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

Commission file number 1-2198

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

DTE ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

Michigan	38-0478650
(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:

None

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 o No þ

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 during the preceding 12 months (or for 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 o Accelerated filer o Non-accelerated filer þ (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

All of the registrant’s 138,632,324 outstanding shares of common stock, par value $10 per share, are owned by DTE Energy Company.

DOCUMENTS INCORPORATED BY REFERENCE

None

DTE Electric 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	7
Item 1B. Unresolved Staff Comments	10
Item 3. Legal Proceedings	11
Item 4. Mine Safety Disclosures	11
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	11
Item 6. Selected Financial Data	11
Item 7. Management’s Narrative Analysis of Results of Operations	12
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	14
Item 8. Financial Statements and Supplementary Data	15
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	56
Item 9A. Controls and Procedures	56
Item 9B. Other Information	56
Part III
Item 10. Directors, Executive Officers and Corporate Governance	56
Item 11. Executive Compensation	56
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	56
Item 13. Certain Relationships and Related Transactions, and Director Independence	56
Item 14. Principal Accountant Fees and Services	56
Part IV
Item 15. Exhibits and Financial Statement Schedules	57
Signatures	65
EX-12.45
EX-23.27
EX-31.79
EX-31.80
EX-32.79
EX-32.80
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

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.
Customer Choice	Michigan legislation giving customers the option to choose alternative suppliers for electricity.
DTE Electric	DTE Electric Company (a direct wholly owned subsidiary of DTE Energy) 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 Company and numerous non-utility subsidiaries
EPA	United States Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FTRs	Financial transmission rights are financial instruments that entitle the holder to receive payments related to costs incurred for congestion on the transmission grid.
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
NRC	United States Nuclear Regulatory Commission
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 of electricity
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.
VIE	Variable Interest Entity

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Units of Measurement
kWh	Kilowatthour of electricity
MW	Megawatt of electricity
MWh	Megawatthour of electricity

2

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 Electric. 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 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 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 and purchased power;

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

• 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

DTE Electric is a Michigan corporation organized in 1903 and is a wholly-owned subsidiary of DTE Energy. DTE Electric 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.

References in this report to “we,” “us,” “our” or “Company” are to DTE Electric.

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	150		456		479
Subtotal	5,186		5,034		4,848
Interconnection sales (a)	105		118		145
Total Revenue	$	5,291	$	5,152	$	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.

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.

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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 6 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 6 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.

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.

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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, 7, 8 and 14 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 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.

ENVIRONMENTAL MATTERS

We are subject to extensive environmental regulation. We expect to continue recovering environmental costs 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.

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	(In millions)
Air	$	1,784
Water	80
Contaminated and other sites	13
Estimated total future expenditures through 2020	$	1,877
Estimated 2013 expenditures	$	336
Estimated 2014 expenditures	$	324

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, with further emission controls planned for reductions in mercury and other emissions. Further, additional rulemakings could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants over the next few years.

Water - In response to an EPA regulation, 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. DTE Electric owns, or previously owned, three former MGP sites.

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, 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.

See Notes 8 and 14 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

EMPLOYEES

We had approximately 4,800 employees as of December 31, 2012, of which approximately 2,700 were represented by unions. The majority of our union employees are under a contract that expires in June 2013.

Item 1A. Risk Factors

There are various risks associated with the operations of DTE Electric. To provide a framework to understand the operating environment of the Company, we are providing a brief explanation of the more significant risks associated with our business. 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.  Our electric rates 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. We typically self-implement base rate changes six months after rate case filings in accordance with Michigan law. However, if the

7

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 mechanisms that are intended to mitigate the risk 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. These laws and regulations require us to seek a variety of environmental licenses, permits, inspections and other regulatory approvals. We could be required to install expensive pollution control measures or limit or cease activities based on these regulations. Additionally, we may become a responsible party for environmental cleanup at sites identified by a regulatory body. We cannot predict with certainty the amount and timing of future expenditures related to environmental matters because of the difficulty of estimating clean up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on potentially responsible parties.

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

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. 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. We have hedging strategies and regulatory recovery mechanisms in place to mitigate some of the negative fluctuations in commodity supply prices, but there can be no assurances that our financial performance will not be negatively impacted by price fluctuations.

The 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

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interruptions for these commodities and other items could have a negative impact on the amounts we charge our customers for our products.

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 customers, the results of operations and financial position of our company could be negatively affected. Without sustained growth in the plan investments over time to increase the value of our plan assets, we could be required to fund our plans with significant amounts of cash. Such cash funding obligations could have a material impact on our cash flows, financial position, or results of operations.

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 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 facility does not expire until 2016, but we regularly access capital markets to refinance existing debt or fund new projects, and we cannot predict the pricing or demand for those future transactions.

Construction and capital improvements to our power facilities subject us to risk. We are managing ongoing and planning future significant construction and capital improvement projects at multiple power generation and distribution facilities. 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.

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.

Renewable portfolio standards and energy efficiency programs may affect our business.  We are subject to existing Michigan and potential future federal legislation and regulation requiring us to secure sources of renewable energy. Under the current Michigan legislation we will be required in the future to provide a specified percentage of our power from Michigan renewable energy sources. We are 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

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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 business follows the economic cycles of the customers we serve and the credit risk of counterparties we do business with. Should national or regional economic conditions deteriorate, reduced volumes of electricity, collections of accounts receivable, and reductions in federal and state energy assistance funding, and potentially higher levels of stolen 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 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 Electric 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 2,700 of our employees. The majority of our union employees are under a contract that expires in June 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.

