and 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 state and local income tax provisions 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. The subsidiaries record federal, state and local income taxes payable to or receivable from DTE Energy based on the federal, state and local 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 the sale of reduced emissions fuel, power sales, gas sales and coal transportation services in the following segments:

	2012			2011			2010
	(In millions)
Electric	$	29		$	33		$	30
Gas	4			2			—
Gas Storage and Pipelines	6			8			4
Power and Industrial Projects	801			238			161
Energy Trading	43			70			89
Corporate and Other	(37		)	(50		)	(65		)
Discontinued Operations	2			—			—
	$	848		$	301		$	219

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)
2012
Electric	$	5,293		$	827	$	(1	)	$	272		$	280		$	483		$	17,755		$	1,208	$	1,230
Gas	1,315			92		(7		)	59			50			115			4,059			745		220
Gas Storage and Pipelines	96			8		(8		)	8			39			61			668			22		233
Power and Industrial Projects	1,823			65		(7		)	37			(44		)	42			991			26		83
Energy Trading	1,109			2		—			8			7			12			629			17		1
Corporate and Other	3			1		(52		)	121			(46		)	(47		)	3,074			—		3
Reclassifications and Eliminations	(848		)	—		65			(65		)	—			—			(837		)	—		—
Total from Continuing Operations	$	8,791		$	995	$	(10	)	$	440		$	286		666			26,339			2,018		1,770
Discontinued Operations (Note 7)															(56		)	—			—		49
Total															$	610		$	26,339		$	2,018	$	1,819

	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	$	5,154		$	818	$	(1	)	$	289		$	265		$	434		$	17,567		$	1,208	$	1,203
Gas	1,505			89		(7		)	64			60			110			4,065			745		179
Gas Storage and Pipelines	91			6		(5		)	7			35			57			538			22		16
Power and Industrial Projects	1,129			60		(8		)	32			11			38			789			26		56
Energy Trading	1,276			3		—			9			34			52			612			17		1
Corporate and Other	4			1		(47		)	145			(136		)	23			2,605			—		—
Reclassifications and Eliminations	(301		)	—		58			(58		)	(1		)	—			(485		)	—		—
Total from Continuing Operations	$	8,858		$	977	$	(10	)	$	488		$	268		$	714		$	25,691		$	2,018	$	1,455
Discontinued Operations (Note 7)															(3		)	318			2		29
Total															$	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	$	4,993		$	849	$	(1	)	$	313		$	270		$	441		$	16,611		$	1,206	$	864
Gas	1,648			92		(9		)	66			67			127			3,925			759		147
Gas Storage and Pipelines	83			5		(1		)	6			32			51			446			9		5
Power and Industrial Projects	1,144			60		(3		)	33			3			85			872			27		53
Energy Trading	875			5		—			13			5			6			513			17		1
Corporate & Other	1			1		(47		)	160			(62		)	(72		)	2,616			—		—
Reclassifications and Eliminations	(219		)	—		49			(48		)	—			—			(413		)	—		—
Total from Continuing Operations	$	8,525		$	1,012	$	(12	)	$	543		$	315		$	638		$	24,570		$	2,018	$	1,070
Discontinued Operations (Note 7)															(8		)	326			2		27
Total															$	630		$	24,896		$	2,020	$	1,097

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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, 2009		$ 3,257	$ 3,168	$ (147)	$ 38	$ 6,316
Beginning Balance, shares at Dec. 31, 2009		165,400,000
Net Income	639		630			639
Net Income (Loss) Attributable to Noncontrolling Interest	9				9
Dividends declared on common stock			(367)			(367)
Stock Issued During Period, Shares, New Issues		777,000
Issuance of common stock, value		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				2		2
Net change in unrealized losses on investments, net of tax				(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
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(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		3,440	3,431	(149)	45	6,767
Ending Balance, shares at Dec. 31, 2010		169,428,000
Beginning Balance at Sep. 30, 2010
Net Income			711			720
Dividends declared on common stock			(392)			(392)
Issuance of common stock, value						36
Ending Balance at Dec. 31, 2010		3,440	3,431	(149)	45	6,767
Beginning Balance, shares at Dec. 31, 2010		169,428,000
Net Income	720
Net Income (Loss) Attributable to Noncontrolling Interest	9				9
Treasury Stock, Shares, Acquired		(1,184,000)
Treasury Stock, Value		(58)
Issuance of common stock, value	3,417					(58)
Benefit obligations, net of tax	(9)			(9)		(9)
Foreign currency translation, 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
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(10)
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
Net Income	618		610			618
Net Income (Loss) Attributable to Noncontrolling Interest	8
Dividends declared on common stock			(414)			(414)
Stock Issued During Period, Shares, New Issues		684,000
Issuance of common stock, value	3,587	39				39
Benefit obligations, net of tax	(2)			(2)		(2)
Foreign currency translation, net of tax	1			1
Net change in unrealized losses on derivatives, net of tax	0
Net change in unrealized losses on investments, net of tax				1		1
Stock-based compensation, distributions to noncontrolling interests and other, shares		1,086,000
Stock-based compensation, distributions to noncontrolling interests and other		51				35
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(14)
Contribution of Common Stock to Pension Plan Shares		1,335,000
Contribution of Common Stock to Pension Plan		80				80
Repurchase of common stock						1
Ending Balance at Dec. 31, 2012	$ 7,411	$ 3,587	$ 3,944	$ (158)	$ 38	$ 7,411
Ending Balance, shares at Dec. 31, 2012	172,351,680	172,352,000

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Supplementary Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly earnings per share may not equal full year totals, 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)
2012
Operating Revenues	$	2,239	$	2,013		$	2,190	$	2,349		$	8,791
Operating Income	$	312	$	294		$	406	$	267		$	1,279
Net Income Attributable to DTE Energy Company
Continuing Operations	$	156	$	147		$	226	$	137		$	666
Discontinued Operations	—		(1		)	1		(56		)	(56		)
Net Income Attributable to DTE Energy Company	$	156	$	146		$	227	$	81		$	610
Basic Earnings per Share
Continuing Operations	$	0.91	$	0.87		$	1.31	$	0.79		$	3.89
Discontinued Operations	—		(0.01		)	0.01		(0.32		)	(0.33		)
Total	$	0.91	$	0.86		$	1.32	$	0.47		$	3.56
Diluted Earnings per Share
Continuing Operations	$	0.91	$	0.87		$	1.30	$	0.79		$	3.88
Discontinued Operations	—		(0.01		)	0.01		(0.32		)	(0.33		)
Total	$	0.91	$	0.86		$	1.31	$	0.47		$	3.55

2011
Operating Revenues	$	2,423		$	2,018		$	2,254	$	2,163		$	8,858
Operating Income	$	389		$	288		$	398	$	346		$	1,421
Net Income Attributable to DTE Energy Company
Continuing Operations (a)	$	177		$	203		$	183	$	151		$	714
Discontinued Operations	(1		)	(1		)	—		(1		)	(3		)
Net Income Attributable to DTE Energy Company	$	176		$	202		$	183	$	150		$	711
Basic Earnings per Share
Continuing Operations	$	1.05		$	1.19		$	1.08	$	0.88		$	4.21
Discontinued Operations	(0.01		)	—			—		—			(0.02		)
Total	$	1.04		$	1.19		$	1.08	$	0.88		$	4.19
Diluted Earnings per Share
Continuing Operations	$	1.05		$	1.19		$	1.07	$	0.88		$	4.20
Discontinued Operations	(0.01		)	—			—		—			(0.02		)
Total	$	1.04		$	1.19		$	1.07	$	0.88		$	4.18

_______________________________________

(a) 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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Property, Plant and Equipment (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Electric [Abstract]
Property Plant and Equipment Accumulated Depreciation Nonutility and Other	$ (659)	$ (688)
Gas [Abstract]
Non-utility and other	1,921	1,884
Total	23,631	22,541
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	(8,947)	(8,795)
Net Property, Plant and Equipment	14,684	13,746
Electric Generation [Member]
Electric [Abstract]
Generation	10,383	9,785
Generation	(3,880)	(3,946)
Electric Distribution [Member]
Electric [Abstract]
Distribution	7,306	7,003
Distribution	(2,837)	(2,580)
Electric Generation, Transmission and Distribution Equipment [Member]
Electric [Abstract]
Total Electric	(6,717)	(6,526)
Public Utilities, Property, Plant and Equipment, Plant in Service	17,689	16,788
Gas Distribution [Member]
Electric [Abstract]
Distribution	2,735	2,561
Distribution	(1,075)	(1,041)
Storage [Member]
Gas [Abstract]
Storage	434	406
Storage	(133)	(127)
Other [Member]
Gas [Abstract]
Other	852	902
Other	(363)	(413)
Gas Distribution and Storage [Member]
Electric [Abstract]
Total Electric	(1,571)	(1,581)
Public Utilities, Property, Plant and Equipment, Plant in Service	$ 4,021	$ 3,869

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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, 2012	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Regulatory Assets			$ 4,417	$ 4,853
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Accumulated benefit obligation, end of year			4,349	3,881
Benefit obligation, beginning of year	4,195	3,785	4,195	3,785
Service cost			82	69	64
Interest cost			204	202	202
Actuarial loss			474	355
Special termination benefits			2	2	0
Benefits paid			(228)	(218)
Benefit obligation, end of year			4,729	4,195	3,785
Plan assets at fair value, beginning of the year	2,886	2,913	2,886	2,913
Actual return on plan assets			325	(18)
Company contributions	315	229	240	209
Plan assets at fair value, end of the year			3,223	2,886	2,913
Funded status of the plans			(1,506)	(1,309)
Current liabilities			(8)	(11)
Noncurrent liabilities			(1,498)	(1,298)
Pension and Other Postretirement Defined Benefit Plans, Liabilities			(1,506)	(1,309)
Net actuarial loss			205	202
Prior serice cost (credit)			(2)	(3)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax			203	199
Net actuarial loss			2,413	2,201
Prior service cost			7	7
Regulatory Assets			$ 2,420	$ 2,208

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Acquisition Acquisition (Tables)

12 Months Ended

Dec. 31, 2012

Business Combinations [Abstract]

Schedule of Purchase Price Allocation [Table Text Block]

	(In millions)
Cash	$	22
Accounts receivable	14
Other current assets	8
Property, plant and equipment	100
Intangible assets	75
Other noncurrent assets	9
Current liabilities	(7		)
Non-controlling interest	(1		)
Total purchase price	$	220

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Retirement Benefits and Trusteed Assets (Tables)

12 Months Ended

Dec. 31, 2012

Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]

Schedule of Net Benefit Costs [Table Text Block]

	2012			2011			2010
	(In millions)
Service cost	$	82		$	69		$	64
Interest cost	204			202			202
Expected return on plan assets	(244		)	(246		)	(258		)
Amortization of:
Net loss	176			142			100
Prior service cost	—			3			4
Special termination benefits	2			2			—
Net pension cost	$	220		$	172		$	112

Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]

	2012			2011
	(In millions)
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income
Net actuarial loss	$	395		$	619
Amortization of net actuarial loss	(178		)	(142		)
Amortization of prior service cost	—			(3		)
Total recognized Regulatory assets and Other comprehensive income	$	217		$	474
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	437		$	646
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	$	202		$	171

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

	2012			2011
	(In millions)
Accumulated benefit obligation, end of year	$	4,349		$	3,881
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	4,195		$	3,785
Service cost	82			69
Interest cost	204			202
Actuarial loss	474			355
Special termination benefits	2			2
Benefits paid	(228		)	(218		)
Projected benefit obligation, end of year	$	4,729		$	4,195
Change in plan assets
Plan assets at fair value, beginning of year	$	2,886		$	2,913
Actual return on plan assets	325			(18		)
Company contributions	240			209
Benefits paid	(228		)	(218		)
Plan assets at fair value, end of year	$	3,223		$	2,886
Funded status of the plans	$	(1,506	)	$	(1,309	)
Amount recorded as:
Current liabilities	$	(8	)	$	(11	)
Noncurrent liabilities	(1,498		)	(1,298		)
	$	(1,506	)	$	(1,309	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	205		$	202
Prior service (credit)	(2		)	(3		)
	$	203		$	199
Amounts recognized in Regulatory assets (see Note 11)
Net actuarial loss	$	2,413		$	2,201
Prior service cost	7			7
	$	2,420		$	2,208

Schedule of Expected Benefit Payments [Table Text Block]

At December 31, 2012, 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)
2013	$	236
2014	242
2015	252
2016	260
2017	269
2018-2022	1,485
	$	2,744

Schedule of Assumptions Used [Table Text Block]

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

	2012		2011		2010
Projected benefit obligation
Discount rate	4.15	%	5.00	%	5.50	%
Rate of compensation increase	4.20	%	4.20	%	4.00	%
Net pension costs
Discount rate	5.00	%	5.50	%	5.90	%
Rate of compensation increase	4.20	%	4.00	%	4.00	%
Expected long-term rate of return on plan assets	8.25	%	8.50	%	8.75	%

Schedule of Allocation of Plan Assets [Table Text Block]

Target allocations for plan assets as of December 31, 2012 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, 2012 and 2011 (a):

	December 31, 2012								December 31, 2011
	Level 1		Level 2		Level 3		Net Balance		Level 1		Level 2		Level 3		Net Balance
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	24	$	—	$	24	$	—	$	33	$	—	$	33
Equity securities															—
U.S. Large Cap (c)	688		44		—		732		640		40		—		680
U.S. Small/Mid Cap (d)	153		5		—		158		159		5		—		164
Non U.S (e)	530		120		—		650		392		114		—		506
Fixed income securities (f)	87		765		—		852		88		703		—		791
Hedge Funds and Similar Investments (g)	209		80		339		628		190		58		296		544
Private Equity and Other (h)	—		—		179		179		—		—		168		168
Total	$	1,667	$	1,038	$	518	$	3,223	$	1,469	$	953	$	464	$	2,886

_______________________________________

Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets [Table Text Block]

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

	Year Ended December 31, 2012									Year Ended December 31, 2011
	Hedge Funds and Similar Investments			Private Equity and Other			Total			Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1	$	296		$	168		$	464		$	304		$	174		$	478
Total realized/unrealized gains (losses):
Realized gains (losses)	18			(6		)	12			(4		)	6			2
Unrealized gains (losses)	(5		)	12			7			1			(30		)	(29		)
Purchases, sales and settlements:
Purchases	250			33			283			64			23			87
Sales	(220		)	(28		)	(248		)	(69		)	(5		)	(74		)
Ending Balance at December 31	$	339		$	179		$	518		$	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	$	16		$	6		$	22		$	4		$	(28	)	$	(24	)

Schedule of Net Postretirement Costs [Table Text Block]

Net postretirement cost includes the following components:

	2012			2011			2010
	(In millions)
Service cost	$	68		$	64		$	61
Interest cost	120			121			125
Expected return on plan assets	(92		)	(94		)	(74		)
Amortization of:
Net loss	80			55			54
Prior service credit	(27		)	(26		)	(4		)
Net transition asset	2			2			2
Net postretirement cost	$	151		$	122		$	164

Schedule of Postretirement Plan Amounts Recognized in Regulatory Assets and Other Comprehensive Income [Table Text Block]

	2012			2011
	(In millions)
Other changes in plan assets and APBO recognized in Regulatory assets and Other comprehensive income (in millions)
Net actuarial (gain) loss	$	(34	)	$	195
Amortization of net actuarial loss	(80		)	(55		)
Prior service credit	(264		)	(4		)
Amortization of prior service credit	27			26
Amortization of transition asset	(2		)	(2		)
Total recognized in Regulatory assets and Other comprehensive income	$	(353	)	$	160
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	(202	)	$	282
Estimated amounts to be amortized from Regulatory assets and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year (in millions)
Net actuarial loss	$	69		$	78
Prior service credit	$	(91	)	$	(27	)
Net transition obligation	$	—		$	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:

	2012			2011
	(In millions)
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation, beginning of year	$	2,470		$	2,305
Service cost	68			64
Interest cost	120			121
Plan amendments	(264		)	(4		)
Actuarial loss	5			80
Medicare Part D subsidy	6			6
Benefits paid	(90		)	(102		)
Accumulated postretirement benefit obligation, end of year	$	2,315		$	2,470
Change in plan assets
Plan assets at fair value, beginning of year	$	985		$	1,029
Actual return on plan assets	131			(22		)
Company contributions	140			111
Benefits paid	(103		)	(133		)
Plan assets at fair value, end of year	$	1,153		$	985
Funded status, end of year	$	(1,162	)	$	(1,485	)
Amount recorded as:
Current liabilities	$	(2	)	$	(1	)
Noncurrent liabilities	$	(1,160	)	$	(1,484	)
	$	(1,162	)	$	(1,485	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	40		$	47
Prior service credit	(14		)	(20		)
Net transition asset	(1		)	(1		)
	$	25		$	26
Amounts recognized in Regulatory assets (See Note 11)
Net actuarial loss	$	727		$	835
Prior service cost	(302		)	(60		)
Net transition obligation	1			3
	$	426		$	778

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:

	2012		2011		2010
Projected benefit obligation
Discount rate	4.15	%	5.00	%	5.50	%
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
Net benefit costs
Discount rate	5.00	%	5.50	%	5.90	%
Expected long-term rate of return on plan assets	8.25	%	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	2020		2019		2016

Schedule of Allocation of Plan Assets OPEB [Table Text Block]

Target allocations for plan assets as of December 31, 2012 are listed below:

U.S. Domestic Equity Securities	21	%
Non U.S. Equity Securities	20
Fixed Income Securities	25
Hedge Funds and Similar Investments	20
Private Equity and Other	14
	100	%

Other Postretirement Benefit Plans Hierachy Level [Table Text Block]

Fair Value Measurements at December 31, 2012 and 2011(a):

	December 31, 2012								December 31, 2011
	Level 1		Level 2		Level 3		Net Balance		Level 1		Level 2		Level 3		Net Balance
Asset Category:	(In millions)
Short-term investments (b)	$	1	$	2	$	—	$	3	$	—	$	13	$	—	$	13
Equity securities:
U.S. Large Cap (c)	189		3		—		192		175		15		—		190
U.S. Small/Mid Cap (d)	105		—		—		105		70		6		—		76
Non U.S (e)	230		7		—		237		176		14		—		190
Fixed income securities (f)	38		247		—		285		24		236		—		260
Hedge Funds and Similar Investments (g)	102		24		119		245		80		21		95		196
Private Equity and Other (h)	—		—		86		86		—		—		60		60
Total	$	665	$	283	$	205	$	1,153	$	525	$	305	$	155	$	985

_______________________________________

(

Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets OPEB [Table Text Block]

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

	Year Ended December 31, 2012									Year Ended December 31, 2011
	Hedge Funds and Similar Investments			Private Equity and Other			Total			Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1	$	95		$	60		$	155		$	79		$	55		$	134
Total realized/unrealized gains (losses):
Realized gains (losses)	6			(11		)	(5		)	(1		)	2			1
Unrealized gains (losses)	—			14			14			2			(22		)	(20		)
Purchases, sales and settlements:
Purchases	86			36			122			68			48			116
Sales	(68		)	(13		)	(81		)	(53		)	(23		)	(76		)
Ending Balance at December 31	$	119		$	86		$	205		$	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	$	6		$	2		$	8		$	5		$	(16	)	$	(11	)

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Fair Value (Details 7) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Option, Quantitative Disclosures [Line Items]
Nuclear decommissioning trusts	$ 1,037	$ 937
Unrealized Gains	149	102
Equity securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Equity securities	631	533
Unrealized Gains	122	80
Debt securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Debt securities	399	385
Unrealized Gains	27	22
Cash and cash equivalents [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Cash and cash equivalents	7	19
Unrealized Gains	$ 0	$ 0

XML

Consolidated Statements of Operations (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Revenues	$ 8,791	$ 8,858	$ 8,525
Operating Expenses
Fuel, purchased power and gas	3,296	3,537	3,190
Operation and maintenance	2,892	2,612	2,567
Depreciation, depletion and amortization	995	977	1,012
Taxes other than income	332	310	306
Asset (gains) and losses, reserves and impairments, net	(3)	1	(20)
Total operating expenses	7,512	7,437	7,055
Operating Income	1,279	1,421	1,470
Other (Income) and Deductions
Interest expense	440	488	543
Interest income	(10)	(10)	(12)
Other income	(173)	(117)	(78)
Other expenses	62	69	55
Total Other (Income) and Deductions	319	430	508
Income Before Income Taxes	960	991	962
Income Tax Expense	286	268	315
Income from Continuing Operations	674	723	647
Discontinued Operations (Loss), net of tax	(56.00)	(3.00)	(8.00)
Net Income	618	720	639
Less: Net Income Attributable to Noncontrolling Interests	8	9	9
Net Income Attributable to DTE Energy Company	$ 610	$ 711	$ 630
Basic Earnings per Common Share
Net Income Attributable to DTE Energy Company	$ 3.56	$ 4.19	$ 3.75
Income from continuing operations	$ 3.89	$ 4.21	$ 3.79
Discontinued operations	$ (0.33)	$ (0.02)	$ (0.04)
Diluted Earnings per Common Share
Net Income Attributable to DTE Energy Company	$ 3.55	$ 4.18	$ 3.74
Income from continuing operations	$ 3.88	$ 4.20	$ 3.78
Discontinued operations	$ (0.33)	$ (0.02)	$ (0.04)
Weighted Average Common Shares Outstanding
Basic	171	169	168
Diluted	172	170	169
Dividends Declared per Common Share	$ 2.42	$ 2.32	$ 2.18

XML

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2012

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:

	2012			2011
	(In millions)
Assets
Recoverable pension and postretirement costs:
Pension	$	2,420		$	2,208
Postretirement costs	426			778
Asset retirement obligation	424			420
Recoverable Michigan income taxes	304			324
Recoverable income taxes related to securitized regulatory assets	226			316
Cost to achieve Performance Excellence Process	96			116
Accrued PSCR/GCR revenue	87			147
Other recoverable income taxes	76			81
Choice incentive mechanism	66			166
Unamortized loss on reacquired debt	63			64
Deferred environmental costs	58			49
Recoverable restoration expense	49			58
Recoverable revenue decoupling	28			18
Enterprise Business Systems costs	16			18
Other	78			90
	4,417			4,853
Less amount included in current assets	(182		)	(314		)
	$	4,235		$	4,539
Securitized regulatory assets	$	413		$	577

	2012			2011
	(In millions)
Liabilities
Asset removal costs	$	439		$	419
Renewable energy	230			192
Refundable revenue decoupling/deferred gain	127			127
Negative pension offset	105			120
Refundable income taxes	56			66
Over recovery of Securitization	54			53
Refundable uncollectible expense	37			31
Energy Optimization	34			34
Accrued PSCR/GCR refund	16			26
Fermi 2 refueling outage	12			23
Low Income Energy Efficiency Fund	—			26
Other	10			9
	1,120			1,126
Less amount included in current liabilities	(89		)	(107		)
	$	1,031		$	1,019

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Common Stock (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Class of Stock [Line Items]
Contribution of Common stock to the Pension Plan Value	$ 80	$ 100
Days to Contrbute Common Stock to Pension Plan	4 days
Maximum Total Funded Debt to Total Capitalization Ratio	0.65
Minimum Total Funded Debt to Total Capitilization Ration Denominator	1
Line of Credit Facility, Dividend Restrictions	239
Retained Earnings (Accumulated Deficit)	3,944	3,750
Limitations with Respect of Company's Ability to Pay Dividends	0
Retained Earnings [Member]
Class of Stock [Line Items]
Retained Earnings (Accumulated Deficit)	$ 4,000

XML

Stock-Based Compensation (Details 6) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Compensation Expense Recorded [Line Items]
Compensation expense	$ 83	$ 66	$ 52
Performance Share Awards [Member]
Compensation Expense Recorded [Line Items]
Compensation expense	71	53	36
Cash settlements (1)	4	3	3
Stock settlements (1)	$ 41	$ 25	$ 23

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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, 2012	Dec. 31, 2011
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ 395	$ 619
Amortization of net actuarial loss	(178)	(142)
Amortization of prior service cost	0	(3)
Total recognized Regulatory assets and Other comprehensive income	217	474
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	437	646
Net actuarial loss	$ 202	$ 171

XML

Consolidated Statements of Financial Position (Parenthetical) (Parentheticals) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Allowance for doubtful accounts	$ 62	$ 162
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	400,000,000	400,000,000
Common stock, shares issued	172,351,680	169,247,282
Common stock, shares outstanding	172,351,680	169,247,282

XML

Income Taxes (Details 3) (Uncertain Tax Positions [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Uncertain Tax Positions [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits	$ 11	$ 48	$ 28	$ 81
Additions for tax positions of prior years	0	27	4
Reductions for tax positions of prior years	(2)	(4)	(4)
Additions for tax positions related to the current year	1	1	0
Settlements	(30)	(3)	(53)
Lapse of statute of limitations	$ (6)	$ (1)	$ 0

XML

Stock-Based Compensation (Details Textuals) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 performance	Dec. 31, 2011	Dec. 31, 2010
Schedule of Stock Based Compensation [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	11,500,000
Performance Units	1,000,000
Performance Units Price per Unit	1.00
Expiration Period After Date of Grant	10 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	4 years 3 months 20 days
Non Vested Stock Options	200,844
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Exercisable, Number	332,026
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value	$ 25	$ 20	$ 9
Stock or Unit Option Plan Expense	0.7	2.0	4.0
Unrecognized Compensation Cost	$ 58
Weighted Average to be Recognized	1 year 4 months 15 days
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

Supplemental Cash Flow Information (Details 1) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Other Significant Noncash Transactions [Line Items]
Interest (net of interest capitalized)	$ 438	$ 485	$ 551
Income taxes	$ 173	$ (205)	$ 93

XML

Organization and Basis of Presentation (Details Textuals) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012 customers
Legal Entities [Line Items]
Number of Electric Customers	2,100,000
Number of Gas Customers	1,200,000
Significant Potential Exposure to Loss Due to VIE Long-Term Purchase Contracts	$ 0

XML

Long-Term Debt (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Securitization bonds	$ 302	$ 479
Long-term Debt	7,813	7,682
Less amount due within one year	(634)	(355)
Long-term Debt, Excluding Current Maturities	6,220	6,405
Long-term Transition Bond	302	479
DTE Energy Unsecured Debt 5.4% due in 2013 to 2033 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End	5.40%
DTE Energy Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt	1,298	1,298
DTE Electric Taxable Debt Principally Secured 5.0% due in 2013 to 2042 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End	5.00%
DTE Electric Tax-Exempt Revenue Bonds 5.3% due in 2014 to 2038 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End	5.30%
Tax Exempt Revenue Bonds [Member]
Debt Instrument [Line Items]
Long-term Debt	707	893
DTE Gas Taxable Debt Principally Secured 5.6% due in 2013 to 2042 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End	5.60%
Long-term Debt [Member]
Debt Instrument [Line Items]
Long-term Debt	153	165
Total [Member]
Debt Instrument [Line Items]
Long-term Debt	6,854	6,760
Junior Subordinated Notes	480	280
Securitization Bonds 6.6% due in 2013 to 2015 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End	6.60%
Securitization Bonds [Member]
Debt Instrument [Line Items]
Securitization bonds	479	643
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	280
Junior Subordinated Debentures 5.25% due 2062 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End	5.25%
Subordinated Debt [Member]
Debt Instrument [Line Items]
Junior Subordinated Debentures	200	0
DTE Electric [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt	3,777	3,515
DTE Gas [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt	919	889
Securitization Bonds [Member]
Debt Instrument [Line Items]
Less amount due within one year	$ (177)	$ (164)

XML

Organization and Basis of Presentation (Tables)

12 Months Ended

Dec. 31, 2012

Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]

Schedule of Variable Interest Entities [Table Text Block]

	December 31, 2012								December 31, 2011
	Securitization		Other		Total		Restricted Amounts		Securitization		Other		Total		Restricted Amounts
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	10	$	10	$	8	$	—	$	25	$	25	$	—
Restricted cash	102		7		109		109		107		7		114		114
Accounts receivable	34		7		41		38		34		17		51		36
Inventories	—		141		141		3		—		183		183		—
Other current assets	—		1		1		1		—		1		1		—
Property, plant and equipment	—		93		93		49		—		73		73		23
Securitized regulatory assets	413		—		413		413		577		—		577		577
Other assets	7		11		18		18		10		6		16		16
	$	556	$	270	$	826	$	639	$	728	$	312	$	1,040	$	766
LIABILITIES
Accounts payable and accrued current liabilities	$	11	$	14	$	25	$	12	$	14	$	24	$	38	$	14
Current portion long-term debt, including capital leases	177		8		185		185		164		7		171		171
Other current liabilities	50		4		54		53		55		—		55		55
Mortgage bonds, notes and other	—		25		25		25		—		30		30		30
Securitization bonds	302		—		302		302		479		—		479		479
Capital lease obligations	—		11		11		11		—		14		14		14
Other long-term liabilities	7		2		9		8		7		2		9		8
	$	547	$	64	$	611	$	596	$	719	$	77	$	796	$	771

Summary of amounts for non-consolidated VIEs [Table Text Block

	December 31, 2012		December 31, 2011
	(In millions)
Other investments	$	130	$	117
Notes receivable	6		7

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Stock-Based Compensation (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2012
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Number of Options	1,192,670
Weighted Average Exercise Price	$ 41.86
Weighted Average Remaining Contractual Life (Years)	4 years 9 months 11 days
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	142,619
Weighted Average Exercise Price	$ 27.98
Weighted Average Remaining Contractual Life (Years)	6 years 1 month 23 days
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	291,982
Weighted Average Exercise Price	$ 41.14
Weighted Average Remaining Contractual Life (Years)	3 years 2 months 19 days
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	605,569
Weighted Average Exercise Price	$ 44.03
Weighted Average Remaining Contractual Life (Years)	5 years 4 months 24 days
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	152,500
Weighted Average Exercise Price	$ 47.62
Weighted Average Remaining Contractual Life (Years)	4 years 0 months 11 days

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Fair Value (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	$ 123	$ 140
Assets [Abstract]
Nuclear decommissioning trusts	1,037	937
Other investments	110	95
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	1,016	2,805
Derivative Assets	1,417	1,468
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(1,020)	(2,811)
Derivative Liabilities	(151)	(247)
Derivative Assets (Liabilities), at Fair Value, Net	1,266	1,221
Derivative Assets, Current	108	222
Derivative Assets, Noncurrent	39	74
Derivative Liabilities, Current	125	158
Derivative Liabilities, Noncurrent	26	89
Current Asset [Member]
Derivative liabilities [Abstract]
Derivative Assets, Current	231	362
Non Current Asset [Member]
Derivative liabilities [Abstract]
Derivative Assets, Noncurrent	1,186	1,106
Current Liability [Member]
Derivative liabilities [Abstract]
Derivative Liabilities, Current	(125)	(158)
Noncurrent Liability [Member]
Derivative liabilities [Abstract]
Derivative Liabilities, Noncurrent	(26)	(89)
Foreign currency exchange contracts [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	(2)
Interest rate contracts [Member]
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(1)	(1)
Natural Gas [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	40	33
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(56)	(104)
Electricity [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	102	257
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(93)	(140)
Other [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	5	6
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(1)	0
Total derivative assets [Member]
Derivative assets [Abstract]
Derivative Assets	147	296
Total derivative liabilities [Member]
Derivative liabilities [Abstract]
Derivative Liabilities	(151)	(247)
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	0	0
Assets [Abstract]
Nuclear decommissioning trusts	694	577
Other investments	66	57
Derivative assets [Abstract]
Derivative Assets	1,321	2,583
Derivative liabilities [Abstract]
Derivative Liabilities	(532)	(1,959)
Derivative Assets (Liabilities), at Fair Value, Net	789	624
Derivative Assets, Current	493	1,571
Derivative Assets, Noncurrent	828	1,012
Derivative Liabilities, Current	(466)	(1,603)
Derivative Liabilities, Noncurrent	(66)	(356)
Fair Value, Inputs, Level 1 [Member] | Foreign currency exchange contracts [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Interest rate contracts [Member]
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Natural Gas [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	555	1,926
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(526)	(1,940)
Fair Value, Inputs, Level 1 [Member] | Electricity [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Other [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	6	23
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(6)	(19)
Fair Value, Inputs, Level 1 [Member] | Total derivative assets [Member]
Derivative assets [Abstract]
Derivative Assets	561	1,949
Fair Value, Inputs, Level 1 [Member] | Total derivative liabilities [Member]
Derivative liabilities [Abstract]
Derivative Liabilities	(532)	(1,959)
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	123	140
Assets [Abstract]
Nuclear decommissioning trusts	343	360
Other investments	44	38
Derivative assets [Abstract]
Derivative Assets	805	1,144
Derivative liabilities [Abstract]
Derivative Liabilities	(315)	(646)
Derivative Assets (Liabilities), at Fair Value, Net	490	498
Derivative Assets, Current	372	660
Derivative Assets, Noncurrent	433	484
Derivative Liabilities, Current	(269)	(527)
Derivative Liabilities, Noncurrent	(46)	(119)
Fair Value, Inputs, Level 2 [Member] | Foreign currency exchange contracts [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	3
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	(5)
Fair Value, Inputs, Level 2 [Member] | Interest rate contracts [Member]
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(1)	(1)
Fair Value, Inputs, Level 2 [Member] | Natural Gas [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	66	78
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(73)	(126)
Fair Value, Inputs, Level 2 [Member] | Electricity [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	226	523
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(240)	(513)
Fair Value, Inputs, Level 2 [Member] | Other [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	3	2
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(1)	(1)
Fair Value, Inputs, Level 2 [Member] | Total derivative assets [Member]
Derivative assets [Abstract]
Derivative Assets	295	606
Fair Value, Inputs, Level 2 [Member] | Total derivative liabilities [Member]
Derivative liabilities [Abstract]
Derivative Liabilities	(315)	(646)
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	0	0
Assets [Abstract]
Nuclear decommissioning trusts	0	0
Other investments	0	0
Derivative assets [Abstract]
Derivative Assets	160	250
Derivative liabilities [Abstract]
Derivative Liabilities	(173)	(206)
Derivative Assets (Liabilities), at Fair Value, Net	(13)	44
Derivative Assets, Current	120	181
Derivative Assets, Noncurrent	40	69
Derivative Liabilities, Current	(144)	(152)
Derivative Liabilities, Noncurrent	(29)	(54)
Fair Value, Inputs, Level 3 [Member] | Foreign currency exchange contracts [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Interest rate contracts [Member]
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Natural Gas [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	24	20
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(62)	(14)
Fair Value, Inputs, Level 3 [Member] | Electricity [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	134	224
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(111)	(192)
Fair Value, Inputs, Level 3 [Member] | Other [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	2	6
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Total derivative assets [Member]
Derivative assets [Abstract]
Derivative Assets	160	250
Fair Value, Inputs, Level 3 [Member] | Total derivative liabilities [Member]
Derivative liabilities [Abstract]
Derivative Liabilities	(173)	(206)
Netting Adjustments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	0	0
Assets [Abstract]
Nuclear decommissioning trusts	0	0
Other investments	0	0
Derivative assets [Abstract]
Derivative Assets	(869)	(2,509)
Derivative liabilities [Abstract]
Derivative Liabilities	869	2,564
Derivative Assets (Liabilities), at Fair Value, Net	0	55
Derivative Assets, Current	(754)	(2,050)
Derivative Assets, Noncurrent	(115)	(459)
Derivative Liabilities, Current	754	2,124
Derivative Liabilities, Noncurrent	115	440
Netting Adjustments [Member] | Foreign currency exchange contracts [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	(3)
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	3
Netting Adjustments [Member] | Interest rate contracts [Member]
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Netting Adjustments [Member] | Natural Gas [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	(605)	(1,991)
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	605	1,976
Netting Adjustments [Member] | Electricity [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	(258)	(490)
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	258	565
Netting Adjustments [Member] | Other [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	(6)	(25)
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	6	20
Netting Adjustments [Member] | Total derivative assets [Member]
Derivative assets [Abstract]
Derivative Assets	(869)	(2,509)
Netting Adjustments [Member] | Total derivative liabilities [Member]
Derivative liabilities [Abstract]
Derivative Liabilities	$ 869	$ 2,564

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Earnings Per Share (Notes)

12 Months Ended

Dec. 31, 2012

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:

	2012		2011		2010
	(In millions, expect per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	610	$	711	$	630
Average number of common shares outstanding	171		169		168
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	413	$	392	$	365
Dividends declared — net restricted shares	1		1		2
Total distributed earnings	$	414	$	393	$	367
Net income less distributed earnings	$	196	$	318	$	263
Distributed (dividends per common share)	$	2.42	$	2.32	$	2.18
Undistributed	1.14		1.87		1.57
Total Basic Earnings per Common Share	$	3.56	$	4.19	$	3.75
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	610	$	711	$	630
Average number of common shares outstanding	171		169		168
Average incremental shares from assumed exercise of options	1		1		1
Common shares for dilutive calculation	172		170		169
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	413	$	392	$	365
Dividends declared — net restricted shares	1		1		2
Total distributed earnings	$	414	$	393	$	367
Net income less distributed earnings	$	196	$	318	$	263
Distributed (dividends per common share)	$	2.42	$	2.32	$	2.18
Undistributed	1.13		1.86		1.56
Total Diluted Earnings per Common Share	$	3.55	$	4.18	$	3.74

Options to purchase approximately 5 million shares of common stock in 2010 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, 2012

Accounting Policies [Abstract]

Schedule of Comprehensive Income (Loss) [Table Text Block]

	Year Ended December 31, 2012
	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 January 1, 2012	$	(4	)	$	(30	)	$	(125	)	$	1	$	(158	)
Current period change, net of tax	—			1			(2		)	1		—
Ending balances December 31, 2012	$	(4	)	$	(29	)	$	(127	)	$	2	$	(158	)

Schedule of Finite-Lived Intangible Assets by Major Class [Table Text Block]