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

Item 1B. Unresolved Staff Comments

None.

10

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 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. DTE Energy and DTE Electric cannot predict the financial impact or outcome of these matters, or the timing of its resolution.

For additional discussion on legal matters, see Notes 8 and 14 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Item 4. Mine Safety Disclosures

Not applicable.

Part II

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

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

We paid cash dividends on our common stock of $317 million in 2012 and $305 million in 2011, and 2010.

Item 6. Selected Financial Data

Omitted per General Instruction I (2) (a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

11

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

The Management’s Narrative Analysis of Results of Operations discussion for DTE Electric is presented in accordance with General Instruction I (2) (a) of Form 10-K for wholly-owned subsidiaries (reduced disclosure format).

	2012			2011		2010
	(In millions)
Operating revenues	$	5,291		$	5,152	$	4,993
Fuel and purchased power	1,758			1,716		1,580
Gross margin	3,533			3,436		3,413
Operation and maintenance	1,429			1,369		1,305
Depreciation and amortization	822			813		849
Taxes other than income	256			240		237
Asset (gains) losses and reserves, net	(2		)	12		(6		)
Operating Income	1,028			1,002		1,028
Other (Income) and Deductions	260			298		317
Income Tax Expense	282			267		270
Net Income	$	486		$	437	$	441

Gross margin increased $97 million in 2012 and increased $23 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 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			(14		)
Increase in gross margin	$	97		$	23

	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.

12

Operation and maintenance expense increased $60 million in 2012 and increased $64 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 $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 $36 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 $14 million in 2012 and increased $18 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 7 of the Notes to the Consolidated Financial Statements.

Other (income) and deductions were lower by $38 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.

Environmental Matters— 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 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 Electric or its customers at this time.

13

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Price Risk

We have commodity price risk arising from market price fluctuations. We have risks in conjunction with the anticipated purchases of coal, uranium, electricity, and base metals to meet our service obligations. However, we do not bear significant exposure to earnings risk as such changes are included in the PSCR regulatory rate-recovery mechanism. We are exposed to short-term cash flow or liquidity risk as a result of the time differential between actual cash settlements and regulatory rate recovery.

Credit Risk

Bankruptcies

We purchase and sell electricity from and to governmental entities and numerous companies operating in the steel, automotive, energy, retail and other industries. Certain of our customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We regularly review contingent matters relating to these customers and our purchase and sale contracts and we record provisions for amounts considered at risk of probable loss. We believe our accrued amounts are adequate for probable loss. The final resolution of these matters may have a material effect on our 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.

Interest Rate Risk

DTE Electric is subject to interest rate risk in connection with the issuance of debt securities. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). We estimate that if interest rates were 10% higher or lower, the fair value of long-term debt at December 31, 2012 would decrease $139 million and increase $148 million, respectively.

14

Item 8. Financial Statements and Supplementary Data

	Page
Controls and Procedures	16
Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm	17
Consolidated Statements of Operations	18
Consolidated Statements of Comprehensive Income	19
Consolidated Statements of Financial Position	20
Consolidated Statements of Cash Flows	22
Consolidated Statements of Changes in Shareholder’s Equity	23
Notes to Consolidated Financial Statements	24
Financial Statement Schedule
Schedule II — Valuation and Qualifying Accounts	64

15

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 Electric’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.

This annual report does not include an audit report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to audit by the Company’s independent registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

(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.

16

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of DTE Electric Company

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of DTE Electric Company (formerly known as The Detroit Edison 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. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Detroit, Michigan

February 20, 2013

17

DTE Electric Company

Consolidated Statements of Operations

	Year Ended December 31
	2012			2011			2010
	(In millions)
Operating Revenues	$	5,291		$	5,152		$	4,993
Operating Expenses
Fuel and purchased power	1,758			1,716			1,580
Operation and maintenance	1,429			1,369			1,305
Depreciation and amortization	822			813			849
Taxes other than income	256			240			237
Asset (gains) losses and reserves, net	(2		)	12			(6		)
	4,263			4,150			3,965
Operating Income	1,028			1,002			1,028
Other (Income) and Deductions
Interest expense	272			289			313
Interest income	(1		)	—			(1		)
Other income	(53		)	(47		)	(39		)
Other expenses	42			56			44
	260			298			317
Income Before Income Taxes	768			704			711
Income Tax Expense	282			267			270
Net Income	$	486		$	437		$	441

See Notes to Consolidated Financial Statements

18

DTE Electric Company

Consolidated Statements of Comprehensive Income

	2012			2011			2010
	(In millions)
Net income	$	486		$	437		$	441
Other comprehensive income:
Benefit obligations, net of tax of $(1), $(2) and $—	(2		)	(4		)	—
Comprehensive income	$	484		$	433		$	441

See Notes to Consolidated Financial Statements

19

DTE Electric Company

Consolidated Statements of Financial Position

	December 31
	2012			2011
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	30		$	13
Restricted cash, principally Securitization	102			127
Accounts receivable (less allowance for doubtful accounts of $35 and $80, respectively)
Customer	697			709
Affiliates	5			61
Other	63			76
Inventories
Fuel	246			264
Materials and supplies	193			183
Notes receivable
Affiliates	—			26
Other	2			2
Regulatory assets	162			272
Other	77			63
	1,577			1,796
Investments
Nuclear decommissioning trust funds	1,037			937
Other	133			121
	1,170			1,058
Property
Property, plant and equipment	17,689			16,788
Less accumulated depreciation and amortization	(6,717		)	(6,526		)
	10,972			10,262
Other Assets
Regulatory assets	3,348			3,618
Securitized regulatory assets	413			577
Intangible assets	30			36
Notes receivable	3			4
Other	138			142
	3,932			4,377
Total Assets	$	17,651		$	17,493

See Notes to Consolidated Financial Statements

20

DTE Electric Company

Consolidated Statements of Financial Position

	December 31
	2012			2011
	(In millions, except shares)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Accounts payable
Affiliates	$	52		$	67
Other	350			421
Accrued interest	61			69
Current portion long-term debt, including capital leases	443			470
Regulatory liabilities	66			80
Short-term borrowings
Affiliates	80			64
Other	130			—
Other	166			230
	1,348			1,401
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	4,221			4,105
Securitization bonds	302			479
Capital lease obligations	1			9
	4,524			4,593
Other Liabilities
Deferred income taxes	2,761			2,701
Regulatory liabilities	483			454
Asset retirement obligations	1,557			1,440
Unamortized investment tax credit	49			57
Nuclear decommissioning	159			148
Accrued pension liability — affiliates	1,368			1,231
Accrued postretirement liability — affiliates	996			1,217
Other	103			115
	7,476			7,363
Commitments and Contingencies (Notes 8 and 14)
Shareholder’s Equity
Common stock, $10 par value, 400,000,000 shares authorized, and 138,632,324 shares issued and outstanding	3,196			3,196
Retained earnings	1,129			960
Accumulated other comprehensive income (loss)	(22		)	(20		)
	4,303			4,136
Total Liabilities and Shareholder’s Equity	$	17,651		$	17,493

See Notes to Consolidated Financial Statements

21

DTE Electric Company

Consolidated Statements of Cash Flows

	Year Ended December 31
	2012			2011			2010
	(In millions)
Operating Activities
Net income	$	486		$	437		$	441
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	822			813			849
Deferred income taxes	(52		)	231			322
Asset (gains) losses and reserves, net	(2		)	13			(6		)
Changes in assets and liabilities, exclusive of changes shown separately (Note 16)	258			(141		)	(253		)
Net cash from operating activities	1,512			1,353			1,353
Investing Activities
Plant and equipment expenditures	(1,230		)	(1,202		)	(864		)
Restricted cash for debt redemption, principally Securitization	5			(3		)	(25		)
Notes receivable from affiliate	26			77			(21		)
Proceeds from sale of nuclear decommissioning trust fund assets	97			80			377
Investment in nuclear decommissioning trust funds	(102		)	(97		)	(410		)
Other	(26		)	(32		)	(60		)
Net cash used for investing activities	(1,230		)	(1,177		)	(1,003		)
Financing Activities
Issuance of long-term debt	496			609			614
Redemption of long-term debt	(587		)	(554		)	(652		)
Short-term borrowings, net	130			—			—
Short-term borrowings from affiliate	16			64			—
Dividends on common stock	(317		)	(305		)	(305		)
Other	(3		)	(7		)	(11		)
Net cash used for financing activities	(265		)	(193		)	(354		)
Net Increase (Decrease) in Cash and Cash Equivalents	17			(17		)	(4		)
Cash and Cash Equivalents at Beginning of the Period	13			30			34
Cash and Cash Equivalents at End of the Period	$	30		$	13		$	30

See Notes to Consolidated Financial Statements

22

DTE Electric Company

Consolidated Statements of Changes in Shareholder’s Equity

				Additional					Accumulated Other
	Common Stock			Paid-in		Retained			Comprehensive
	Shares	Amount		Capital		Earnings			Income (Loss)			Total
	(Dollars in millions, shares in thousands)
Balance, December 31, 2009	138,632	1,386		1,810		693			(16		)	3,873
Net income	—	—		—		441			—			441
Dividends declared on common stock	—	—		—		(305		)	—			(305		)
Balance, December 31, 2010	138,632	1,386		1,810		829			(16		)	4,009
Net income	—	—		—		437			—			437
Dividends declared on common stock	—	—		—		(306		)	—			(306		)
Benefit obligations, net of tax	—	—		—		—			(4		)	(4		)
Balance, December 31, 2011	138,632	$	1,386	$	1,810	$	960		$	(20	)	$	4,136
Net income	—	—		—		486			—			486
Dividends declared on common stock	—	—		—		(317		)	—			(317		)
Benefit obligations, net of tax	—	—		—		—			(2		)	(2		)
Balance, December 31, 2012	138,632	$	1,386	$	1,810	$	1,129		$	(22	)	$	4,303

See Notes to Consolidated Financial Statements

23

DTE Electric Company

Notes to Consolidated Financial Statements

NOTE 1 — BASIS OF PRESENTATION

Corporate Structure

DTE Electric is an electric utility engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan. DTE Electric is regulated by the MPSC and the FERC. In addition, we are regulated by other federal and state regulatory agencies including the NRC, the EPA and the MDEQ.

References in this report to “we,” “us,” “our” or “Company” are to DTE Electric 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.

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 related to Securitization is reflected on the Company’s Consolidated Statements of Financial Position.

The following table summarizes the major balance sheet items at December 31, 2012 and 2011 restricted for Securitization that are either (1) assets that can be used only to settle their obligations or (2) liabilities for which creditors do not have recourse to the general credit of the primary beneficiary.