Summary of intangible assets as of December 31, 2012 and 2011:

	2012		2011
	(In millions)
Emission allowances	$	6	$	10
Renewable energy credits	44		39
Contract intangible assets	139		65
	189		114
Less accumulated amortization	34		28
Intangible assets, net	155		$	86
Less current intangible assets	20		$	13
	$	135	$	73

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Earnings Per Share (Details Textuals) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2010
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	5

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Retirement Benefits and Trusteed Assets (Details 11) (Other Postretirement Benefit Plans, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2012
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 2013	$ 103
Defined Benefit Plan, Expected Future Benefit Payments in 2014	109
Defined Benefit Plan, Expected Future Benefit Payments in 2015	115
Defined Benefit Plan, Expected Future Benefit Payments in 2016	120
Defined Benefit Plan, Expected Future Benefit Payments in 2017	127
Defined Benefit Plan, Expected Future Benefit Payments in 2018-2022	726
Total Expected Future Benefit Payments	$ 1,300

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Preferred and Preferenced Securities

12 Months Ended

Dec. 31, 2012

Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Preferred Stock [Text Block]

PREFERRED AND PREFERENCE SECURITIES

As of December 31, 2012, the amount of authorized and unissued stock is as follows:

Company	Type of Stock	Par Value		Shares Authorized
DTE Energy	Preferred	$	—	5,000,000
DTE Electric	Preferred	$	100	6,747,484
DTE Electric	Preference	$	1	30,000,000
DTE Gas	Preferred	$	1	7,000,000
DTE Gas	Preference	$	1	4,000,000

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Fair Value Fair Value (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ (1,020,000,000)	$ (2,811,000,000)
Derivative Asset, Fair Value, Gross Asset	1,016,000,000	2,805,000,000
Electricity [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Liability, Fair Value, Gross Liability	(93,000,000)	(140,000,000)
Derivative Asset, Fair Value, Gross Asset	102,000,000	257,000,000
Natural Gas [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Liability, Fair Value, Gross Liability	(56,000,000)	(104,000,000)
Derivative Asset, Fair Value, Gross Asset	40,000,000	33,000,000
Fair Value, Inputs, Level 3 [Member] | Electricity [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Maximum Weighted Average Range for Unobservable Inputs	16
Weighted Average of Unobservable Fair Value Inputs	3
Minimum Weighted Average Range for Unobservable Inputs	(2)
Derivative Liability, Fair Value, Gross Liability	(111,000,000)	(192,000,000)
Derivative Asset, Fair Value, Gross Asset	134,000,000	224,000,000
Fair Value, Inputs, Level 3 [Member] | Natural Gas [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Maximum Weighted Average Range for Unobservable Inputs	1.95
Weighted Average of Unobservable Fair Value Inputs	0.03
Minimum Weighted Average Range for Unobservable Inputs	(0.63)
Derivative Liability, Fair Value, Gross Liability	(62,000,000)	(14,000,000)
Derivative Asset, Fair Value, Gross Asset	$ 24,000,000	$ 20,000,000

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Capital and Operating (Details 1) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Capital Lease Receivable [Line Items]
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 in 2017	12
Capital Lease Payments Receivable Thereafter	31
Total minimum future lease receipts	91
Residual value of leased pipeline	40
Less unearned income	(48)
Net Iivestment in Capital lease	83
Less current portion	(4)
Capital Leases, Lessor Balance Sheet, Net Investment in Direct Financing Leases, Noncurrent	$ 79

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Activities
Net Income	$ 618	$ 720	$ 639
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	1,018	995	1,027
Deferred income taxes	47	220	457
Gain (Loss) on Sale of Business	83	0	0
Asset (gains), losses and reserves and impairments, net	1	(21)	(5)
Changes in assets and liabilities, exclusive of changes shown separately (Note 22)	442	94	(293)
Net cash from operating activities	2,209	2,008	1,825
Investing Activities
Plant and equipment expenditures — utility	(1,451)	(1,382)	(1,011)
Plant and equipment expenditures — non-utility	(369)	(102)	(88)
Proceeds from Divestiture of Businesses	255	0	0
Proceeds from sale of assets	38	18	56
Restricted cash for debt redemption, principally Securitization	2	(5)	(32)
Payments to Acquire Businesses, Net of Cash Acquired	(198)	0	0
Proceeds from sale of nuclear decommissioning trust fund assets	97	80	377
Investment in nuclear decommissioning trust funds	(102)	(97)	(410)
Consolidation of VIEs	0	0	19
Investment in Millennium Pipeline Project	0	(3)	(49)
Other	(41)	(69)	(88)
Net cash used for investing activities	(1,769)	(1,560)	(1,226)
Financing Activities
Issuance of long-term debt, net	759	1,179	614
Redemption of long-term debt	(639)	(1,455)	(663)
Short-term borrowings	(179)	269	(177)
Issuance of common stock	39	0	36
Repurchase of common stock	0	(18)	0
Dividends on common stock	(407)	(389)	(360)
Other	(16)	(31)	(36)
Net cash used for financing activities	(443)	(445)	(586)
Net Increase (Decrease) in Cash and Cash Equivalents	(3)	3	13
Cash and Cash Equivalents at Beginning of Period	68	65	52
Cash and Cash Equivalents at End of Period	$ 65	$ 68	$ 65

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Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Statement of Income and Comprehensive Income [Abstract]
Net Income	$ 618	$ 720	$ 639
Benefit obligations:
Benefit obligation, net of taxes of $(1), $(5) and $3	(2)	(9)	5
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $-, $- and $5	0	0	10
Total Benefit obligations	(2)	(9)	15
Net unrealized gains (losses) on derivatives:
Gains during the period, net of taxes of $-, $- and $1	0	0	1
Amounts reclassified to income, net of taxes of $-, $- and $1	0	0	1
Net unrealized gains (losses) on derivatives	0	0	2
Net unrealized gains (losses) on investments:
Gains (losses) during the period, net of taxes of $1, $- and $(6)	1	0	(10)
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $-, $- and $(5)	0	0	(10)
Net unrealized gains (losses) on investments	1	0	(20)
Foreign currency translation, net of taxes of $-, $- and $-	1	0	1
Comprehensive income	0	(9)	(2)
Comprehensive income	618	711	637
Less: Comprehensive income attributable to noncontrolling interests	8	9	9
Comprehensive income attributable to DTE Energy Company	$ 610	$ 702	$ 628

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Jointly Owned Utility Plant

12 Months Ended

Dec. 31, 2012

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

Jointly Owned Utility Plant [Text Block]

JOINTLY OWNED UTILITY PLANT

DTE Electric has joint ownership interest in two power plants, Belle River and Ludington Hydroelectric Pumped Storage. DTE Electric’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, 2012 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	(a)			49		%
Investment (in millions)	$	1,661		$	199
Accumulated depreciation (in millions)	$	953		$	164

_______________________________________

(a) DTE Electric'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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Long-Term Debt (Details Textuals) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Junior Subordinated Debt [Member]
Debt Instrument [Line Items]
Junior Subordinated Debentures	$ 280	$ 280
Junior Subordinated Debentures 6.5% due in 2061 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End	6.50%
Subordinated Debt [Member]
Debt Instrument [Line Items]
Junior Subordinated Debentures	$ 200	$ 0
Junior Subordinated Debentures 5.25% due 2062 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End	5.25%

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Income Taxes (Details 2) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Deferred Tax Liability Not Recognized [Line Items]
Property, plant and equipment	$ (3,389)		$ (3,131)
Securitized regulatory assets	(256)		(360)
Alternative minimum tax credit carry-forwards	254		294
Merger basis differences	42		50
Pension and benefits	(33)		(39)
Other comprehensive income	101		99
Derivative assets liabilities	66		64
State net operating loss and credit carry-forwards	37		30
Other	41		(45)
Deferred Tax Assets Liabilities Gross	(3,137)		(3,038)
Less valuation allowance	(33)		(27)
Deferred Tax Assets (Liabilities), Net	(3,170)		(3,065)
Current deferred income tax assets	21	51	51
Long-term deferred income tax liabilities	(3,191)	(3,116)	(3,116)
Deferred income tax assets	1,038		1,048
Deferred income tax liabilities	$ (4,208)		$ (4,113)

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Reconciliation of Income Tax Expense to Federal Tax Rate [Line Items]
Income before income taxes		$ 960	$ 991	$ 962
Income tax expense at 35% statutory rate		336	347	337
Production tax credits		(49)	(6)	(33)
Investment tax credits		(6)	(6)	(6)
Depreciation		(4)	(4)	(4)
Employee Stock Ownership Plan dividends		(4)	(4)	(5)
Domestic production activities deduction		(14)	(7)	(7)
Settlement of Federal tax audit		0	0	(12)
State and Local income taxes, net of federal benefit		257	267	311
State and local income taxes, net of federal benefit		37	37	44
Enactment of Michigan Corporate income Tax, net of federal expense		0	(87)	0
Other, net		(10)	(2)	1
Income Tax Expense	$ 87	$ 286	$ 268	$ 315
Effective Income Tax Rate		29.80%	27.00%	32.70%

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Retirement Benefits and Trusteed Assets (Details 10) (USD $) In Millions, unless otherwise specified	1 Months Ended	12 Months Ended
	Jan. 31, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Change in Accumulated PostRetirement Benefit Obligation [Line Items]
Regulatory Assets		$ 4,417	$ 4,853
Other Postretirement Benefit Plans, Defined Benefit [Member]
Change in Accumulated PostRetirement Benefit Obligation [Line Items]
Benefit obligation, beginning of year	2,470	2,470	2,305
Service cost		68	64	61
Interest cost		120	121	125
Plan amendments		(264)	(4)
Actuarial loss		5	80
Medicare Part D subsidy		6	6
Benefits paid		(90)	(102)
Benefit obligation, end of year		2,315	2,470	2,305
Defined Benefit Plan, Fair Value of Plan Assets		1,153	985	1,029
Actual return on plan assets		131	(22)
Company contributions	145	140	111
Benefits paid		(103)	(133)
Funded status of the plans		(1,162)	(1,485)
Net actuarial loss		40	47
Prior serice cost (credit)		(14)	(20)
Net transition obligation		(1)	(1)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax		25	26
Net actuarial loss		727	835
Prior service cost		(302)	(60)
Net transition obligation		1	3
Regulatory Assets		426	778
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities		(2)	(1)
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent		(1,160)	(1,484)
Pension and Other Postretirement Defined Benefit Plans, Liabilities		$ (1,162)	$ (1,485)

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Stock-Based Compensation (Details 3)	12 Months Ended
	Dec. 31, 2011
Share Based Compensation Summary of Fair Value of Options Assumptions [Line Items]
Risk-free interest rate	2.91%
Dividend yield	5.08%
Expected volatility	22.96%
Expected Life	6 years

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Valuation and Qualifying Accounts Valuation and Qualifying Accounts (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period	$ 162	$ 196	$ 262
Charged to cost and expenses	79	94	113
Charged to other accounts (1)	16	18	20
Deductions (2)	(195)	(146)	(199)
Balance at End of Period	$ 62	$ 162	$ 196

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Retirement Benefits and Trusteed Assets (Details 7) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	$ 44	$ 59
Realized gains (losses)	60	87
Purchases	2	3
Ending Balance	(13)	44
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	58	75
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	464	478
Realized gains (losses)	12	2
Unrealized gains (losses)	7	(29)
Purchases	283	87
Sales	(248)	(74)
Ending Balance	518	464
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	22	(24)
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	296	304
Realized gains (losses)	18	(4)
Unrealized gains (losses)	(5)	1
Purchases	250	64
Sales	(220)	(69)
Ending Balance	339	296
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	4
Pension Plans, Defined Benefit [Member] | Private Equity and Other [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	168	174
Realized gains (losses)	(6)	6
Unrealized gains (losses)	12	(30)
Purchases	33	23
Sales	(28)	(5)
Ending Balance	179	168
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	$ 6	$ (28)

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DEI Document (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Jan. 31, 2013	Jun. 30, 2012
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, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q4
Amendment Flag	false
Entity Common Stock, Shares Outstanding		172,545,941
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 10.2

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Retirement Benefits and Trusteed Assets Retirement Benefits and Trusteed Assets (Details 13) (Other Postretirement Benefit Plans, Defined Benefit [Member])	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Other Postretirement Benefits Target Allocations of Plan Assets [Line Items]
Defined Benefit Plan Health Care Trend Rate Pre and Post Sixty Five	7.00%	7.00%	7.00%	7.00%
Defined Benefit Plan Target Allocation Percentage of Assets Hedged Funds and Similar Investments	20.00%
Defined Benefit Plan Target Allocation Percentage of Assets Total	100.00%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate	5.00%	5.00%	5.00%	5.00%
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	21.00%
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%
Fixed Income Securities [Member]
Other Postretirement Benefits Target Allocations of Plan Assets [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities	25.00%
Equity Securities, Other [Member]
Other Postretirement Benefits Target Allocations of Plan Assets [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities	14.00%

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Asset Retirement Obligations (Notes)

12 Months Ended

Dec. 31, 2012

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, dismantlement of facilities located on leased property and various other operations. The Company has conditional retirement obligations for gas pipelines, asbestos and PCB removal at certain of its power plants and various distribution equipment. 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.

If a reasonable estimate of fair value cannot be made in the period in which the retirement obligation is incurred, such as for assets with indeterminate lives, the liability is recognized when a reasonable estimate of fair value can be made. Natural gas storage system assets, substations, manholes and certain other distribution assets have an indeterminate life. Therefore, no liability has been recorded for these assets.

A reconciliation of the asset retirement obligations for 2012 follows:

	(In millions)
Asset retirement obligations at December 31, 2011	$	1,593
Accretion	100
Liabilities incurred	27
Liabilities settled	(11		)
Revision in estimated cash flows	10
Asset retirement obligations at December 31, 2012	1,719

In 2001, DTE Electric 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, DTE Electric accrued an additional $19 million with respect to the decommissioning of Fermi 1. Management has suspended decommissioning activities and placed 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, in 2011, based on updated studies revising the timing and estimate of cash flows, a reduction of approximately $20 million was made to the DTE Electric 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.

In October 2011, the MPSC approved DTE Electric'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. DTE Electric 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 in 2011. It is estimated that the cost of decommissioning Fermi 2 is $1.5 billion in 2012 dollars and $10 billion in 2045 dollars, using a 6% inflation rate. Approximately $1.5 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. DTE Electric 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 returning the site to greenfield. This removal and greenfielding 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 DTE Electric. Contributions to the Fermi 1 trust are discretionary. See Note 3 for additional discussion of Nuclear Decommissioning Trust Fund Assets.

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Acquisition Acquisitions (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Allocation of the Purchase Price to Assets and Liabilities [Line Items]
Business Acquisition, Purchase Price Allocation, Current Assets, Cash and Cash Equivalents	$ 22
Business Acquisition, Purchase Price Allocation, Current Assets, Receivables	14
Business Acquisition, Purchase Price Allocation, Current Assets, Prepaid Expense and Other Assets	8
Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment	100
Allocation of Purchase Price to Existing Contracts and Agreements	75
Business Acquisition, Purchase Price Allocation, Other Noncurrent Assets	9
Business Acquisition, Purchase Price Allocation, Current Liabilities	(7)
Business Acquisition, Purchase Price Allocation, Noncontrolling Interest	(1)
Business Acquisition, Cost of Acquired Entity, Cash Paid	$ 220

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Regulatory Matters (Details Textuals) (USD $)	3 Months Ended	12 Months Ended			3 Months Ended		9 Months Ended		12 Months Ended		9 Months Ended	12 Months Ended
	Mar. 31, 2012	Dec. 31, 2012 people	Dec. 31, 2011	Jun. 30, 2010	Mar. 31, 2012 Electric [Member]	Mar. 31, 2011 Electric [Member]	Sep. 30, 2012 Electric [Member] kWh	Sep. 30, 2011 Electric [Member]	Dec. 31, 2012 Electric [Member]	Jun. 30, 2012 Electric [Member]	Sep. 30, 2011 Gas [Member]	Dec. 31, 2012 Gas [Member]	Dec. 31, 2011 Gas [Member]	Sep. 30, 2012 Gas [Member]	Jun. 30, 2012 Gas [Member]
Regulatory Asset and Liability [Line Items]
Probability of Recovery Through Regulatory Rates for Regulatory Assets and Liabilities		$ 0
Time Period Required by Non-Bypassable Securitization Bond Surcharge to Recover Securitized Regulatory Asset		14 years
Amortization Period of Cost to Achieve Deferral		10 years
Deferral of Investigation and Remediation of Costs Associated with Gas Utilities Former MGP Sites		10 years
Amortization Period for Enterprise Business Systems		10 years
Approved Rate Base Relating to the AMI Program										37,000,000
Expenditures Net of Grant Funds for AMI Program										110,000,000
Matching Grant Funds for the AMI Program										60,000,000
Defer the Reversal of RDM Liability							127,000,000
Number of Parties that Appealed the COA Decision Regarding RDM		0
Monthly Amount to Amortize from Liability to Income							10,600,000
EO Plans Performance Incentive Surcharges									8,400,000			3,400,000
Requested Recovery of Enery Optimization Expenses for Future Period Revised								224,000,000			66,000,000
Requested net recovery of RETM and LCT			44,000,000
Requesting Authority to Refund Uncollectible Expense to Customers	9,000,000
Authorized Recovery Amount for CIM									63,000,000
Authorized Recovery Period for CIM									10 months
PSCR Reconciliation Calculating net Under Recovery					148,000,000
Net Under Recovery of Power Suppy Cost Recovery Expense						52,600,000
PSCR Reconciliation Includes an Over-Recovery					3,800,000
Net Over Recovery of Power Supply Cost Recovery Expense								10,500,000
Power Supply Cost Recovery Plan Case Factor Next Year							4.74
Total PSCR Forecasted Expense							1,500,000,000
Recovery of Current Year PSCR							81,000,000
Projected Test Year Period for Gas Rate Case												12 months
Gas Rate Increase to Recover Higher Costs														77,000,000
Gas Self Implementation of Rates												27,000,000
MPSC Approved Increase in Annual Gas Rates												19,900,000
RDM Refund Liability												1,000,000
UETM Net Refund														7,000,000
UTEM Sufficiency Gross Amount Related to Uncollectibles														19,000,000
Under Recovery Relating to Under-Collection of UETM Gross														12,000,000
Time Period to Implementation Credits and Surcharges Related to the UETM												12 months
UETM Accrual for Over-Recovery		20,000,000
RDM Application Proposed Recovery														8,600,000	20,000,000
Time Period to Implement RDM Surcharge												12 months
RDM Revenue Recognized For 2010/2011 Period															5,000,000
RDM Revenue Recognized for 2011/2012 Period															3,000,000
RDM Amount Recognized for the Under-Recovery												5,000,000
RDM Caps for First Reconciliation Period		1.125%
RDM Cap for Second Period Reconciliation		2.25%
Annual Depreciation Expense Increase															12,400,000
GCR Time Period of Reconciliation												12 months	12 months
GCR Reconciliation Over-Recovery														6,000,000
GCR Reconciliation Under-Recovery															6,400,000
Amortization Period of CTA		10 years
Pre Tax Amount of Cost To Achieve Previously Expensed Deferred and Recognized in Income				32,000,000
After Tax Amount of Cost To Achieve Previously Expensed deferred and Recognized in Income				$ 20,000,000

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Consolidated Statements of Comprehensive Income (Parenthetical) (Parentheticals) (Tax Effect [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Tax Effect [Member]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Benefit Plan Improvement, Tax Effect	$ (1)	$ (5)	$ 3
Amounts Reclassified to Benefit Obligations Related to Consolidation of VIEs Tax Effect	0	0	5
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	0	0	1
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Tax	0	0	1
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax	1	0	(6)
Amounts Reclassified to Benefit Obligations Related to Consolidation of VIEs Tax Effect 1	0	0	(5)
Other Comprehensive Income (Loss), Foreign Currency Translation Gain (Loss) Arising During Period, Tax	$ 0	$ 0	$ 0

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Financial and Other Derivative Instruments (Notes)

12 Months Ended

Dec. 31, 2012

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. 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, pipeline transportation contracts, renewable energy credits and storage assets.

Electric — DTE Electric generates, purchases, distributes and sells electricity. DTE Electric uses forward energy 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 — DTE Gas purchases, stores, transports, distributes and sells natural gas and sells storage and transportation capacity. DTE Gas has fixed-priced contracts for portions of its expected gas supply requirements through 2015. Substantially all of these contracts meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. DTE Gas may also sell forward transportation and storage capacity contracts. Forward transportation and storage contracts are generally 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.

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.

Energy Trading — Commodity Price Risk — Energy Trading markets and trades electricity, coal, 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 natural gas and power purchase and sale contracts and natural 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 2013, 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, 2012 and 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 gas purchases and sales, gas transportation and storage capacity. Changes in the value of derivatives in this category typically 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 DTE Electric related to FTRs. Changes in the value of derivative contracts at DTE Electric 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, 2012 and 2011:

	December 31, 2012					December 31, 2011
	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)	$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	—	$	—		$	3	$	(5	)
Commodity Contracts:
Natural Gas	645		(661		)	2,024		(2,080		)
Electricity	360		(351		)	747		(705		)
Other	11		(7		)	31		(20		)
Total derivatives not designated as hedging instruments:	$	1,016	$	(1,019	)	$	2,805	$	(2,810	)
Total derivatives:
Current	$	862	$	(879	)	$	2,272	$	(2,282	)
Noncurrent	154		(141		)	533		(529		)
Total derivatives	$	1,016	$	(1,020	)	$	2,805	$	(2,811	)

	December 31, 2012												December 31, 2011
	Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent			Current			Noncurrent			Current			Noncurrent
	(In millions)
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	862		$	154		$	(879	)	$	(141	)	$	2,272		$	533		$	(2,282	)	$	(529	)
Counterparty netting	(754		)	(115		)	754			115			(2,050		)	(440		)	2,050			440
Collateral adjustment	—			—			—			—			—			(19		)	74			—
Total derivatives as reported	$	108		$	39		$	(125	)	$	(26	)	$	222		$	74		$	(158	)	$	(89	)

The effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for years ended December 31, 2012 and 2011 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		2012			2011
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	—		$	(2	)
Commodity Contracts:
Natural Gas	Operating Revenue	(29		)	58
Natural Gas	Fuel, purchased power and gas	25			(21		)
Electricity	Operating Revenue	64			115
Other	Operating Revenue	5			9
Total		$	65		$	159

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, and financial non-trading commodity derivatives, are accounted for using the mark-to-market method with unrealized and realized gains and losses recorded in Operating revenues. Non-trading physical commodity sale and purchase derivative contracts are generally accounted for using the mark-to-market method with unrealized and realized gains and losses for sales recorded in Operating revenue and purchases recorded in Fuel, purchased power and gas.

The effects of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position were $15 million in unrealized gains related to FTRs recognized in Regulatory liabilities for the year ended December 31, 2012, and $3 million in unrealized gains related to FTRs recognized in Regulatory liabilities, for the year ended December 31, 2011.

The following represents the cumulative gross volume of derivative contracts outstanding as of December 31, 2012:

Commodity	Number of Units
Natural Gas (MMBtu)	663,194,602
Electricity (MWh)	48,524,412
Foreign Currency Exchange ($ CAD)	10,838,396
FTR (MWh)	11,077,483

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, 2012, 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 $326 million.

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Fair Value (Notes)

12 Months Ended

Dec. 31, 2012

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, 2012 and December 31, 2011. 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, 2012 and 2011:

	December 31, 2012															December 31, 2011
	Level 1			Level 2			Level 3			Netting (a)			Net Balance			Level 1			Level 2			Level 3			Netting (a)			Net Balance
	(In millions)
Assets:
Cash equivalents (b)	$	—		$	123		$	—		$	—		$	123		$	—		$	140		$	—		$	—		$	140
Nuclear decommissioning trusts	694			343			—			—			1,037			577			360			—			—			937
Other investments (c) (d)	66			44			—			—			110			57			38			—			—			95
Derivative assets:
Foreign currency exchange contracts	—			—			—			—			—			—			3			—			(3		)	—
Commodity Contracts:
Natural Gas	555			66			24			(605		)	40			1,926			78			20			(1,991		)	33
Electricity	—			226			134			(258		)	102			—			523			224			(490		)	257
Other	6			3			2			(6		)	5			23			2			6			(25		)	6
Total derivative assets	561			295			160			(869		)	147			1,949			606			250			(2,509		)	296
Total	$	1,321		$	805		$	160		$	(869	)	$	1,417		$	2,583		$	1,144		$	250		$	(2,509	)	$	1,468
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	—		$	—		$	—		$	—		$	—		$	(5	)	$	—		$	3		$	(2	)
Interest rate contracts	—			(1		)	—			—			(1		)	—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(526		)	(73		)	(62		)	605			(56		)	(1,940		)	(126		)	(14		)	1,976			(104		)
Electricity	—			(240		)	(111		)	258			(93		)	—			(513		)	(192		)	565			(140		)
Other	(6		)	(1		)	—			6			(1		)	(19		)	(1		)	—			20			—
Total derivative liabilities	(532		)	(315		)	(173		)	869			(151		)	(1,959		)	(646		)	(206		)	2,564			(247		)
Total	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)	$	(1,959	)	$	(646	)	$	(206	)	$	2,564		$	(247	)
Net Assets at the end of the period	$	789		$	490		$	(13	)	$	—		$	1,266		$	624		$	498		$	44		$	55		$	1,221
Assets:
Current	$	493		$	372		$	120		$	(754	)	$	231		$	1,571		$	660		$	181		$	(2,050	)	$	362
Noncurrent (e)	828			433			40			(115		)	1,186			1,012			484			69			(459		)	1,106
Total Assets	$	1,321		$	805		$	160		$	(869	)	$	1,417		$	2,583		$	1,144		$	250		$	(2,509	)	$	1,468
Liabilities:
Current	$	(466	)	$	(269	)	$	(144	)	$	754		$	(125	)	$	(1,603	)	$	(527	)	$	(152	)	$	2,124		$	(158	)
Noncurrent	(66		)	(46		)	(29		)	115			(26		)	(356		)	(119		)	(54		)	440			(89		)
Total Liabilities	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)	$	(1,959	)	$	(646	)	$	(206	)	$	2,564		$	(247	)
Net Assets at the end of the period	$	789		$	490		$	(13	)	$	—		$	1,266		$	624		$	498		$	44		$	55		$	1,221

_______________________________________

(a) 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.

(b) At December 31, 2012 available for sale securities of $123 million included $109 million and $14 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively. At December 31, 2011 available for sale securities of $140 million, included $124 million and $16 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively.

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

(d) Available for sale equity securities of $5 million at December 31, 2012 and December 31, 2011 are included in Other investments on the Consolidated Statements of Financial Position, respectively.

(e) Includes $110 million and $95 million of Other investments that are included in the Consolidated Statements of Financial Position in Other investments at December 31, 2012 and December 31, 2011, respectively.

Cash Equivalents

Cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value table are comprised of short-term investments and money market funds. The fair values of the shares in these investments are based upon observable market prices for similar securities and, therefore, have been categorized as Level 2 in the fair value hierarchy.

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. The Company has established a Risk Management Committee whose responsibilities include directly or indirectly ensuring all valuation methods are applied in accordance with predefined policies. The development and maintenance of our forward price curves has been assigned to our Risk Management Department, which is separate and distinct from the trading functions within the Company.

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, 2012 and 2011:

	Year Ended December 31, 2012												Year Ended December 31, 2011
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets as of January 1	$	6		$	32		$	6		$	44		$	1		$	54		$	4		$	59
Transfers into Level 3	1			—			—			1			—			4			—			4
Transfers out of Level 3	—			—			—			—			1			(25		)	—			(24		)
Total gains (losses):
Included in earnings	(41		)	101			—			60			7			77			3			87
Recorded in regulatory assets/liabilities	—			—			15			15			—			—			2			2
Purchases, issuances and settlements:
Purchases	—			2			—			2			—			3			—			3
Settlements	(4		)	(112		)	(19		)	(135		)	(3		)	(81		)	(3		)	(87		)
Net Assets (Liabilities) as of December 31	$	(38	)	$	23		$	2		$	(13	)	$	6		$	32		$	6		$	44
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, 2012 and 2011and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(33	)	$	91		$	—		$	58		$	8		$	65		$	2		$	75

Derivatives are transferred between levels primarily due to changes in the source data used to construct price curves as a result of changes in market liquidity. Transfers in and transfers out are reflected as if they had occurred at the beginning of the period. The following table shows transfers between the levels of the fair value hierarchy for the years ended December 31, 2012 and 2011:

	Year Ended December 31, 2012						Year Ended December 31, 2011
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
	(In millions)
Transfers into Level 1 from	N/A		$	—	$	—	N/A		$	—	$	—
Transfers into Level 2 from	$	—	N/A		—		$	—	N/A		24
Transfers into Level 3 from	—		1		N/A		—		4		N/A

The following table presents the unobservable inputs related to Level 3 assets and liabilities as of December 31, 2012:

	December 31, 2012
Commodity Contracts	Derivative Assets		Derivative Liabilities			Valuation Techniques	Unobservable Input	Range							Weighted Average
(In millions)
Natural Gas	$	24	$	(62	)	Discounted Cash Flow	Forward basis price (per MMBtu)	$	(0.63	)	—	$	1.95	/MMBtu	$	0.03	/MMBtu
Electricity	134		(111		)	Discounted Cash Flow	Forward basis price (per MWh)	$	(2	)	—	$	16	/MWh	$	3	/MWh

The unobservable inputs used in the fair value measurement of the electricity and natural gas commodity types consists of inputs that are less observable due in part to lack of available broker quotes, supported by little, if any, market activity at the measurement date or are based on internally developed models. Certain forward market and/or basis prices (i.e., the difference in pricing between two locations) that were included in the valuation of natural gas and electricity contracts were deemed unobservable.

The inputs listed above would have a direct impact on the fair values of the above security types if they were adjusted. A significant increase (decrease) in the forward market or basis price would result in a higher (lower) fair value for long positions, with offsetting impacts to short positions.

Fair Value of Financial Instruments

The fair value of financial instruments included in the table below is determined by using quoted market prices when available. When quoted prices are not available, pricing services may be used to determine the fair value with reference to observable interest rate indexes. DTE Energy has obtained an understanding of how the fair values are derived. DTE Energy also selectively corroborates the fair value of its transactions by comparison of market-based price sources. Discounted cash flow analyses based upon estimated current borrowing rates are also used to determine fair value when quoted market prices are not available. The fair values of notes receivable, excluding capital leases, are estimated using discounted cash flow techniques that incorporate market interest rates as well assumptions about the remaining life of the loans and credit risk. Depending on the information available, other valuation techniques may be used that rely on internal assumptions and models. Valuation policies and procedures are determined by DTE Energy's Treasury Department which reports to the Company's Vice President and Treasurer.

The following table presents the carrying amount and fair value of financial instruments as of December 31, 2012 and 2011:

	December 31, 2012								December 31, 2011
	Carrying		Fair Value						Carrying		Fair
	Amount		Level 1		Level 2		Level 3		Amount		Value
	(In millions)
Notes receivable, excluding capital leases	$	39	$	—	$	—	$	39	$	48	$	48
Dividends payable	107		107		—		—		99		99
Short-term borrowings	240		—		240		—		419		419
Long-term debt	7,813		507		7,453		933		7,682		8,757

See Note 4 for further fair value information on financial and derivative instruments.

Nuclear Decommissioning Trust Funds

DTE Electric 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. DTE Electric is continuing to fund FERC jurisdictional amounts for decommissioning even though explicit provisions are not included in FERC rates. See Note 10.

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

	December 31 2012		December 31 2011
	(In millions)
Fermi 2	$	1,021	$	915
Fermi 1	3		3
Low level radioactive waste	13		19
Total	$	1,037	$	937

At December 31, 2012, 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. 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. The debt securities at both December 31, 2012 and December 31, 2011 had an average maturity of approximately 6 and 7 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
	2012			2011			2010
	(In millions)
Realized gains	$	37		$	46		$	192
Realized losses	$	(31	)	$	(38	)	$	(83	)
Proceeds from sales of securities	$	97		$	80		$	377

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:

	December 31, 2012				December 31, 2011
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
	(In millions)
Equity securities	$	631	$	122	$	533	$	80
Debt securities	399		27		385		22
Cash and cash equivalents	7		—		19		—
	$	1,037	$	149	$	937	$	102

Securities held in the nuclear decommissioning trust funds are classified as available-for-sale. As DTE Electric 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. DTE Electric recognized $44 million and $67 million of unrealized losses as Regulatory assets at December 31, 2012 and 2011, respectively. Since the decommissioning of Fermi 1 is funded by DTE Electric 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 2012, 2011 and 2010 for Fermi 1.

Available-for-sale Securities

At December 31, 2012 and 2011, these securities are comprised primarily of money-market and equity securities. During the year ended December 31, 2012 and December 31, 2011no amounts of unrealized losses on available for sale securities were reclassified out of other comprehensive income into net income for the periods. Gains related to trading securities held at December 31, 2012, 2011, and 2010 were $9 million, $3 million and $7 million, respectively.

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Segment Information (Details 1) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Segment Reporting Information [Line Items]
Depreciation, Depletion and Amortization									$ 1,018	$ 995	$ 1,027
Interest Expense									440	488	543
Income Taxes									173	(205)	93
Net Income Attributable to DTE Energy Company	81	227	146	156	150	183	202	176	610	711	630
Total Assets	26,339				26,009				26,339	26,009
Goodwill	2,018				2,020				2,018	2,020	2,020
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	(56.00)	1.00	(1.00)	0	(1.00)	0	(1.00)	(1.00)	(56.00)	(3.00)	(8.00)
Electric [Member]
Segment Reporting Information [Line Items]
Operating Revenue									5,293	5,154	4,993
Depreciation, Depletion and Amortization									827	818	849
Interest Income									(1)	(1)	(1)
Interest Expense									272	289	313
Income Taxes									280	265	270
Net Income Attributable to DTE Energy Company									483	434	441
Total Assets	17,755				17,567				17,755	17,567	16,611
Goodwill	1,208				1,208				1,208	1,208	1,206
Capital Expenditures									1,230	1,203	864
Gas [Member]
Segment Reporting Information [Line Items]
Operating Revenue									1,315	1,505	1,648
Depreciation, Depletion and Amortization									92	89	92
Interest Income									(7)	(7)	(9)
Interest Expense									59	64	66
Income Taxes									50	60	67
Net Income Attributable to DTE Energy Company									115	110	127
Total Assets	4,059				4,065				4,059	4,065	3,925
Goodwill	745				745				745	745	759
Capital Expenditures									220	179	147
Gas Storage and Pipelines [Member]
Segment Reporting Information [Line Items]
Operating Revenue									96	91	83
Depreciation, Depletion and Amortization									8	6	5
Interest Income									(8)	(5)	(1)
Interest Expense									8	7	6
Income Taxes									39	35	32
Net Income Attributable to DTE Energy Company									61	57	51
Total Assets	668				538				668	538	446
Goodwill	22				22				22	22	9
Capital Expenditures									233	16	5
Power and Industrial Projects [Member]
Segment Reporting Information [Line Items]
Operating Revenue									1,823	1,129	1,144
Depreciation, Depletion and Amortization									65	60	60
Interest Income									(7)	(8)	(3)
Interest Expense									37	32	33
Income Taxes									(44)	11	3
Net Income Attributable to DTE Energy Company									42	38	85
Total Assets	991				789				991	789	872
Goodwill	26				26				26	26	27
Capital Expenditures									83	56	53
Energy Trading [Member]
Segment Reporting Information [Line Items]
Operating Revenue									1,109	1,276	875
Depreciation, Depletion and Amortization									2	3	5
Interest Income									0	0	0
Interest Expense									8	9	13
Income Taxes									7	34	5
Net Income Attributable to DTE Energy Company									12	52	6
Total Assets	629				612				629	612	513
Goodwill	17				17				17	17	17
Capital Expenditures									1	1	1
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating Revenue									3	4	1
Depreciation, Depletion and Amortization									1	1	1
Interest Income									(52)	(47)	(47)
Interest Expense									121	145	160
Income Taxes									(46)	(136)	(62)
Net Income Attributable to DTE Energy Company									(47)	23	(72)
Total Assets	3,074				2,605				3,074	2,605	2,616
Goodwill	0				0				0	0	0
Capital Expenditures									3	0	0
Corporate Elimination [Member]
Segment Reporting Information [Line Items]
Operating Revenue									(848)	(301)	(219)
Depreciation, Depletion and Amortization									0	0	0
Interest Income									65	58	49
Interest Expense									(65)	(58)	(48)
Income Taxes									0	(1)	0
Net Income Attributable to DTE Energy Company									0	0	0
Total Assets	(837)				(485)				(837)	(485)	(413)
Goodwill	0				0				0	0	0
Capital Expenditures									0	0	0
Segment, Continuing Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenue									8,791	8,858	8,525
Depreciation, Depletion and Amortization									995	977	1,012
Interest Income									(10)	(10)	(12)
Interest Expense									440	488	543
Income Taxes									286	268	315
Net Income Attributable to DTE Energy Company									666	714	638
Total Assets	26,339				25,691				26,339	25,691	24,570
Goodwill	2,018				2,018				2,018	2,018	2,018
Capital Expenditures									1,770	1,455	1,070
Segment, Discontinued Operations [Member]
Segment Reporting Information [Line Items]
Total Assets	0				318				0	318	326
Goodwill	0				2				0	2	2
Capital Expenditures									49	29	27
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent									(56.00)	(3.00)	(8.00)
Total [Member]
Segment Reporting Information [Line Items]
Net Income Attributable to DTE Energy Company									610	711	630
Total Assets	26,339				26,009				26,339	26,009	24,896
Goodwill	2,018				2,020				2,018	2,020	2,020
Capital Expenditures									$ 1,819	$ 1,484	$ 1,097

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Long-Term Debt (Notes)

12 Months Ended

Dec. 31, 2012

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 (a) of debt outstanding at December 31 were:

	2012			2011
	(In millions)
Mortgage bonds, notes, and other
DTE Energy Debt, Unsecured
5.4% due 2013 to 2033	$	1,298		$	1,298
DTE Electric Taxable Debt, Principally Secured
5.0% due 2013 to 2042	3,777			3,515
DTE Electric Tax-Exempt Revenue Bonds (b)
5.3% due 2014 to 2038	707			893
DTE Gas Taxable Debt, Principally Secured
5.6% due 2013 to 2042	919			889
Other Long-Term Debt, Including Non-Recourse Debt	153			165
	6,854			6,760
Less amount due within one year	(634		)	(355		)
	$	6,220		$	6,405
Securitization bonds
6.6% due 2013 to 2015	$	479		$	643
Less amount due within one year	(177		)	(164		)
	$	302		$	479
Junior Subordinated Debentures
6.5% due 2061	$	280		$	280
5.25% due 2062	200			—
	$	480		$	280

_______________________________________

(a) Weighted average interest rates as of December 31, 2012 are shown below the description of each category of debt.