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	December 31,		December 31,
	2012		2011
	(In millions)
ASSETS
Restricted cash	$	102	$	107
Accounts receivable	34		34
Securitized regulatory assets	413		577
Other assets	7		10
	$	556	$	728
LIABILITIES
Accounts payable and accrued current liabilities	$	11	$	14
Other current liabilities	50		55
Current portion long-term debt, including capital leases	177		164
Securitization bonds	302		479
Other long term liabilities	7		7
	$	547	$	719

As of December 31, 2012 and December 31, 2011, DTE Electric had $3 million and $4 million in Notes receivable, related to non-consolidated VIEs, respectively.

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

Revenues

Revenues from the sale and delivery of electricity are recognized as services are provided. The Company records revenues for electricity provided but unbilled at the end of each month. Rates for DTE Electric include provisions to adjust billings for fluctuations in fuel and purchased power costs, 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 8 for further discussion of recovery mechanisms authorized by the MPSC.

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 and purchased power and net sales in Operating revenues on the Consolidated Statements of Operations. DTE Electric records net sale billing adjustments when invoices are received. DTE Electric records expense accruals for future net purchases adjustments based on historical experience, and reconciles accruals to actual expenses when invoices are received from MISO.

Comprehensive Income

Comprehensive income is the change in common shareholder’s 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 reflected changes in benefit obligations.

	Benefit			Accumulated Other Comprehensive
	Obligations			Loss
	(In millions)
Beginning balance January 1, 2012	$	(20	)	$	(20	)
Current period change	(2		)	(2		)
Ending balance December 31, 2012	$	(22	)	$	(22	)

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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 agreements, related to Securitization bonds. 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 is generally calculated using the aging approach that utilizes rates developed in reserve studies. DTE Electric establishes 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.

Unbilled revenues of $275 million and $264 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 loans and 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.

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

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

Utility property is depreciated over its estimated useful life using straight-line rates approved by the MPSC.

Depreciation 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 8.

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

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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 and renewable energy credits. 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’s intangible assets related to emission allowances were $6 million at December 31, 2012 and $9 million at December 31, 2011. The Company’s intangible assets related to renewable energy credits were $44 million and $39 million at December 31, 2012 and December 31, 2011, respectively.

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, the unamortized discount, premium and expense related to debt redeemed with a refinancing are amortized over the life of the replacement issue.

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.

Stock-Based Compensation

The Company received an allocation of costs from DTE Energy associated with stock-based compensation. Our allocation for 2012, 2011 and 2010 for stock-based compensation expense was approximately $42 million, $30 million and $23 million, respectively.

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.

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Other Accounting Policies

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

Note	Title
3	Fair Value
4	Financial and Other Derivative Instruments
7	Asset Retirement Obligations
8	Regulatory Matters
9	Income Taxes
15	Retirement Benefits and Trusteed Assets

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.

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The following table presents assets 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		Net Balance		Level 1		Level 2		Level 3		Net Balance
	(In millions)
Assets:
Cash equivalents (a)	$	—	$	116	$	—	$	116	$	—	$	129	$	—	$	129
Nuclear decommissioning trusts	694		343		—		1,037		577		360		—		937
Other investments (b)	64		44		—		108		55		38		—		93
Derivative assets — FTRs	—		—		1		1		—		—		1		1
Total	$	758	$	503	$	1	$	1,262	$	632	$	527	$	1	$	1,160
Assets:
Current	$	—	$	116	$	1	$	117	$	—	$	129	$	1	$	130
Noncurrent	758		387		—		1,145		632		398		—		1,030
Total Assets	$	758	$	503	$	1	$	1,262	$	632	$	527	$	1	$	1,160

_______________________________________

(a) At December 31, 2012 available for sale securities of $116 million, included $102 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 $129 million, included $113 million and $16 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively.

(b) Available for sale equity securities at December 31, 2012 and December 31, 2011 of $5 million and $4 million are included in Other investments on the Consolidated Statements of Financial Position, respectively.

The following table presents 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			2011
	(In millions)
Net Assets as of January 1	$	1		2
Change in fair value recorded in regulatory assets/liabilities	15			2
Purchases, issuances and settlements:
Settlements	(15		)	(3		)
Net Assets as of December 31	$	1		$	1
The amount of total gains (losses) included in regulatory assets and liabilities attributed to the change in unrealized gains (losses) related to regulatory assets and liabilities held at December 31, 2012 and 2011	$	1		$	1

No transfers between Levels 1, 2 or 3 occurred in the years ended December 31, 2012 and December 31, 2011.

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. The Company has obtained an understanding of how these

29

prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, the Company 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. The Company 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. The Company 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. The Company has obtained an understanding of how these prices are derived. Additionally, the Company selectively corroborates the fair value of its transactions by comparison of market-based price sources. Mathematical valuation models are used for derivatives for which external market data is not readily observable, such as contracts which extend beyond the actively traded reporting period.

Fair Value of Financial Instruments

The fair value of 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. The Company has obtained an understanding of how the fair values are derived. The Company 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 as 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 the Company'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 December 31, 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	$	5	$	—	$	—	$	5	$	6	$	6
Notes receivable — affiliates	—		—		—		—		26		26
Short-term borrowings — affiliates	80		—		—		80		64		64
Short-term borrowings — other	130		—		130		—		—		—
Long-term debt	4,963		—		5,021		620		5,051		5,740

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 7.