(b) DTE Electric Tax-Exempt Revenue Bonds are issued by a public body that loans the proceeds to DTE Electric on terms substantially mirroring the Revenue Bonds.

Debt Issuances

In 2012, the Company issued the following long-term debt:

Company	Month Issued	Type	Interest Rate		Maturity	Amount
	(In millions)
DTE Electric	June	Mortgage Bonds (a)	2.65	%	2022	$	250
DTE Electric	June	Mortgage Bonds (a)	3.95	%	2042	250
DTE Energy	October	Junior Subordinated Debentures (b)	5.25	%	2062	200
DTE Gas	December	Mortgage Bonds (c)	3.92	%	2042	70
						$	770

_______________________________________

(a) Proceeds were used for the early redemption of DTE Electric long-term debt; for the repayment of short-term borrowings; and for general corporate purposes.

(b) Proceeds were used to pay a portion of the purchase price for a portfolio of on-site energy projects; for the repayment of short-term borrowings; and for general corporate purposes.

(c) Proceeds were used for general corporate purposes.

Debt Redemptions

In 2012, the following debt was redeemed:

Company	Month	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March/September	Securitization Bonds	6.42	%	2012	$	164
DTE Electric	April	Mortgage Bonds	7.90	%	2012	10
DTE Electric	April	Mortgage Bonds	8.36	%	2012	3
DTE Gas	May	Secured Medium Term Notes	7.06	%	2012	40
DTE Electric	July	Senior Notes	5.20	%	2012	225
DTE Electric	December	Tax Exempt Revenue Bonds (a)	3.05	%	2024	65
DTE Electric	December	Tax Exempt Revenue Bonds (a)	5.45	%	2032	64
DTE Electric	December	Tax Exempt Revenue Bonds (a)	5.25	%	2032	56
DTE Energy	Various	Other Long-Term Debt	Various		2012	12
						$	639

_______________________________________

(a) DTE Electric Tax Exempt Revenue Bonds are issued by a public body that loans the proceeds to DTE Electric on terms substantially mirroring the Revenue Bonds.

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

	2013		2014		2015		2016		2017		2018 and Thereafter		Total
	(In millions)
Amount to mature	$	811	$	891	$	476	$	465	$	9	$	5,166	$	7,818

Junior Subordinated Debentures

At December 31, 2012, the Company had $280 million of 6.5% Junior Subordinated Debentures due 2061 and $200 million of 5.25% Junior Subordinated Debentures due 2062. 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 associated with the related debt issue.

Cross Default Provisions

Substantially all of the net utility properties of DTE Electric and DTE Gas are subject to the lien of mortgages. Should DTE Electric or DTE Gas 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 (Notes)

12 Months Ended

Dec. 31, 2012

Public Utilities, General Disclosures [Abstract]

REGULATORY MATTERS

REGULATORY MATTERS

Regulation

DTE Electric and DTE Gas 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. DTE Electric 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.

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.

Regulatory Assets and Liabilities

DTE Electric and DTE Gas 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:

	2012			2011
	(In millions)
Assets
Recoverable pension and postretirement costs:
Pension	$	2,420		$	2,208
Postretirement costs	426			778
Asset retirement obligation	424			420
Recoverable Michigan income taxes	304			324
Recoverable income taxes related to securitized regulatory assets	226			316
Cost to achieve Performance Excellence Process	96			116
Accrued PSCR/GCR revenue	87			147
Other recoverable income taxes	76			81
Choice incentive mechanism	66			166
Unamortized loss on reacquired debt	63			64
Deferred environmental costs	58			49
Recoverable restoration expense	49			58
Recoverable revenue decoupling	28			18
Enterprise Business Systems costs	16			18
Other	78			90
	4,417			4,853
Less amount included in current assets	(182		)	(314		)
	$	4,235		$	4,539
Securitized regulatory assets	$	413		$	577

	2012			2011
	(In millions)
Liabilities
Asset removal costs	$	439		$	419
Renewable energy	230			192
Refundable revenue decoupling/deferred gain	127			127
Negative pension offset	105			120
Refundable income taxes	56			66
Over recovery of Securitization	54			53
Refundable uncollectible expense	37			31
Energy Optimization	34			34
Accrued PSCR/GCR refund	16			26
Fermi 2 refueling outage	12			23
Low Income Energy Efficiency Fund	—			26
Other	10			9
	1,120			1,126
Less amount included in current liabilities	(89		)	(107		)
	$	1,031		$	1,019

As noted below, certain 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 DTE Electric or DTE Gas’s rate base, thereby providing a return on invested costs (except as noted). Certain other regulatory assets are not included in rate base but accrue recoverable carrying charges until surcharges to collect the assets are billed. 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. DTE Electric and DTE Gas 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. (a)

• 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. (a)

• 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. (a)

• 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. (a)

• 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.

• Accrued PSCR/GCR revenue — Receivable for the temporary under-recovery of and a return on fuel and purchased power costs incurred by DTE Electric which are recoverable through the PSCR mechanism and temporary under-recovery of and return on gas costs incurred by DTE Gas which are recoverable through the GCR mechanism.

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

• Choice incentive mechanism (CIM) — DTE Electric 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 DTE Electric.

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

• Deferred environmental costs — The MPSC approved the deferral of investigation and remediation costs associated with DTE Gas'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. (a)

• 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 DTE Electric.

• Recoverable revenue decoupling — Amounts recoverable from DTE Gas 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. The December 2012 order in DTE Gas' rate case requires the RDM be discontinued effective November 1, 2012. The order provides for a new RDM beginning in November 2013.

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

• 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.

_________________________________

(a) Regulatory assets not earning a return or accruing carrying charges.

LIABILITIES

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

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

• Refundable revenue decoupling / deferred gain — At December 31, 2011, amounts were accrued as refundable to DTE Electric 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. In 2012, the revenue decoupling liability was reversed and a new regulatory liability representing DTE Electric's obligation to refund the resulting gain was accrued. See further discussion below.

• Negative pension offset — DTE Gas’ 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 DTE Gas’ pension expense is positive in future years.

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

• Over recovery of Securitization — Over recovery of securitization bond expenses.

• Refundable uncollectible expense (UETM )— DTE Electric and DTE Gas 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 for DTE Electric in the October 20, 2011 MPSC rate case order and terminated for DTE Gas in the December 20, 2012 MPSC approval of the partial settlement agreement.

• Energy Optimization (EO) - Amounts collected in rates in excess of energy optimization expenditures.

• Accrued PSCR/GCR refund — Liability for the temporary over-recovery of and a return on power supply costs and transmission costs incurred by DTE Electric which are recoverable through the PSCR mechanism and temporary over-recovery of and a return on gas costs incurred by DTE Gas which are recoverable through the GCR mechanism.

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

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

2009 Electric Rate Case Filing - Court of Appeals Decision/Refundable Deferred Gain

On April 10, 2012, the Michigan Court of Appeals (COA) issued a decision relating to an appeal of the January 2010 MPSC order in DTE Electric's January 2009 rate case filing.

The COA found that the record of evidence in the 2009 rate case order was insufficient to support the MPSC's authorization to recover costs for the pilot advanced metering infrastructure (AMI) program and remanded this matter to the MPSC. The MPSC had approved $37 million of rate base related to the AMI program in the January 2010 order. DTE Electric is currently operating its AMI program pursuant to the MPSC's approval set forth in its October 20, 2011 order, which was not reviewed by or subject to the COA's April 10, 2012 decision. On November 28, 2012, DTE Electric filed the necessary data and evidence to the MPSC supporting the AMI program expenditures. DTE Electric's AMI program expenditures are $110 million as of December 31, 2012, net of Department of Energy matching grant funds of $60 million.

The COA affirmed the use of a number of tracking mechanisms (restoration, line clearance, uncollectibles expense and choice incentive) and the peak demand computations approved in the January 2010 order. The COA also determined that the MPSC only had statutory authority to implement a Revenue Decoupling Mechanism (RDM) for gas providers, but not for electric providers, thereby reversing the MPSC's decision to authorize an RDM for DTE Electric. DTE Electric had accrued a total of $127 million of RDM refund liabilities for the 2010 and 2011 RDM reconciliation periods. No party appealed the COA decision regarding the RDM determination.

On August 1, 2012, DTE Electric filed an application for approval of accounting authority to defer for future amortization the gain resulting from the reversal of the Company's $127 million regulatory liability associated with the operation of the RDM. On August 14, 2012, the MPSC dismissed DTE Electric's initial pilot RDM reconciliation cases. On September 25, 2012, the MPSC issued an order approving the Company's accounting application. As described in the accounting application, DTE Electric will amortize the new regulatory liability to income, at a monthly rate of approximately $10.6 million, beginning January 2014. It is currently anticipated that with this accounting treatment, along with other cost saving measures, DTE Electric will not need to increase base rates until 2015. If DTE Electric's base rates are increased prior to January 1, 2015, the Company will cease amortization and refund to customers the remaining unamortized balance of the new regulatory liability.

Energy Optimization (EO) Plans

The EO plan 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.

In May 2012, DTE Electric and DTE Gas both filed separate applications for approval of their respective reconciliations of their 2011 EO plan expenses. On October 31, 2012, the MPSC approved DTE Electric's reconciliation and on November 16, 2012, the MPSC approved DTE Gas' reconciliation. The MPSC orders also approved performance incentive surcharges for DTE Electric of $8.4 million and for DTE Gas of $3.4 million to be applied to customer bills rendered on and after January 1, 2013.

In August 2012, Detroit Edison and MichCon filed amended EO plans with the MPSC. DTE Electric's EO plan application proposed the recovery of EO expenditures for the period 2013-2015 of $224 million and DTE Gas' EO plan application proposed the recovery of EO expenditures for the period 2013-2015 of $66 million. Both applications requested approval of surcharges to recover these costs.

DTE Electric Restoration Expense Tracker Mechanism (RETM) and Line Clearance Tracker (LCT) Reconciliation

In January 2012, DTE Electric 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, DTE Electric requested net recovery of approximately $44 million. An MPSC order is expected in the first quarter of 2013.

DTE Electric Uncollectible Expense True-Up Mechanism (UETM)

In February 2012, DTE Electric filed an application with the MPSC for approval of its UETM for 2011 requesting authority to refund approximately $9 million consisting of costs related to 2011 uncollectible expense. An MPSC order is expected in the first quarter of 2013.

DTE Electric Choice Incentive Mechanism (CIM)

In January 2012, DTE Electric 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. On January 17, 2013, the MPSC approved a settlement agreement authorizing the Company to recover $63 million, plus interest, from its customers through a surcharge to be implemented over a ten-month period beginning March 2013 through December 2013.

Power Supply Cost Recovery Proceedings

The PSCR process is designed to allow DTE Electric to recover all of its power supply costs if incurred under reasonable and prudent policies and practices. DTE Electric'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.

2011 PSCR Year -In March 2012, DTE Electric filed the 2011 PSCR reconciliation calculating a net under-recovery of $148 million that includes an under-recovery of $52.6 million for the 2010 PSCR year. In addition, the 2011 PSCR reconciliation includes an over-refund of $3.8 million for the 2011 refund of the self-implementation rate increase related to the 2009 electric rate case filing and a credit of $10.5 million related to the expiration of a wholesale power sales contract.

2013 Plan Year - In September 2012, DTE Electric filed its 2013 PSCR plan case seeking approval of a levelized PSCR factor of 4.74 mills/kWh above the amount included in base rates for all PSCR customers. The filing supports a total power supply expense forecast of $1.5 billion. The plan also includes approximately $81 million for the recovery of its projected 2012 PSCR under-recovery.

2012 Gas Rate Case Filing

DTE Gas filed a rate case on April 20, 2012 based on a projected test year for the twelve-month period ending October 31, 2013. The filing with the MPSC requested an increase in base rates of approximately $77 million that is required to recover higher costs associated with increased investments in plant, the impact of sales reductions due to customer losses and continuing conservation, and increasing operating costs, primarily pipeline integrity and leak remediation expenses. On October 24, 2012, DTE Gas filed notification with the MPSC indicating that it intended to self-implement $27 million of rate relief beginning in November 2012, suspend the RDM and terminate the monthly credit which was implemented to remove the Vulnerable Household Warmth Fund collections from rates. On December 20, 2012, the MPSC approved a partial settlement agreement and authorized the Company to increase its annual gas revenues by $19.9 million for service rendered on and after January 1, 2013. A refund liability of approximately $1 million, representing the difference between the final ordered rate relief and the self- implemented revenue, was accrued as of December 31, 2012.

The case also included a proposal for an infrastructure recovery mechanism (IRM) designed to recover DTE Gas' projected costs related to its gas main renewal and meter move out programs. The approved settlement did not resolve the IRM which will continue to be litigated with an order expected by April 2013.

DTE Gas UETM

In March 2012, DTE Gas filed an application with the MPSC for approval of its UETM for 2011 requesting authority to refund approximately $7 million, consisting of a $19 million over-recovery related to 2011 uncollectible expense, partially offset by $12 million related to the 2010 UETM under-recovery. In September 2012, the MPSC approved a settlement agreement approving the net refund of $7 million and the implementation of credits and surcharges over a twelve-month period beginning in November 2012. The December 2012 order in DTE Gas' rate case requires the UETM be terminated effective November 1, 2012 and the reconciliation to be filed by March 31, 2013. DTE Gas accrued a refund obligation of approximately $20 million for the 2012 over-recovery.

DTE Gas Revenue Decoupling Mechanism (RDM)

In September 2011, DTE Gas filed an application with the MPSC for approval of its RDM reconciliation for the period July 1, 2010 through June 30, 2011. DTE Gas' RDM application proposed the recovery of approximately $20 million. On July 13, 2012, the MPSC approved a settlement agreement approving the RDM reconciliation and the implementation of a surcharge over a twelve-month period beginning in August 2012. As a result of the provisions of the settlement, during the quarter ended June 30, 2012, DTE Gas recognized an additional $5 million of revenue related to the 2010/2011 period and $3 million related to the 2011/2012 period.

In October 2012, DTE Gas filed an application with the MPSC for approval of its RDM reconciliation for the period July 1, 2011 through June 30, 2012. The application requests authority to adjust existing retail gas rates so as to collect a net amount of $8.6 million, plus interest. An order is expected in the first quarter of 2013.

The December 2012 order in DTE Gas' rate case requires the RDM be discontinued effective November 1, 2012 and a reconciliation be filed by October 31, 2013. DTE Gas recognized approximately $5 million for the under-recovery during the July through October 2012 period. The order provides for a new RDM beginning in November 2013 for the period November 1, 2013 through October 31, 2014. The new RDM decouples weather normalized distribution revenue inside caps. The caps are tied to expected conservation targets: 1.125% in the first reconciliation period and 2.25% for the second and future periods.

DTE Gas Depreciation Filing

In June 2012, DTE Gas filed a depreciation study, as ordered by the MPSC, indicating an annual depreciation expense increase of $12.4 million. Pursuant to the December 2012 order in DTE Gas' rate case, the final approved depreciation rates will be implemented in conjunction with the MPSC's order in DTE Gas' next general rate case. Management cannot predict when DTE Gas will file its next rate case.

Gas Cost Recovery Proceedings

The GCR process is designed to allow DTE Gas 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.

2010-2011 GCR Year - An MPSC order was issued on August 14, 2012 approving the GCR reconciliation for the twelve-month period ended March 31, 2011. The MPSC authorized DTE Gas to include in its 2011-2012 GCR reconciliation beginning balance the net over-recovery of approximately $6 million.

2011-2012 GCR Year - In June 2012, DTE Gas filed its GCR reconciliation for the twelve months ending March 31, 2012 calculating a net under-recovery of $6.4 million.

Gas Recovery of Costs to Achieve (CTA) Performance Excellence Process

DTE Gas incurred CTA restructuring expense during a review of its operations which began in 2005. In September 2006, the MPSC issued an order approving a settlement agreement that allowed DTE Electric and DTE Gas, commencing in 2006, to defer the incremental CTA. Further, the order provided for DTE Electric and DTE Gas to amortize the CTA deferrals over a ten-year period beginning with the year subsequent to the year the CTA was deferred. The September 2006 order did not provide a regulatory recovery mechanism for DTE Gas, therefore DTE Gas expensed CTA incurred during the period 2006 through 2008. A June 2010 MPSC order provided for DTE Gas’ recovery of the regulatory unamortized balance of CTA. DTE Gas deferred and recognized in income approximately $32 million ($20 million after-tax) of previously expensed CTA in 2010.

XML

Property, Plant and Equipment (Details 1)	12 Months Ended
	Dec. 31, 2012
Electric [Member]
Public Utility Property, Plant and Equipment [Line Items]
Generation Electric	P40Y
Distribution	P41Y
Gas [Member]
Public Utility Property, Plant and Equipment [Line Items]
Distribution	P50Y
Transmission Gas	P53Y

XML

Disposals and Discontinued Operations

12 Months Ended

Dec. 31, 2012

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

DISCONTINUED OPERATIONS

Sale of Unconventional Gas Production Business

In December 2012, the Company sold its 100% equity interest in its Unconventional Gas Production business which consisted of gas and oil production assets in the western Barnett and Marble Falls shale areas of Texas. The properties in the sale included all of the reserves on approximately 88,000 net acres near Dallas, Texas. The sale resulted in gross proceeds of approximately $255 million, which resulted in a pre-tax loss of approximately $83 million ($55 million after tax). The sale price is subject to customary purchase price adjustments that will be recognized in the first half of 2013.

The activity of the discontinued Unconventional Gas Production business is shown below. The amounts exclude general corporate overhead costs, and related tax effects, and no portion of corporate interest costs were allocated to discontinued operations.