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

	December 31		December 31
	2012		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		Unrealized		Fair		Unrealized
	Value		Gains		Value		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, 2011 no 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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NOTE 4 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

The Company recognizes all derivatives at their fair value 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 fair value are recognized in earnings each period.

The Company's primary market risk exposure is associated with commodity prices, credit and interest rates. The Company has risk management policies to monitor and manage market risks. The Company uses derivative instruments to manage some of the exposure. 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.

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

	December 31
	2012		2011
	(In millions)
FTRs — Other current assets	$	1	$	1
Total derivatives not designated as hedging instrument	$	1	$	1

The effect of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position were $15 million in gains related to FTRs recognized in Regulatory liabilities for the year ended December 31, 2012, and $3 million in 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
FTRs (MWh)	49,411

NOTE 5 — PROPERTY, PLANT AND EQUIPMENT

Summary of property by classification as of December 31:

	2012			2011
Property, Plant and Equipment	(In millions)
Generation	$	10,383		$	9,785
Distribution	7,306			7,003
Total	17,689			16,788
Less Accumulated Depreciation and Amortization
Generation	(3,880		)	(3,946		)
Distribution	(2,837		)	(2,580		)
Total	(6,717		)	(6,526		)
Net Property, Plant and Equipment	$	10,972		$	10,262

The Allowance for Funds used During Construction (AFUDC) capitalized during 2012 and 2011 was approximately $19 million and $9 million, respectively.

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

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The average estimated useful life for our generation and distribution property was 40 years and 41 years, respectively, at December 31, 2012.

Capitalized software costs are classified as Property, plant and equipment and the related amortization is included in Accumulated depreciation 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 5 to 15 years.

Capitalized software costs amortization expense was $62 million in 2012, $58 million in 2011 and $55 million in 2010. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2012 were $479 million and $245 million, respectively. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2011 were $501 million and $218 million, respectively. Amortization expense of capitalized software costs is estimated to be approximately $40 million annually for 2013 through 2017.

Gross property under capital leases was $6 million and $26 million at December 31, 2012 and December 31, 2011, respectively. Accumulated amortization of property under capital leases was $3 million and $14 million at December 31, 2012 and December 31, 2011, respectively.

NOTE 6 — 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 and purchased power 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:

				Ludington Hydroelectric
	Belle River			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.

NOTE 7 — 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 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.

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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. 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 January 1, 2012	$	1,442
Accretion	91
Revision in estimated cash flows	2
Liabilities incurred	26
Liabilities settled	(4		)
Asset retirement obligations at December 31, 2012	$	1,557

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.

NOTE 8 — REGULATORY MATTERS

Regulation

DTE Electric is 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.

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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 is 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
Assets	(In millions)
Recoverable pension and postretirement costs:
Pension	$	1,815		$	1,656
Postretirement costs	316			582
Asset retirement obligation	424			420
Recoverable Michigan income taxes	253			270
Recoverable income taxes related to securitized regulatory assets	226			316
Accrued PSCR revenue	87			147
Cost to achieve Performance Excellence Process	82			100
Other recoverable income taxes	76			81
Choice incentive mechanism	66			166
Recoverable restoration expense	49			58
Unamortized loss on reacquired debt	37			36
Enterprise Business Systems costs	16			18
Other	63			40
	3,510			3,890
Less amount included in current assets	(162		)	(272		)
	$	3,348		$	3,618
Securitized regulatory assets	$	413		$	577
Liabilities
Renewable energy	$	230		$	192
Refundable revenue decoupling / deferred gain	127			127
Asset removal costs	81			73
Over recovery of Securitization	54			53
Energy Optimization	26			24
Fermi 2 refueling outage	12			23
Refundable uncollectible expense	10			13
Low Income Energy Efficiency Fund	—			23
Other	9			6
	549			534
Less amount included in current liabilities	(66		)	(80		)
	$	483		$	454

As noted below, regulatory assets for which costs have been incurred have been included (or are expected to be included, for costs incurred subsequent to the most recently approved rate case) in DTE Electric'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.

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ASSETS

• Recoverable pension and postretirement costs — Accounting rules for pension and 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. The Company records the impact of actuarial gains and losses and prior service 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 MBT was enacted by the State of Michigan. A State deferred tax liability was established, and an offsetting regulatory asset was recorded as the impact of the deferred tax liability will be reflected in rates as the related taxable temporary difference reverses and flows through current income tax expense. In May 2011, the MBT was repealed and the 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)

• Accrued PSCR 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.

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

• Other recoverable income taxes — Income taxes receivable from DTE Electric 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) — 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.

• 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 MPSC authorization. The restoration expense tracking mechanism 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.

• 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

• 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.

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

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

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

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

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

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

2009 Electric Rate Case Filing - Court of Appeals Decision

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 Court 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 case. 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 filed an application for approval of its reconciliation of its 2011 EO plan expenses. On October 31, 2012, the MPSC approved DTE Electric's reconciliation. The MPSC order also approved performance incentive surcharges for DTE Electric of $8.4 million to be applied to customer bills rendered on and after January 1, 2013.

In August 2012, DTE Electric filed an amended EO plan with the MPSC. The plan application proposed the recovery of EO expenditures for the period 2013-2015 of $224 million and further requested approval of a surcharge to recover these costs. On December 20, 2012, the MPSC approved DTE Electric's EO plan.

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.

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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 4.74mills/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.

NOTE 9 — INCOME TAXES

Income Tax Summary

We are part of the consolidated federal income tax return of DTE Energy. The federal income tax expense for DTE Electric is determined on an individual company basis with no allocation of tax expenses or benefits from other affiliates of DTE Energy. We had an income tax payable to DTE Energy of $13 million at December 31, 2012 and we had an income tax receivable from DTE Energy of $48 million at December 31, 2011.

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	$	768		$	704		$	711
Income tax expense at 35% statutory rate	$	269		$	246		$	249
Investment tax credits	(6		)	(6		)	(6		)
Depreciation	3			3			3
Employee Stock Ownership Plan dividends	(3		)	(3		)	(3		)
Domestic production activities deduction	(16		)	(6		)	(6		)
State and other income taxes, net of federal benefit	40			39			40
Other, net	(5		)	(6		)	(7		)
Income Tax Expense	$	282		$	267		$	270
Effective income tax rate	36.7		%	38.0		%	38.0		%

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Components of income tax expense (benefits) were as follows:

	2012			2011		2010
Current income tax expense (benefit)	(In millions)
Federal	$	267		$	15	$	(89	)
State and other income tax	67			21		37
Total current income taxes	334			36		(52		)
Deferred income tax expense (benefit)
Federal	(47		)	193		297
State and other income tax	(5		)	38		25
Total deferred income taxes	(52		)	231		322
Total	$	282		$	267	$	270

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	$	(2,578	)	$	(2,285	)
Securitized regulatory assets	(261		)	(384		)
Pension and benefits	73			67
Other comprehensive income	15			15
Other, net	(24		)	(182		)
	$	(2,775	)	$	(2,769	)
Current deferred income tax liability (included in Current Liabilities — Other)	$	(14	)	$	(68	)
Long-term deferred income tax liabilities	$	(2,761	)	$	(2,701	)
	$	(2,775	)	$	(2,769	)
Deferred income tax assets	$	557		$	608
Deferred income tax liabilities	(3,332		)	(3,377		)
	$	(2,775	)	$	(2,769	)

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.

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	$	59		$	18		$	96
Additions for tax positions of prior years	—			45			1
Reductions for tax positions of prior years	(3		)	(5		)	—
Additions for tax positions of current year	—			1			6
Settlements	(52		)	—			(85		)
Balance at December 31	$	4		$	59		$	18

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 our effective tax rate. The Company does not anticipate any material decrease in unrecognized tax benefits in the next 12 months.

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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 $(3) million, $1 million and $1 million in 2012, 2011 and 2010, respectively.

In 2012, DTE Energy and its subsidiaries settled a federal tax audit for the 2009 and 2010 tax years, which resulted in the recognition of $52 million of unrecognized tax benefits by Detroit Edison. The Company's federal income tax returns for years 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 is 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 Michigan Corporate Income Tax was enacted effective January 1, 2012. The new 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 old 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 new 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 $30 million 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 net deferred tax assets of $342 million. The $342 million decrease in deferred tax assets was offset against the regulatory liabilities established upon enactment of the MBT.

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

NOTE 10 — 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
Taxable Debt, Principally Secured	(In millions)
5.0% due 2013 to 2042	$	3,777		$	3,515
Tax- Exempt Revenue Bonds (b)
5.3% due 2014 to 2038	707			893
	4,484			4,408
Less amount due within one year	(263		)	(303		)
	$	4,221		$	4,105
Securitization Bonds
6.6% due 2013 to 2015	$	479		$	643
Less amount due within one year	(177		)	(164		)
	$	302		$	479

_________________________________

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

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

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Debt Issuances

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

Month	Type	Interest Rate		Maturity	Amount
					(In millions)
June	Mortgage Bonds (a)	2.65	%	2022	$	250
June	Mortgage Bonds (a)	3.95	%	2042	250
					$	500

_____________________________

(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.

Debt Redemptions

In 2012, the following debt was redeemed:

Month	Type	Interest Rate	Maturity	Amount
				(In millions)
March/September	Securitization Bonds	6.42%	2012	$	164
April	Mortgage Bonds	7.90%	2012	10
April	Mortgage Bonds	8.36%	2012	3
July	Senior Notes	5.20%	2012	225
December	Tax Exempt Bonds	3.05%	2024	65
December	Tax Exempt Bonds	5.45%	2032	64
December	Tax Exempt Bonds	5.25%	2032	56
				$	587

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

											2018 &
	2013		2014		2015		2016		2017		thereafter		Total
	(In millions)
Amount to mature	$	440	$	500	$	315	$	151	$	—	$	3,565	$	4,971

Cross Default Provisions

Substantially all of the net properties of DTE Electric are subject to the lien of its mortgage. Should DTE Electric fail to timely pay its indebtedness under this mortgage, such failure may create cross defaults in the indebtedness of DTE Energy.

NOTE 11 — PREFERRED AND PREFERENCE SECURITIES

At December 31, 2012, DTE Electric had approximately 6.75 million shares of preferred stock with a par value of $100 per share and 30 million shares of preference stock with a par value of $1 per share authorized, with no shares issued.

NOTE 12 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

DTE Electric has a $300 million unsecured revolving credit agreement with a syndicate of 20 banks that may be used for general corporate borrowings, but is intended to provide liquidity support for the Company's commercial paper program. No one bank provides more than 8.5% of the commitment in the facility. Borrowings under the facility are available at prevailing short-term interest rates. The facility will expire in October 2016. At December 31, 2012, there was $130 million outstanding against this facility, while there were no amounts outstanding against this facility at December 31, 2011.