	Year Ended December 31
	2012			2011			2010
				(In millions)
Operating Revenues	$	55		$	39		$	32
Operation and Maintenance	24			16			11
Depreciation, Depletion and Amortization	23			18			15
Taxes Other than Income	4			3			2
Asset (Gains) and Losses, Net	83			—			10
	134			37			38
Operating Income	(79		)	2			(6		)
Other (Income) and Deductions	6			6			6
Loss Before Income Taxes	(85		)	(4		)	(12		)
Income Tax Benefit	(29		)	(1		)	(4		)
Net Loss	$	(56	)	$	(3	)	$	(8	)

XML

Organization and Basis of Presentation (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Assets [Abstract]
Cash and cash equivalents	$ 65	$ 68	$ 65	$ 52
Restricted cash	122	147
Accounts receivable	1,336	1,317
Other current assets	194	196
Property, plant and equipment	14,684	13,746
Securitized regulatory assets	413	577
Other assets	197	199
Total Assets	26,339	26,009
Liabilities [Abstract]
Current portion long-term debt, including, capital leases	817	526
Other current liabilities	538	549
Mortgage bonds, notes and other	6,220	6,405
Securitization bonds	302	479
Capital lease obligations	12	23
Other long term liabilities	306	331
Variable Interest Entity Securitization [Member]
Assets [Abstract]
Cash and cash equivalents	0		0
Restricted cash	102		107
Accounts receivable	34		34
Inventories	0		0
Other current assets	0		0
Property, plant and equipment	0		0
Securitized regulatory assets	413		577
Other assets	7		10
Total Assets	556		728
Liabilities [Abstract]
Accounts payable and accrued current liabilities	11		14
Current portion long-term debt, including, capital leases	177		164
Other current liabilities	50		55
Mortgage bonds, notes and other	0		0
Securitization bonds	302		479
Capital lease obligations	0		0
Other long term liabilities	7		7
Total Liabilities	547		719
Variable Interest Entity, Primary Beneficiary [Member]
Assets [Abstract]
Cash and cash equivalents	10		25
Restricted cash	7		7
Accounts receivable	7		17
Inventories	141		183
Other current assets	1		1
Property, plant and equipment	93		73
Securitized regulatory assets	0		0
Other assets	11		6
Total Assets	270		312
Liabilities [Abstract]
Accounts payable and accrued current liabilities	14		24
Current portion long-term debt, including, capital leases	8		7
Other current liabilities	4		0
Mortgage bonds, notes and other	25		30
Securitization bonds	0		0
Capital lease obligations	11		14
Other long term liabilities	2		2
Total Liabilities	64		77
Consolidated Variable Interest Entity [Member]
Assets [Abstract]
Cash and cash equivalents	10		25
Restricted cash	109		114
Accounts receivable	41		51
Inventories	141		183
Other current assets	1		1
Property, plant and equipment	93		73
Securitized regulatory assets	413		577
Other assets	18		16
Total Assets	826		1,040
Liabilities [Abstract]
Accounts payable and accrued current liabilities	25		38
Current portion long-term debt, including, capital leases	185		171
Other current liabilities	54		55
Mortgage bonds, notes and other	25		30
Securitization bonds	302		479
Capital lease obligations	11		14
Other long term liabilities	9		9
Total Liabilities	611		796
Variable Interest Entity Restricted [Member]
Assets [Abstract]
Cash and cash equivalents	8		0
Restricted cash	109		114
Accounts receivable	38		36
Inventories	3		0
Other current assets	1		0
Property, plant and equipment	49		23
Securitized regulatory assets	413		577
Other assets	18		16
Total Assets	639		766
Liabilities [Abstract]
Accounts payable and accrued current liabilities	12		14
Current portion long-term debt, including, capital leases	185		171
Other current liabilities	53		55
Mortgage bonds, notes and other	25		30
Securitization bonds	302		479
Capital lease obligations	11		14
Other long term liabilities	8		8
Total Liabilities	$ 596		$ 771

XML

Commitments and Contingencies (Details Textuals) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2012 facilities dte_instances
Loss Contingencies [Line Items]
Waiting Period of Policy		P12W
EPA is Alleging Detroit Edison Power Plants Violated New Source Performance Standards		5
Enforcement Actions Initiated by the MDEQ for Opacity Exceedances		0
Number of Options to Regulate Coal Ash Residue		2
Period Gas Utility Can Amortize MGP Costs		10 years
Company will Pay a Fine to the EPA to Settle Air and Water Issues		$ 1,750,000
Possible Environmental Capital Expenditures to Comply with Requirements		6,000,000
Capital Expenditures Over the Next Few Years		17,000,000
The Re-Proposed Regulations will Provide Minimum Period for Compliance		3 years
EPA Sulfur Dioxide Ambient Air Quality Standard		1
Insurance Coverage for Extra ExpenseWhen to Necessitate Power Plant when Unavailable		490,000,000
Period of Coverage of Policy for Extra Expenses		3 years
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
Insurance Deductible for Nuclear Power Plant		1,000,000
Time Period for TRIA Insurance After the First Loss from Terrorism		1 year
NEIL Policies Against Terroism Loss		3,200,000,000
Amount per Event Loss Associated with Nuclear Power Plants		31,000,000
Time Period for Maximum Assessments for Losses Associated to Events at Nuclear Plants		1 year
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
Settlement Provided for Delay-Related Costs		48,000,000
Guarantee Obligations Maximum Exposure One		50,000,000
Performance Bonds Outstanding		41,000,000
Number of Represented Employees		4,900
Long-term Purchase Commitment, Amount		4,400,000,000
estimated future capital expenditures for current year		2,200,000,000
Electric [Member]
Loss Contingencies [Line Items]
Environmental Capital Expenditures Through Current Year		1,900,000,000
Environmental Capital Expenditures in Current Year		335,000,000
Environmental Capital Expenditures In Future Years	1,600,000,000
Exceedances of Opacity Standard		1,330
Number of Facilities Accused of Exceedance of Opacity		9
Period of Years Exceedances Took Place		5 years
No Enforcement by MDEQ Over the Alleged Exceedance Period		5 years
Number of Former MGP Sites		3
Accrued for remediation related to the sites	8,000,000	9,000,000
Gas [Member]
Loss Contingencies [Line Items]
Number of Former MGP Sites		15
Accrued for remediation related to the sites	36,000,000	29,000,000
Synthetic Fuel [Member]
Loss Contingencies [Line Items]
Days Obligations will Survive After Expiration of All Applicable Statutes of Limiations		90 years
Guarantor Obligations, Maximum Exposure, Undiscounted		1,200,000,000
Emissions [Member]
Loss Contingencies [Line Items]
Days Obligations will Survive After Expiration of All Applicable Statutes of Limiations		90 days
Guarantor Obligations, Maximum Exposure, Undiscounted		$ 77,000,000

XML

Goodwill

12 Months Ended

Dec. 31, 2012

Goodwill and Intangible Assets Disclosure [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, 2012 and 2011 is as follows:

	2012			2011
	(In millions)
Balance as of January 1	$	2,020		$	2,020
Goodwill attributable to sale of Unconventional Gas Production business	(2		)	—
Balance at December 31	$	2,018		$	2,020

XML

Acquisition

12 Months Ended

Dec. 31, 2012

Business Combinations [Abstract]

Business Combination Disclosure [Text Block]

ACQUISITION

In July 2012, the Company executed an agreement to purchase a portfolio of fourteen on-site energy projects, primarily located in the Midwest, from subsidiaries of Duke Energy Corporation and GDF Suez Energy North America, Inc. This acquisition provides a growth opportunity for the Company's Power and Industrial Projects segment that will leverage its extensive energy-related operating experience and project management capabilities.

Closing for all of the entities occurred in the fourth quarter 2012. The purchase of equity interests range from 46 percent to 100 percent of the project companies for a total purchase price of approximately $294 million, which consists of $220 million paid in cash and assumption of approximately $74 million of debt. The debt assumed relates to two project companies which have been deemed variable interest entities. DTE, however, is not the primary beneficiary and thus the VIEs' assets and liabilities are not included in the Company's Consolidated Statements of Financial Position. Therefore, the assumed debt is not included in the purchase price allocation table below. There is no exposure to loss related to the debt assumed as the customer of the project companies is obligated to pay the loans in the event of default or termination. See Note 1.

The Company has completed its valuation analysis and calculations in sufficient detail necessary to arrive at the fair value of the project company assets acquired and liabilities assumed, along with the related allocation to intangible assets.

The allocation of the total consideration transferred in the acquisition to the assets acquired and liabilities assumed includes adjustments for the fair value of existing contracts and agreements and property, plant and equipment. The fair value of the assets acquired and liabilities assumed have been determined based on the accounting guidance for fair value measurements in accordance with ASC 805, “Business Combinations.” The following is the Company's assignment as of the closing date of the consideration:

	(In millions)
Cash	$	22
Accounts receivable	14
Other current assets	8
Property, plant and equipment	100
Intangible assets	75
Other noncurrent assets	9
Current liabilities	(7		)
Non-controlling interest	(1		)
Total purchase price	$	220

The Company did not record any goodwill due to the acquisition.

The intangible assets recorded as a result of the acquisition pertain to existing contracts and agreements, which were valued at approximately $75 million as of the closing date. The fair value of the intangible assets acquired was estimated by applying the income approach. The income approach is based upon discounted projected future cash flows attributable to the existing contracts and agreements. The fair value measurement is based on significant unobservable inputs, including management estimates and assumptions, and thus represents a Level 3 measurement, pursuant to the applicable accounting guidance. Key estimates and inputs include revenue and expense projections and discount rates based on the risks associated with the projects. The intangible assets are amortized on a straight line basis over a weighted-average amortization period of approximately eight years.

The Company's 2012 results of operations include revenue of $30 million and net income of $2 million associated with the acquired project companies for the approximate three-month period following the closing date. The pro forma results of operations have not been presented for DTE Energy because the effects of the acquisition were not material to our consolidated results of operations.

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Stock-Based Compensation (Details 8) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Share Based Compensation Unrecognized and Non-Vested Cost [Line Items]
Unrecognized Compensation Cost	$ 58
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 4 months 15 days
Options [Member]
Share Based Compensation Unrecognized and Non-Vested Cost [Line Items]
Unrecognized Compensation Cost	0
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	0 years 1 month 23 days
Stock Awards [Member]
Share Based Compensation Unrecognized and Non-Vested Cost [Line Items]
Unrecognized Compensation Cost	11
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 0 months 6 days
Performance Share Awards [Member]
Share Based Compensation Unrecognized and Non-Vested Cost [Line Items]
Unrecognized Compensation Cost	47
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 5 months 14 days
Total [Member]
Share Based Compensation Unrecognized and Non-Vested Cost [Line Items]
Unrecognized Compensation Cost	$ 58
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 4 months 15 days

XML

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2012

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:

	2012			2011
Property, Plant and Equipment	(In millions)
Electric
Generation	$	10,383		$	9,785
Distribution	7,306			7,003
Total Electric	17,689			16,788
Gas
Distribution	2,735			2,561
Storage	434			406
Other	852			902
Total Gas	4,021			3,869
Non-utility and other	1,921			1,884
Total	23,631			22,541
Less Accumulated Depreciation, Depletion and Amortization
Electric
Generation	(3,880		)	(3,946		)
Distribution	(2,837		)	(2,580		)
Total Electric	(6,717		)	(6,526		)
Gas
Distribution	(1,075		)	(1,041		)
Storage	(133		)	(127		)
Other	(363		)	(413		)
Total Gas	(1,571		)	(1,581		)
Non-utility and other	(659		)	(688		)
Total	(8,947		)	(8,795		)
Net Property, Plant and Equipment	$	14,684		$	13,746

The Allowance for Funds used During Construction (AFUDC) capitalized was approximately $20 million and $10 million during 2012 and 2011, respectively.

The composite depreciation rate for DTE Electric was approximately 3.3% in 2012, 2011 and 2010. The composite depreciation rate for DTE Gas was 2.4% in 2012, 2.3% in 2011 and 2.5% in 2010.

The average estimated useful life for each major class of utility property, plant and equipment as of December 31, 2012 follows:

	Estimated Useful Lives in Years
Utility	Generation	Distribution	Storage
Electric	40	41	N/A
Gas	N/A	50	53

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 15 years.

Capitalized software costs amortization expense was $75 million in 2012 and $65 million in 2011 and 2010. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2012 were $561 million and $295 million, respectively. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2011 were $623 million and $300 million, respectively. Amortization expense of capitalized software costs is estimated to be approximately $46 million annually for 2013 through 2017.

Gross property under capital leases was $32 million and $57 million at December 31, 2012 and December 31, 2011, respectively. Accumulated amortization of property under capital leases was $3 million and $34 million at December 31, 2012 and December 31, 2011, respectively.

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Significant Accounting Policies (Details 1) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Finite-Lived Intangible Assets [Line Items]
Emission Allowance	$ 6	$ 10
Renewable Energy Credits	44	39
Contract Intangible Assets	139	65
Intangible Assets, Gross	189	114
Less: Accumulated Amortization	34	28
Finite-Lived Intangible Assets, Net	155	86
Intangible Assets, Current	20	13
Intangible Assets, Net	$ 135	$ 73

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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, 2012	Dec. 31, 2011	Dec. 31, 2010
Other Postretirement Benefit Plans, Defined Benefit [Member]
Other Postretirement Costs [Line Items]
Service cost	$ 68	$ 64	$ 61
Interest cost	120	121	125
Expected return on plan assets	(92)	(94)	(74)
Net loss	80	55	54
Prior service cost	(27)	(26)	(4)
Net transition obligation	2	2	2
Net postretirement cost	$ 151	$ 122	$ 164

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Property, Plant and Equipment (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Public Utility Property, Plant and Equipment [Line Items]
AFUDC capitalized	$ 20	$ 10
Capitalized Computer Software, Amortization	75	65	65
Capitalized Computer Software, Gross	561	623
Capitalized Computer Software, Accumulated Amortization	295	300
Capitalized Computer Software Future Amortization Expense	46
Capital Leased Assets, Gross	32	57
Capital Leases, Lessee Balance Sheet, Assets by Major Class, Accumulated Depreciation	$ 3	$ 34
Electric [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 [Member]
Public Utility Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.40%	2.30%	2.50%
Minimum [Member]
Public Utility Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Finite-Lived Intangible Assets, Useful Life	3 years
Maximum [Member]
Public Utility Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	55 years
Finite-Lived Intangible Assets, Useful Life	15 years

XML

Fair Value (Details 1) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis
Beginning Balance	$ 44	$ 59
Transfers into Level 3	1	4
Transfer out of Level 3	0	(24)
Total gains: [Abstract]
Included in earnings	60	87
Recorded in regulatory assets/liabilities	15	2
Purchases issuances and settlements [Abstract]
Purchases	2	3
Settlements	(135)	(87)
Ending Balance	(13)	44
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	58	75
Natural Gas [Member]
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis
Beginning Balance	6	1
Transfers into Level 3	1	0
Transfer out of Level 3	0	1
Total gains: [Abstract]
Included in earnings	(41)	7
Recorded in regulatory assets/liabilities	0	0
Purchases issuances and settlements [Abstract]
Purchases	0	0
Settlements	(4)	(3)
Ending Balance	(38)	6
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	(33)	8
Electricity [Member]
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis
Beginning Balance	32	54
Transfers into Level 3	0	4
Transfer out of Level 3	0	(25)
Total gains: [Abstract]
Included in earnings	101	77
Recorded in regulatory assets/liabilities	0	0
Purchases issuances and settlements [Abstract]
Purchases	2	3
Settlements	(112)	(81)
Ending Balance	23	32
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	91	65
Other [Member]
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis
Beginning Balance	6	4
Transfers into Level 3	0	0
Transfer out of Level 3	0	0
Total gains: [Abstract]
Included in earnings	0	3
Recorded in regulatory assets/liabilities	15	2
Purchases issuances and settlements [Abstract]
Purchases	0	0
Settlements	(19)	(3)
Ending Balance	2	6
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	$ 0	$ 2

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Long-Term Debt (Details 3) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Maturity of Long Term Debt [Line Items]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 811
Long-term Debt, Maturities, Repayments of Principal in Year Two	891
Long-term Debt, Maturities, Repayments of Principal in Year Three	476
Long-term Debt, Maturities, Repayments of Principal in Year Four	465
Long-term Debt, Maturities, Repayments of Principal in Year Five	9
Long-term Debt, Maturities, Repayments of Principal after Year Five	5,166
Long Term Debt Maturities Repayment of Principal	$ 7,818

XML

Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Comprehensive Income [Line Items]
Net Unrealized Gain/(Loss) on Derivaive	$ (4)	$ (4)
Net Unrealized Gain/(Loss) on Investments	(29)	(30)
Benefit Obligations	(127)	(125)
Foreign Currency Translation	2	1
Accumulated Other Comprehensive Loss	(158)	(158)
Current period change, net of tax Net Unrealized Gain/(Loss) on Derivatives Gain (Loss) on Derivatives Arising During Period, Net of Tax	0
Current period change, net of tax Net Unrealized Gain/(Loss) on Investments	1	0	(20)
Current period change, net of tax Benefit Obligations	(2)	(9)	15
Current period change, net of tax Foreign Currency Translation	1	0	1
Current period change, net of tax AccumulatedOther Comprehensive Loss	$ 0

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Income Taxes (Details 1) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Tax Expense [Line Items]
Federal	$ 190	$ 27	$ (168)
State and other income tax	49	21	26
Total current income taxes	239	48	(142)
Federal	39	318	415
State and other income tax	8	(98)	42
Total deferred income taxes	47	220	457
Total	286	268	315
Discontinued operations	(29)	(1)	(4)
Total	$ 257	$ 267	$ 311

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Stock-Based Compensation (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 83	$ 66	$ 52
Tax benefit	33	25	20
Stock-based compensation cost capitalized in property, plant and equipment	$ 5	$ 4	$ 3

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Significant Accounting Policies (Policies)

3 Months Ended

12 Months Ended

Dec. 31, 2011

Dec. 31, 2012

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. DTE Electric and DTE Gas record revenues for electricity and gas provided but unbilled at the end of each month. Rates for DTE Electric and DTE Gas 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 subject to reconciliation and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are recorded on the Consolidated Statements of Financial Position and are recovered or returned to customers through adjustments to the billing factors.

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. See Note 4 for discussion of derivative contracts.

Accounting For ISO Transactions [Policy Text Block]

Accounting for ISO Transactions

DTE Electric 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. DTE Electric 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 DTE Electric records net purchases in Fuel, purchased power and gas and net sales in Operating revenues on the Consolidated Statements of Operations. DTE Electric 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.

DTE Electric 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, 2012 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 DTE Electric and DTE Gas 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. The time period for write-off was changed in 2012 from 365 days to 150 days 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 $686 million and $597 million are included in customer accounts receivable at December 31, 2012 and 2011, 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.

Natural gas inventory of $37 million and $52 million as of December 31, 2012 and 2011, respectively, at DTE Gas is determined using the last-in, first-out (LIFO) method. At December 31, 2012, the replacement cost of gas remaining in storage exceeded the LIFO cost by $113 million. At December 31, 2011, the replacement cost of gas remaining in storage exceeded the LIFO cost by $95 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 is charged to accumulated depreciation. Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2.