The agreement requires 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 consolidatedsubsidiaries, including capital lease obligations, hedge agreements and guarantees of third parties' debt, but excluding contingent obligations and nonrecourse and junior subordinated 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 ratio for DTE Electric was 0.52 to 1.

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The weighted average interest rate for short-term borrowings was 0.4% at December 31, 2012.

NOTE 13 — CAPITAL AND OPERATING LEASES

The Company leases various assets under capital and operating leases, including coal railcars, computers, vehicles and other equipment. The lease arrangements expire at various dates through 2023.

Future minimum lease payments under non-cancelable leases at December 31, 2012 were:

	Capital			Operating
	Leases			Leases
	(In millions)
2013	$	3		$	26
2014	1			21
2015	—			18
2016	—			16
2017	—			16
Thereafter	—			66
Total minimum lease payments	4			$	163
Less imputed interest	—
Present value of net minimum lease payments	4
Less current portion	(3		)
Non-current portion	$	1

Rental expense for operating leases was $29 million in 2012, $27 million in 2011, and $22 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.

NOTE 14 — COMMITMENTS AND CONTINGENCIES

Environmental

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

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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.

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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 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 Electric 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. The state implementation plan process is in the preliminary stage and any required emission reductions for DTE Electric 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 three-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.

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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.

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.

Labor Contracts

We had approximately 4,800 employees as of December 31, 2012, of which approximately 2,700 were represented by unions. The majority of our union employees are under a contract that expires in June 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. The Company estimates that these commitments will be approximately $0.8 billion from 2013 through 2028 as detailed in the following table:

	(In millions)
2013	$	475
2014	277
2015	88
2016	2
2017	2
2018 - 2028	4
	$	848

The Company also estimates that 2013 capital expenditures will be approximately $1.6 billion. The Company has made certain commitments in connection with expected capital expenditures.

Bankruptcies

The Company purchases and sells electricity from and to governmental entities and numerous companies operating in the steel, automotive, energy, retail 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.

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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 Note 8 for a discussion of contingencies related to Regulatory Matters.

NOTE 15 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

Pension Plan Benefits

DTE Electric participates in various plans that provide pension and other postretirement benefits for DTE Energy and its affiliates. The plans are sponsored by DTE Energy Corporate Services, LLC (LLC), a subsidiary of DTE Energy. DTE Electric is allocated net periodic benefit costs for its share of the amounts of the combined 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. At the discretion of management, and depending upon financial market conditions, we anticipate making up to a $275 million contribution to the pension plans in 2013.

Net pension cost includes the following components:

	2012			2011			2010
	(In millions)
Service cost	$	64		$	55		$	52
Interest cost	155			154			153
Expected return on plan assets	(166		)	(168		)	(171		)
Amortization of:
Net loss	124			99			70
Prior service cost	1			4			5
Settlements	2			2			—
Net pension cost	$	180		$	146		$	109

	2012			2011
	(In millions)
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income
Net actuarial loss	$	289		$	437
Amortization of net actuarial loss	(125		)	(99		)
Amortization of prior service cost	(1		)	(4		)
Total recognized in Regulatory assets and Other comprehensive income	$	163		$	334
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	343		$	480
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	$	143		$	120
Prior service cost	$	1		$	1

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The following table reconciles the obligations, assets and funded status of the plan as well as the amount 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	$	3,307		$	2,963
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	3,196		$	2,899
Service cost	64			55
Interest cost	155			154
Actuarial loss	342			251
Settlements	2			2
Benefits paid	(174		)	(165		)
Projected benefit obligation, end of year	$	3,585		$	3,196
Change in plan assets
Plan assets at fair value, beginning of year	$	1,957		$	1,936
Actual return on plan assets	220			(18		)
Company contributions	208			204
Benefits paid	(174		)	(165		)
Plan assets at fair value, end of year	$	2,211		$	1,957
Funded status of the plan	$	(1,374	)	$	(1,239	)
Amount recorded as:
Current liabilities	$	(6	)	$	(8	)
Noncurrent liabilities	(1,368		)	(1,231		)
	$	(1,374	)	$	(1,239	)
Amounts recognized in Regulatory assets (see Note 8)
Net actuarial loss	$	1,805		$	1,645
Prior service cost	10			11
	$	1,815		$	1,656

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	$	182
2014	187
2015	193
2016	200
2017	208
2018 - 2022	1,145
Total	$	2,115

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

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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 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 December 31, 2011 (a):

	December 31, 2012								December 31, 2011
(in Millions)	Level 1		Level 2		Level 3		Net Balance		Level 1		Level 2		Level 3		Net Balance
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	16	$	—	$	16	$	—	$	23	$	—	$	23
Equity securities
U.S. Large Cap (c)	478		31		—		509		440		27		—		467
U.S. Small/Mid Cap (d)	108		3		—		111		110		4		—		114
Non U.S. (e)	372		85		—		457		272		79		—		351
Fixed income securities (f)	61		491		—		552		61		448		—		509
Hedge Funds and Similar Investments (g)	147		56		238		441		132		40		205		377
Private Equity and Other (h)	—		—		125		125		—		—		116		116
Total	$	1,166	$	682	$	363	$	2,211	$	1,015	$	621	$	321	$	1,957

_______________________________________

(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.