Utility property at DTE Electric and DTE Gas 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 the straight-line and units of production methods.

Depreciation, depletion and amortization expense also includes the amortization of certain regulatory assets.

Approximately $12 million and $23 million of expenses related to Fermi 2 refueling outages were accrued at December 31, 2012 and December 31, 2011, respectively. Amounts are accrued on a pro-rata basis, generally 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 Statements of Operations and is recorded 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 discounted 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 28 years. Intangible assets amortization expense was $6 million in 2012, $5 million in 2011 and $4 million in 2010. Amortization expense of intangible assets is estimated to be $13 million annually for 2013 through 2017.

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, 2012, the total cash collateral received, net of cash collateral posted, was $20 million. As of December 31, 2011, the total cash collateral posted, net of cash collateral received, was $71 million. There was no collateral related to unrealized positions to net against derivative assets and liabilities as of December 31, 2012. At December 31, 2011, derivative assets and derivative liabilities were shown net of collateral of $19 million and $74 million, respectively. The Company recorded cash collateral paid of $4 million and cash collateral received of $24 million not related to unrealized derivative positions as of December 31, 2012. The Company recorded cash collateral paid of $16 million not related to unrealized derivative positions, as of December 31, 2011. 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.

Foundation Related Party [Policy Text Block]

DTE Energy Foundation

Charitable contributions to the DTE Energy Foundation were $21 million, $21 million, and $14 million for the years ended December 31, 2012, 2011 and 2010, respectively. The DTE Energy Foundation is a non-consolidated not-for-profit private foundation, the purpose of which is to contribute and assist charitable organizations and does not serve a direct business or political purpose of DTE.

Other Accounting Policies [Policy Text Block]

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
10	Asset Retirement Obligations
11	Regulatory Matters
12	Income Taxes
20	Retirement Benefits and Trusteed Assets
21	Stock-based Compensation

XML

Segment Information (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	$ 848	$ 301	$ 219
Electric [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	29	33	30
Gas [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	4	2	0
Gas Storage and Pipelines [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	6	8	4
Power and Industrial Projects [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	801	238	161
Energy Trading [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	43	70	89
Corporate and Other [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	(37)	(50)	(65)
Segment, Discontinued Operations [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	$ 2	$ 0	$ 0

XML

Capital and Operating Leases (Tables)

12 Months Ended

Dec. 31, 2012

Capital and Operating Leases [Abstract]

Capital and Operating Leases [Table Text Block]

	Capital Leases		Operating Leases
	(In millions)
2013	$	7	$	38
2014	5		31
2015	5		25
2016	3		21
2017	—		20
Thereafter	—		98
Total minimum lease payments	$	20	$	233
Less imputed interest	2
Present value of net minimum lease payments	18
Less current portion	6
Non-current portion	$	12

Schedule of Capital Lease of Lessor [Table Text Block]

	(In millions)
2013	$	12
2014	12
2015	12
2016	12
2017	12
Thereafter	31
Total minimum future lease receipts	91
Residual value of leased pipeline	40
Less unearned income	(48		)
Net investment in capital lease	83
Less current portion	(4		)
	$	79

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Common Stock

12 Months Ended

Dec. 31, 2012

Stockholders' Equity Note [Abstract]

Schedule of Stock by Class [Table Text Block]

COMMON STOCK

Common Stock

On June 18, 2012, the Company contributed $80 million of DTE Energy common stock to the DTE Energy Company Affiliates Employee Benefit Plans Master Trust. The common stock was valued using the closing market price of DTE Energy common stock on that date in accordance with fair value measurement and accounting requirements.

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 was to restrict the payment of approximately $239 million at December 31, 2012 of total retained earnings of approximately $4 billion. 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 3) (Pension Plans, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2012
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 2013	$ 236
Defined Benefit Plan, Expected Future Benefit Payments in 2014	242
Defined Benefit Plan, Expected Future Benefit Payments in 2015	252
Defined Benefit Plan, Expected Future Benefit Payments in 2016	260
Defined Benefit Plan, Expected Future Benefit Payments in 2017	269
Defined Benefit Plan, Expected Future Benefit Payments in 2018-2022	1,485
Total Defined Benefit Pension Plan Expected Future Payments	$ 2,744

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Capital and Operating Leases

12 Months Ended

Dec. 31, 2012

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 Company has also entered into various power purchase agreements which meet the criteria of capital and operating leases. The lease arrangements expire at various dates through 2032. Future minimum lease payments under non-cancelable leases at December 31, 2012 were:

	Capital Leases		Operating Leases
	(In millions)
2013	$	7	$	38
2014	5		31
2015	5		25
2016	3		21
2017	—		20
Thereafter	—		98
Total minimum lease payments	$	20	$	233
Less imputed interest	2
Present value of net minimum lease payments	18
Less current portion	6
Non-current portion	$	12

Rental expense for operating leases was $36 million in 2012, $40 million in 2011, and $32 million in 2010. Contingent rental payments of $27 million were incurred in 2012 related to power purchase agreements. The contingent payments are based upon delivery of energy and renewable energy credits, which are dependent upon future production.

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, 2012, were as follows:

	(In millions)
2013	$	12
2014	12
2015	12
2016	12
2017	12
Thereafter	31
Total minimum future lease receipts	91
Residual value of leased pipeline	40
Less unearned income	(48		)
Net investment in capital lease	83
Less current portion	(4		)
	$	79

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Income Taxes (Details Textuals) (USD $)	3 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	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		$ 254,000,000
Deferred Tax Assets State Net Operating Loss and Credit Carry Forwards 1		37,000,000		30,000,000
Valuation Allowance, Amount		33,000,000		27,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate		3,000,000		4,000,000
Time Period of Unrecognized Tax Benefits that Would Impact Effective Tax Rate		12 months
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit		1,000,000
Unrecognized Tax Benefits, Interest on Income Taxes Accrued		1,000,000		2,000,000
Unrecognized Tax Benefits, Income Tax Penalties Accrued		0
Unrecognized Tax Benefits, Interest on Income Taxes Expense		(1,000,000)	(2,000,000)	1,000,000
Michigan Corporate Income Tax	6.00%
Time Period for the MBT Deferred Tax Asset		1 year
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	286,000,000	268,000,000	315,000,000
Consistnet with Orginal Treatment of Deferred Tax Liabilities No Cash Flow Impact	0
Settlement with Taxing Authority [Member]
Federal and State Income Tax [Line Items]
Unrecognized Tax Benefits, Increases Resulting from Prior Period Tax Positions		$ 30,000,000

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Preferred and Preferenced Securities (Tables)

12 Months Ended

Dec. 31, 2012

Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Preferred and Preferenced Securities [Table Text Block]

As of December 31, 2012, the amount of authorized and unissued stock is as follows:

Company	Type of Stock	Par Value		Shares Authorized
DTE Energy	Preferred	$	—	5,000,000
DTE Electric	Preferred	$	100	6,747,484
DTE Electric	Preference	$	1	30,000,000
DTE Gas	Preferred	$	1	7,000,000
DTE Gas	Preference	$	1	4,000,000

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Short-Term Credit Arrangements and Borrowings (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Availability under combined facilities
Total credit facilities at December 31, 2012	$ 1,975
Amounts Outstanding
Commercial paper issuances	240
Letters of credit	175
Total amounts outstanding	415
Net availability at December 31, 2012	1,560
Unsecured letter of credit facility, expiering in May 2013 (Member
Availability under combined facilities
Total credit facilities at December 31, 2012	50
Unsecured letter of credit facility, expiring in August 2015[Member]
Availability under combined facilities
Total credit facilities at December 31, 2012	125
Unsecured revolving credit facility, expiring October 26 [Member]
Availability under combined facilities
Total credit facilities at December 31, 2012	1,800
DTE Energy [Member]
Availability under combined facilities
Total credit facilities at December 31, 2012	1,275
Amounts Outstanding
Commercial paper issuances	0
Letters of credit	175
Total amounts outstanding	175
Net availability at December 31, 2012	1,100
DTE Energy [Member] | Unsecured letter of credit facility, expiering in May 2013 (Member
Availability under combined facilities
Total credit facilities at December 31, 2012	50
DTE Energy [Member] | Unsecured letter of credit facility, expiring in August 2015[Member]
Availability under combined facilities
Total credit facilities at December 31, 2012	125
DTE Energy [Member] | Unsecured revolving credit facility, expiring October 26 [Member]
Availability under combined facilities
Total credit facilities at December 31, 2012	1,100
DTE Electric [Member]
Availability under combined facilities
Total credit facilities at December 31, 2012	300
Amounts Outstanding
Commercial paper issuances	130
Letters of credit	0
Total amounts outstanding	130
Net availability at December 31, 2012	170
DTE Electric [Member] | Unsecured letter of credit facility, expiering in May 2013 (Member
Availability under combined facilities
Total credit facilities at December 31, 2012	0
DTE Electric [Member] | Unsecured letter of credit facility, expiring in August 2015[Member]
Availability under combined facilities
Total credit facilities at December 31, 2012	0
DTE Electric [Member] | Unsecured revolving credit facility, expiring October 26 [Member]
Availability under combined facilities
Total credit facilities at December 31, 2012	300
DTE Gas [Member]
Availability under combined facilities
Total credit facilities at December 31, 2012	400
Amounts Outstanding
Commercial paper issuances	110
Letters of credit	0
Total amounts outstanding	110
Net availability at December 31, 2012	290
DTE Gas [Member] | Unsecured letter of credit facility, expiering in May 2013 (Member
Availability under combined facilities
Total credit facilities at December 31, 2012	0
DTE Gas [Member] | Unsecured letter of credit facility, expiring in August 2015[Member]
Availability under combined facilities
Total credit facilities at December 31, 2012	0
DTE Gas [Member] | Unsecured revolving credit facility, expiring October 26 [Member]
Availability under combined facilities
Total credit facilities at December 31, 2012	$ 400

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Disposals and Discontinued Operations Disposals and Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2012

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]

	Year Ended December 31
	2012			2011			2010
				(In millions)
Operating Revenues	$	55		$	39		$	32
Operation and Maintenance	24			16			11
Depreciation, Depletion and Amortization	23			18			15
Taxes Other than Income	4			3			2
Asset (Gains) and Losses, Net	83			—			10
	134			37			38
Operating Income	(79		)	2			(6		)
Other (Income) and Deductions	6			6			6
Loss Before Income Taxes	(85		)	(4		)	(12		)
Income Tax Benefit	(29		)	(1		)	(4		)
Net Loss	$	(56	)	$	(3	)	$	(8	)

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Capital and Operating Leases (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Capital and Operaing Lease [Line Items]
Capital Lease Payments in 2013	$ 7
Operating Leases Payments in 2013	38
Capital Lease Payments in 2014	5
Operating Lease Payments in 2014	31
Capital Lease Payments in 2015	5
Operating Lease Payments in 2015	25
Capital Lease Payments in 2016	3
Operating Lease Payments in 2016	21
Capital Lease Payments in 2017	0
Operating Lease Payments in 2017	20
Capital Lease Payments Thereafter	0
Operating Lease Payments Thereafter	98
Capital Lease - Total minimum payments	20
Operating Lease - Total minimum payments	233
Less imputed interest	2
Present value of net minimum lease payments	18
Less current portion	6
Non-current portion	$ 12	$ 23

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Consolidated Statements of Financial Position (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Current Assets
Cash and cash equivalents	$ 65	$ 68
Restricted cash, principally Securitization	122	147
Accounts receivable (less allowance for doubtful accounts of $62 and $162, respectively)
Customer	1,336	1,317
Other	126	90
Inventories
Fuel and gas	527	572
Materials and supplies	234	219
Deferred income taxes	21	51
Derivative assets	108	222
Regulatory assets	182	314
Other	194	196
Total Current Assets	2,915	3,196
Investments
Nuclear decommissioning trust funds	1,037	937
Other	554	525
Total Investments	1,591	1,462
Property
Property, plant and equipment	23,631	22,541
Less accumulated depreciation, depletion and amortization	(8,947)	(8,795)
Property, plant and equipment, net	14,684	13,746
Other Assets
Goodwill	2,018	2,020
Regulatory assets	4,235	4,539
Securitized regulatory assets	413	577
Intangible assets	135	73
Notes receivable	112	123
Derivative assets	39	74
Other	197	199
Total Noncurrent Assets	7,149	7,605
Total Assets	26,339	26,009
Current Liabilities
Accounts payable	848	782
Accrued interest	93	95
Dividends payable	107	99
Short-term borrowings	240	419
Current portion long-term debt, including capital leases	817	526
Derivative liabilities	125	158
Other	538	549
Total Current Liabilities	2,768	2,628
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	6,220	6,405
Securitization bonds	302	479
Junior subordinated debentures	480	280
Capital lease obligations	12	23
Total Long-Term Debt (net of current portion)	7,014	7,187
Other Liabilities
Deferred income taxes	3,191	3,116
Regulatory liabilities	1,031	1,019
Asset retirement obligations	1,719	1,591
Unamortized investment tax credit	56	65
Derivative liabilities	26	89
Accrued pension liability	1,498	1,298
Accrued postretirement liability	1,160	1,484
Nuclear decommissioning	159	148
Other	306	331
Total Noncurrent Liabilities	9,146	9,141
Equity
Common stock, without par value, 400,000,000 shares authorized, 172,351,680 and 169,247,282 shares issued and outstanding, respectively	3,587	3,417
Retained earnings	3,944	3,750
Accumulated other comprehensive loss	(158)	(158)
Total DTE Energy Company Equity	7,373	7,009
Noncontrolling interests	38	44
Total Equity	7,411	7,053
Total Liabilities and Equity	$ 26,339	$ 26,009

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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, 2012	Dec. 31, 2011
Asset Retirement Obligations [Line Items]
Liability Recorded for Non Estimatable Values of Assets Related to ARO			$ 0
Revision in estimated cash flows	19,000,000	20,000,000	10,000,000	22,000,000
Reserve and Impairment of Retirement Obligation		6,000,000
Proposed Extension of Nuclear Plant 2 License			20 years
Decommissioning Expenses Current			1,500,000,000
Decommissioning Liability, Noncurrent			159,000,000	148,000,000
Inflation Rate Used to Determine Estimated Decommissioning Expenditures			6.00%
Nuclear Decommissioning Liabilities Funded Through Surcharge and Included In ARO Balance			1,500,000,000
Liabilities Balance upon Completion of Decommissioning			0
Fermi 2 [Member]
Asset Retirement Obligations [Line Items]
Decommissioning Liability, Noncurrent			$ 10,000,000,000

XML

Significant Accounting Policies (Notes)

12 Months Ended

Dec. 31, 2012

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. DTE Electric and DTE Gas record revenues for electricity and gas provided but unbilled at the end of each month. Rates for DTE Electric and DTE Gas 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 subject to reconciliation and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are recorded on the Consolidated Statements of Financial Position and are recovered or returned to customers through adjustments to the billing factors.

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. See Note 4 for discussion of derivative contracts.

Accounting for ISO Transactions

DTE Electric 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. DTE Electric 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 DTE Electric records net purchases in Fuel, purchased power and gas and net sales in Operating revenues on the Consolidated Statements of Operations. DTE Electric 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.

DTE Electric 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, 2012 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.

	Year Ended December 31, 2012
	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 January 1, 2012	$	(4	)	$	(30	)	$	(125	)	$	1	$	(158	)
Current period change, net of tax	—			1			(2		)	1		—
Ending balances December 31, 2012	$	(4	)	$	(29	)	$	(127	)	$	2	$	(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 DTE Electric and DTE Gas 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. The time period for write-off was changed in 2012 from 365 days to 150 days 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 $686 million and $597 million are included in customer accounts receivable at December 31, 2012 and 2011, 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.

Natural gas inventory of $37 million and $52 million as of December 31, 2012 and 2011, respectively, at DTE Gas is determined using the last-in, first-out (LIFO) method. At December 31, 2012, the replacement cost of gas remaining in storage exceeded the LIFO cost by $113 million. At December 31, 2011, the replacement cost of gas remaining in storage exceeded the LIFO cost by $95 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 is charged to accumulated depreciation. Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2.

Utility property at DTE Electric and DTE Gas 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 the straight-line and units of production methods.

Depreciation, depletion and amortization expense also includes the amortization of certain regulatory assets.

Approximately $12 million and $23 million of expenses related to Fermi 2 refueling outages were accrued at December 31, 2012 and December 31, 2011, respectively. Amounts are accrued on a pro-rata basis, generally 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 Statements of Operations and is recorded 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 discounted 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, 2012 and 2011:

	2012		2011
	(In millions)
Emission allowances	$	6	$	10
Renewable energy credits	44		39
Contract intangible assets	139		65
	189		114
Less accumulated amortization	34		28
Intangible assets, net	155		$	86
Less current intangible assets	20		$	13
	$	135	$	73

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 28 years. Intangible assets amortization expense was $6 million in 2012, $5 million in 2011 and $4 million in 2010. Amortization expense of intangible assets is estimated to be $13 million annually for 2013 through 2017.

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, 2012, the total cash collateral received, net of cash collateral posted, was $20 million. As of December 31, 2011, the total cash collateral posted, net of cash collateral received, was $71 million. There was no collateral related to unrealized positions to net against derivative assets and liabilities as of December 31, 2012. At December 31, 2011, derivative assets and derivative liabilities were shown net of collateral of $19 million and $74 million, respectively. The Company recorded cash collateral paid of $4 million and cash collateral received of $24 million not related to unrealized derivative positions as of December 31, 2012. The Company recorded cash collateral paid of $16 million not related to unrealized derivative positions, as of December 31, 2011. 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.

DTE Energy Foundation

Charitable contributions to the DTE Energy Foundation were $21 million, $21 million, and $14 million for the years ended December 31, 2012, 2011 and 2010, respectively. The DTE Energy Foundation is a non-consolidated not-for-profit private foundation, the purpose of which is to contribute and assist charitable organizations and does not serve a direct business or political purpose of DTE.

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
10	Asset Retirement Obligations
11	Regulatory Matters
12	Income Taxes
20	Retirement Benefits and Trusteed Assets
21	Stock-based Compensation

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Valuation and Qualifying Accounts Valuation and Qualifying Accounts (Tables)

12 Months Ended

Dec. 31, 2012

Valuation and Qualifying Accounts [Abstract]

Summary of Valuation Allowance [Table Text Block]

Valuation and Qualifying Accounts

	Year Ending December 31,
	2012			2011			2010
	(In millions)
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statements of Financial Position)
Balance at Beginning of Period	$	162		$	196		$	262
Additions:
Charged to costs and expenses	79			94			113
Charged to other accounts (a)	16			18			20
Deductions (b)	(195		)	(146		)	(199		)
Balance at End of Period	$	62		$	162		$	196

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Disposals and Discontinued Operations Disposals and Discontinued Operations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating Income	$ 267	$ 406	$ 294	$ 312	$ 346	$ 398	$ 288	$ 389	$ 1,279	$ 1,421	$ 1,470
Income Tax Benefit							87		286	268	315
Net Loss	(56.00)	1.00	(1.00)	0	(1.00)	0	(1.00)	(1.00)	(56.00)	(3.00)	(8.00)
Segment, Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Revenue									55	39	32
Disposal Group, Including Discontinued Operation, Operating Expense									24	16	11
Depreciation and Amortization, Discontinued Operations									23	18	15
Taxes Other than Income Related to Discontinued Operations									4	3	2
Assets (Gains) and Losses Related to Sale of Segment									83	0	10
Expenses from Discontinued Operations									134	37	38
Operating Income									(79)	2	(6)
Other (income) and deductions									6	6	6
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax									(85)	(4)	(12)
Income Tax Benefit									(29)	(1)	(4)
Net Loss									$ (56.00)	$ (3.00)	$ (8.00)

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Short-Term Credit Arrangements and Borrowings (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 banks	Dec. 31, 2011
Short-term Debt [Line Items]
Revolving Credit Facilities with a Syndicate Number of Banks	20
Number of Banks that Provide Percentage of Commitment in any Facility	1
Maximum Percentage of Commitment to Bank in any Facility	8.50%
Maximum Total Funded Debt to Total Capitalization Ratio	0.65
Maximum Total Funded Debt to Total Capitilization Ration Denominator	1
Letters of Credit Outstanding, Amount	$ 73
Short-term Debt, Weighted Average Interest Rate	0.40%	0.50%
Borrowing Capacity Under Financing Agreement With iss Clearing Agent	100
Maximum Additional Margin Financing	50
Line of Credit Facility, Increase, Additional Borrowings	40
Line of Credit Facility Current Borrowing	140
Other Short-term Borrowings	$ 65	$ 56
DTE Energy [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio	0.48
Total Funded Debt to Total Capitalization Ratio Denominator	1
DTE Electric [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio	0.52
Total Funded Debt to Total Capitalization Ratio Denominator	1
DTE Gas [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio	0.46
Total Funded Debt to Total Capitalization Ratio Denominator	1

XML

Fair Value Fair Value (Details 4) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Fair Value of Financial Instruments [Line Items]
Notes Receivable Excudling Capital Leases	$ 39	$ 48
Notes Receivable, Fair Value Disclosure		48
Dividends Payable, Current	107	99
Dividends Payable Fair Value Disclosure		99
Short-term Debt	240	419
Notes Payable, Fair Value Disclosure		419
Long-term Debt	7,813	7,682
Long-term Debt, Fair Value		8,757
Fair Value, Inputs, Level 1 [Member]
Fair Value of Financial Instruments [Line Items]
Notes Receivable, Fair Value Disclosure	0
Dividends Payable Fair Value Disclosure	107
Notes Payable, Fair Value Disclosure	0
Long-term Debt, Fair Value	507
Fair Value, Inputs, Level 2 [Member]
Fair Value of Financial Instruments [Line Items]
Notes Receivable, Fair Value Disclosure	0
Dividends Payable Fair Value Disclosure	0
Notes Payable, Fair Value Disclosure	240
Long-term Debt, Fair Value	7,453
Fair Value, Inputs, Level 3 [Member]
Fair Value of Financial Instruments [Line Items]
Notes Receivable, Fair Value Disclosure	39
Dividends Payable Fair Value Disclosure	0
Notes Payable, Fair Value Disclosure	0
Long-term Debt, Fair Value	$ 933

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Commitments and Contingencies (Notes)

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

Environmental

Electric

Air - DTE Electric 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, DTE Electric has spent approximately $1.9 billion through 2012. The Company estimates DTE Electric will make capital expenditures of approximately $335 million in 2013 and up to approximately $1.6 billion of additional capital expenditures through 2020 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 U. S. Court of Appeals for the District of Columbia Circuit granted the motions to stay the rule, leaving DTE Electric temporarily subject to the previously existing Clean Air Interstate Rule (CAIR). On August 21, 2012, the Court issued its decision, vacating CSAPR and leaving CAIR in place. The EPA's petition seeking a rehearing of the U.S. Court of Appeals' decision regarding the CSAPR was denied on January 24, 2013. 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 DTE Electric 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 U. S. 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 DTE Electric, 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 DTE Electric 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 DTE Electric 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 DTE Electric'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. Oral arguments took place on November 27, 2012 in the appeal of the August 2011 summary judgment before a three-judge panel of the Sixth Circuit Court of Appeals in Cincinnati, Ohio. A decision in this appeal is expected in early 2013. DTE Energy and DTE Electric 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.

On November 9, 2012, the Sierra Club filed a Notice of Intent to Sue DTE Electric for Violations of the Clean Air Act at the St. Clair, Belle River, and Trenton Channel power plants. The notice cites 1,330 total exceedances of the 6-minute opacity standard at nine electric generating units over a five-year period. The Sierra Club obtained the opacity exceedance data from excess emission reports that are submitted every quarter by DTE Electric to the MDEQ. No enforcement actions have been initiated by the MDEQ over this five-year period as a result of the reported opacity exceedances. The Company will develop a strategy for responding to the petition from the Sierra Club that is expected in early 2013.

Water - In response to an EPA regulation, DTE Electric would be 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, DTE Electric may be required to install technologies to reduce the impacts of the water intake structures. The initial rule published in 2004 was subsequently remanded and a proposed rule published in 2011. The proposed rule specified an eight year compliance timeline. In July 2012, the EPA announced that a notice of its final action on the rule will be issued June 2013. 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. DTE Electric 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, electric generating power plants, 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, 2012 and 2011, the Company had $9 million and $8 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.

DTE Electric 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. 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

Contaminated Sites — Gas segment, owned 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 segment recognizes a liability and corresponding regulatory asset for estimated investigation and remediation costs at former MGP sites. As of December 31, 2012 and 2011, the Company had $29 million and $36 million, accrued for remediation, respectively.

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 DTE Gas, which allows DTE Gas 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 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 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 and the Pennsylvania Department of Environmental Protection (PADEP) have also alleged certain violations of the Clean Water Act including wastewater discharges and coal pile storm water runoff discussed below. The Company agreed to a Consent Order with the EPA and settled these historic air and water issues by paying a fine of $1.75 million.

The Company received two NOVs from the PADEP 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 PADEP to upgrade its wastewater treatment technology to a biological treatment facility. The Company expects to spend less than $6 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 $17 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. Final IBMACT and CISWI were issued by the EPA in December 2012. The Company will assess the financial impact, if any, on current operations for compliance with the applicable new standards.

In 2010, the EPA finalized a new 1-hour sulfur dioxide ambient air quality standard that requires states to submit plans for non-attainment areas to be in compliance by 2017. Michigan's proposed non-attainment area includes DTE Energy facilities in southwest Detroit and areas of Wayne County. Preliminary modeling runs by the MDEQ suggest that emission reductions may be required by significant sources of sulfur dioxide emissions in these areas, including DTE Electric power plants and our Michigan coke battery. The state implementation plan process is in the preliminary stage and any required emission reductions for DTE Energy sources to meet the standard cannot be estimated currently.

Nuclear Operations

Property Insurance

DTE Electric 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.

DTE Electric 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 3-year period.

DTE Electric 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, subject to a $1 million deductible.

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

Public Liability Insurance

As of January 1, 2013, as required by federal law, DTE Electric 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, DTE Electric has a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. DTE Electric 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. DTE Electric 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 2014. 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.

DTE Electric 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. In July 2012, DTE Electric executed a settlement agreement with the federal government for costs associated with the DOE's delay in acceptance of spent nuclear fuel from Fermi 2 for permanent storage. The settlement provided for a payment of approximately $48 million, received in August 2012, for delay-related costs experienced by DTE Electric through 2010, and a claims process for submittal of delay-related costs from 2011 through 2013. The settlement proceeds reduced the cost of the dry cask storage facility assets. The federal government continues to maintain its legal obligation to accept spent nuclear fuel from Fermi 2 for permanent storage. Issues relating to long-term waste disposal policy and to the disposition of funds contributed by DTE Electric 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, 2012 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, 2012 is approximately $77 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 $50 million at December 31, 2012.

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, 2012, the Company had approximately $41 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 4,900 represented employees. The majority of represented employees are under contracts that expire in June and October 2013.

Purchase Commitments

As of December 31, 2012, 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 $4.4 billion from 2013 through 2052 as detailed in the following table:

	(In millions)
2013	$	1,937
2014	1,199
2015	424
2016	147
2017	88
2018 — 2052	582
	$	4,377

The Company also estimates that 2013 capital expenditures will be approximately $2.2 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.

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Retirement Benefits and Trusteed Assets (Details 5) (Pension Plans, Defined Benefit [Member])	12 Months Ended
	Dec. 31, 2012
Pension Plan Target Allocations of Plan Assets [Line Items]
Defined Benefit Plan Target Allocation Percentage of Assets Hedged Funds and Similar Investments	20.00%
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%
Fixed Income Securities [Member]
Pension Plan Target Allocations of Plan Assets [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities	25.00%
Equity Securities, Other [Member]
Pension Plan Target Allocations of Plan Assets [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities	8.00%

XML

Stock-Based Compensation (Details 1) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options outstanding at January 1, 2012	2,764,670
Granted	0
Exercised	(1,555,227)
Forfeitured and expired	(16,773)
Options outstanding at December 31, 2012	1,192,670
Options exercisable at December 31, 2012	991,826
Weighted Average Exercise Price Per Share - Options outstanding at January 1, 2011	$ 41.25
Weighted Average Exercise Price Per Share - Granted	$ 0
Weighted Average Exercise Price Per Share - Exercised	$ 40.78
Weighted Average Exercise Price Per Share - Forfeitured or expired	$ 42.02
Weighted Average Exercise Price Per Share - Options outstanding at December 31, 2011	$ 41.86
Weighted Average Exercise Price Per Share - Options exercisable at December 31, 2011	$ 41.44
Aggregate Intrinsic Value - Options outstanding at December 31, 2012	$ 22
Aggregate Intrinsic Value - Options exercisable at December 31, 2012	$ 19

XML

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, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 1,153	$ 985	$ 1,029
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	665	525
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	283	305
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	205	155
Short-term investments [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	3	13
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	1	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	2	13
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	192	190
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	189	175
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	3	15
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	105	76
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	105	70
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	0	6
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	237	190
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	230	176
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	7	14
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	285	260
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	38	24
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	247	236
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	245	196
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	102	80
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	24	21
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	119	95
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	86	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	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	$ 86	$ 60

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Financial and Other Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	$ 1,016	$ 2,805
Derivative Liability Fair Value Gross Liability	(1,020)	(2,811)
Derivative Assets, Current	108	222
Derivative Assets, Noncurrent	39	74
Derivative Liabilities, Current	125	158
Derivative Liabilities, Noncurrent	26	89
Estimate of Fair Value, Fair Value Disclosure [Member]
Derivatives designated as hedging instruments:
Derivative Assets, Current	862	2,272
Derivative Assets, Noncurrent	154	533
Derivative Liabilities, Current	(879)	(2,282)
Derivative Liabilities, Noncurrent	(141)	(529)
Derivative Asset [Member]
Derivatives designated as hedging instruments:
Derivative Assets, Current	862	2,272
Derivative Assets, Noncurrent	154	533
Derivative Liabilities [Member]
Derivatives designated as hedging instruments:
Derivative Liabilities, Current	(879)	(2,282)
Derivative Liabilities, Noncurrent	(141)	(529)
Counterparty Netting [Member]
Derivatives designated as hedging instruments:
Derivative Assets, Current	(754)	(2,050)
Derivative Assets, Noncurrent	(115)	(440)
Derivative Liabilities, Current	754	2,050
Derivative Liabilities, Noncurrent	115	440
Collateral Adjustment [Member]
Derivatives designated as hedging instruments:
Derivative Assets, Current	0	0
Derivative Assets, Noncurrent	0	(19)
Derivative Liabilities, Current	0	74
Derivative Liabilities, Noncurrent	0	0
Derivative [Member]
Derivatives designated as hedging instruments:
Derivative Assets, Current	108	222
Derivative Assets, Noncurrent	39	74
Derivative Liabilities, Current	(125)	(158)
Derivative Liabilities, Noncurrent	(26)	(89)
Designated as Hedging Instrument [Member] | Interest rate contracts [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	0	0
Derivative Liability Fair Value Gross Liability	(1)	(1)
Not Designated as Hedging Instrument [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	1,016	2,805
Derivative Liability Fair Value Gross Liability	(1,019)	(2,810)
Not Designated as Hedging Instrument [Member] | Foreign currency exchange contracts [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	0	3
Derivative Liability Fair Value Gross Liability	0	(5)
Not Designated as Hedging Instrument [Member] | Natural Gas [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	645	2,024
Derivative Liability Fair Value Gross Liability	(661)	(2,080)
Not Designated as Hedging Instrument [Member] | Electricity [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	360	747
Derivative Liability Fair Value Gross Liability	(351)	(705)
Not Designated as Hedging Instrument [Member] | Other [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	11	31
Derivative Liability Fair Value Gross Liability	$ (7)	$ (20)

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Financial and Other Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2012

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, 2012 and 2011:

	December 31, 2012					December 31, 2011
	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)	$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	—	$	—		$	3	$	(5	)
Commodity Contracts:
Natural Gas	645		(661		)	2,024		(2,080		)
Electricity	360		(351		)	747		(705		)
Other	11		(7		)	31		(20		)
Total derivatives not designated as hedging instruments:	$	1,016	$	(1,019	)	$	2,805	$	(2,810	)
Total derivatives:
Current	$	862	$	(879	)	$	2,272	$	(2,282	)
Noncurrent	154		(141		)	533		(529		)
Total derivatives	$	1,016	$	(1,020	)	$	2,805	$	(2,811	)

	December 31, 2012												December 31, 2011
	Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent			Current			Noncurrent			Current			Noncurrent
	(In millions)
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	862		$	154		$	(879	)	$	(141	)	$	2,272		$	533		$	(2,282	)	$	(529	)
Counterparty netting	(754		)	(115		)	754			115			(2,050		)	(440		)	2,050			440
Collateral adjustment	—			—			—			—			—			(19		)	74			—
Total derivatives as reported	$	108		$	39		$	(125	)	$	(26	)	$	222		$	74		$	(158	)	$	(89	)

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, 2012 and 2011 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		2012			2011
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	—		$	(2	)
Commodity Contracts:
Natural Gas	Operating Revenue	(29		)	58
Natural Gas	Fuel, purchased power and gas	25			(21		)
Electricity	Operating Revenue	64			115
Other	Operating Revenue	5			9
Total		$	65		$	159

Volume of Commodity Contracts [Table Text Block]

Commodity	Number of Units
Natural Gas (MMBtu)	663,194,602
Electricity (MWh)	48,524,412
Foreign Currency Exchange ($ CAD)	10,838,396
FTR (MWh)	11,077,483

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Income Taxes

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [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:

	2012			2011			2010
	(In millions)
Income before income taxes	$	960		$	991		$	962
Income tax expense at 35% statutory rate	$	336		$	347		$	337
Production tax credits	(49		)	(6		)	(33		)
Investment tax credits	(6		)	(6		)	(6		)
Depreciation	(4		)	(4		)	(4		)
Employee Stock Ownership Plan dividends	(4		)	(4		)	(5		)
Domestic production activities deduction	(14		)	(7		)	(7		)
Settlement of Federal tax audit	—			—			(12		)
State and local income taxes, net of federal benefit	37			37			44
Enactment of Michigan Corporate Income Tax, net of federal expense	—			(87		)	—
Other, net	(10		)	(2		)	1
Income tax expense	$	286		$	268		$	315
Effective income tax rate	29.8		%	27.0		%	32.7		%

Components of income tax expense were as follows:

	2012			2011			2010
Current income tax expense (benefit)	(In millions)
Federal	$	190		$	27		$	(168	)
State and other income tax	49			21			26
Total current income taxes	239			48			(142		)
Deferred income tax expense (benefit)
Federal	39			318			415
State and other income tax	8			(98		)	42
Total deferred income taxes	47			220			457
Total income taxes from continuing operations	286			268			315
Discontinued operations	(29		)	(1		)	(4		)
Total	$	257		$	267		$	311

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:

	2012			2011
	(In millions)
Property, plant and equipment	$	(3,389	)	$	(3,131	)
Securitized regulatory assets	(256		)	(360		)
Alternative minimum tax credit carry-forwards	254			294
Merger basis differences	42			50
Pension and benefits	(33		)	(39		)
Other comprehensive income	101			99
Derivative assets and liabilities	66			64
State net operating loss and credit carry-forwards	37			30
Other	41			(45		)
	(3,137		)	(3,038		)
Less valuation allowance	(33		)	(27		)
	$	(3,170	)	$	(3,065	)
Current deferred income tax assets	$	21		$	51
Long-term deferred income tax liabilities	(3,191		)	(3,116		)
	$	(3,170	)	$	(3,065	)
Deferred income tax assets	$	1,038		$	1,048
Deferred income tax liabilities	(4,208		)	(4,113		)
	$	(3,170	)	$	(3,065	)

Production tax credits earned in prior years but not utilized totaled $254 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 $37 million and $30 million at December 31, 2012 and 2011, respectively. The state net operating loss and credit carry-forwards expire from 2013 through 2031. The Company has recorded valuation allowances at December 31, 2012 and 2011 of approximately $33 million and $27 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:

	2012			2011			2010
	(In millions)
Balance at January 1	$	48		$	28		$	81
Additions for tax positions of prior years	—			27			4
Reductions for tax positions of prior years	(2		)	(4		)	(4		)
Additions for tax positions of current year	1			1			—
Settlements	(30		)	(3		)	(53		)
Lapse of statute of limitations	(6		)	(1		)	—
Balance at December 31	$	11		$	48		$	28

The Company had $3 million and $4 million of unrecognized tax benefits at December 31, 2012 and at December 31, 2011, 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 $1 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 $1 million and $2 million at December 31, 2012 and December 31, 2011, respectively. The Company had no accrued penalties pertaining to income taxes. The Company recognized interest expense (income) related to income taxes of $(1) million, $(2) million and $1 million in 2012, 2011 and 2010, respectively.

In 2012, the Company settled a federal tax audit for the 2009 and 2010 tax years, which resulted in the recognition of $30 million of unrecognized tax benefits. The Company's federal income tax returns for 2011 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 Statements of Cash Flows.

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Long-Term Debt (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended			3 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2012 Securitization Bonds [Member]	Dec. 31, 2012 Mortgage Bonds 3 [Member]	Dec. 31, 2012 Mortgage Bonds 4 [Member]	Dec. 31, 2012 Tax-Exempt Revenue Bonds 2 [Member]	Dec. 31, 2012 Secured Medium Term Notes [Member]	Dec. 31, 2012 Senior Notes 1 [Member]	Dec. 31, 2012 Tax Exempt Revenue Bonds [Member]	Dec. 31, 2012 Tax-Exempt Revenue Bonds 1 [Member]	Dec. 31, 2012 Long-term Debt [Member]
Extinguishment of Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.42%	7.90%	8.36%	5.25%	7.06%	5.20%	3.05%	5.45%
Extinguishment of Debt, Amount	$ 639	$ 164	$ 10	$ 3	$ 56	$ 40	$ 225	$ 65	$ 64	$ 12