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(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 Electric 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 Electric 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			Private Equity						Hedge Funds and Similar			Private Equity
	Investments			and Other			Total			Investments			and Other			Total
	(In millions)
Beginning Balance	$	205		$	116		$	321		$	206		$	118		324
Total realized/unrealized gains (losses):
Realized gains (losses)	13			(4		)	9			(3		)	4			1
Unrealized gains (losses)	(3		)	8			5			1			(21		)	(20		)
Purchases, sales and settlements:
Purchases	176			23			199			44			16			60
Sales	(153		)	(18		)	(171		)	(43		)	(1		)	(44		)
Ending Balance	$	238		$	125		$	363		$	205		$	116		$	321
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	$	11		$	4		$	15		$	3		$	(20	)	$	(17	)

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 credit service. The cost of these plans was $19 million, $18 million, and $17 million in each of the years ended 2012, 2011, and 2010, respectively.

Other Postretirement Benefits

The Company participates in plans sponsored by LLC that provide 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 our postretirement benefit obligations. Separate qualified Voluntary Employees Beneficiary Association (VEBA) trusts exist for represented and non-represented employees.

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

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employees hired after September 24, 2012 will receive a $4,000per 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 $120 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	$	51		$	49		$	47
Interest cost	91			91			95
Expected return on plan assets	(61		)	(62		)	(52		)
Amortization of:
Net loss	58			40			38
Prior service costs (credit)	(16		)	(15		)	2
Net transition asset	2			2			2
Net postretirement cost	$	125		$	105		$	132

	2012			2011
	(In millions)
Other changes in plan assets and APBO recognized in Regulatory assets
Net actuarial loss (gain)	$	(14	)	$	139
Amortization of net actuarial loss	(58		)	(40		)
Prior service cost (credit)	(207		)	(3		)
Amortization of prior service credit	16			15
Amortization of transition asset	(2		)	(2		)
Total recognized in Regulatory assets	$	(265	)	$	109
Total recognized in net periodic pension cost and Regulatory assets	$	(140	)	$	214
Estimated amounts to be amortized from Regulatory assets into net periodic benefit cost during next fiscal year
Net actuarial loss	$	50		$	55
Prior service credit	$	(69	)	$	(16	)
Net transition obligation	$	—		$	2

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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
Change in accumulated postretirement benefit obligation	(In millions)
Accumulated postretirement benefit obligation, beginning of year	$	1,868		$	1,742
Service cost	51			49
Interest cost	91			91
Plan amendments	(207		)	(3		)
Actuarial loss	12			60
Medicare Part D subsidy	5			4
Benefits paid	(68		)	(75		)
Accumulated postretirement benefit obligation, end of year	$	1,752		$	1,868
Change in plan assets
Plan assets at fair value, beginning of year	$	651		$	682
Actual return on plan assets	88			(17		)
Company contributions	95			66
Benefits paid	(78		)	(80		)
Plan assets at fair value, end of year	$	756		$	651
Funded status, end of year	$	(996	)	$	(1,217	)
Amount recorded as:
Non-current liabilities	$	(996	)	$	(1,217	)
Amounts recognized in Regulatory assets (see Note 8)
Net actuarial loss	$	560		$	633
Prior service cost	(244		)	(53		)
Net transition obligation	—			2
	$	316		$	582

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	$	78
2014	82
2015	87
2016	91
2017	97
2018-2022	556
	$	991

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 $21 million and increased the accumulated benefit obligation by $218 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 $13 million and would have decreased the accumulated benefit obligation by $185 million at December 31, 2012.

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The process used in determining the long-term rate of return for assets and the investment approach for the 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. 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 December 31, 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	$	1	$	—	$	2	$	1	$	8	$	—	$	9
Equity securities
U.S. Large Cap (c)	122		2		—		124		116		10		—		126
U.S. Small/Mid Cap (d)	70		—		—		70		46		4		—		50
Non U.S. (e)	151		4		—		155		116		10		—		126
Fixed income securities (f)	25		162		—		187		15		156		—		171
Hedge Funds and Similar Investments (g)	68		15		78		161		53		14		63		130
Private Equity and Other (h)	—		—		57		57		—		—		39		39
Total	$	437	$	184	$	135	$	756	$	347	$	202	$	102	$	651

_______________________________________

(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 Electric 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 Electric selectively corroborates the fair values of securities by comparison of market-based price sources.

52

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	$	63		$	39		$	102		$	52		$	36		$	88
Total realized/unrealized gains (losses):
Realized gains (losses)	4			(7		)	(3		)	(1		)	1			—
Unrealized gains (losses)	—			9			9			2			(14		)	(12		)
Purchases, sales and settlements:
Purchases	56			25			81			45			31			76
Sales	(45		)	(9		)	(54		)	(35		)	(15		)	(50		)
Ending Balance	$	78		$	57		$	135		$	63		$	39		$	102
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	4		$	1		$	5		$	3		$	(11	)	$	(8	)

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 $4 million in 2012, $5 million in 2011 and $5 million in 2010.

NOTE 16 — 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
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately	(In millions)
Accounts receivable, net	$	24		$	(62	)	$	—
Inventories	7			(53		)	(71		)
Recoverable pension and postretirement costs	106			(436		)	(26		)
Accrued pension liability — affiliates	137			271			(27		)
Accounts payable	(64		)	41			47
Income taxes payable/receivable	114			54			(77		)
Accrued postretirement liability — affiliates	(221		)	157			3
Regulatory assets	125			(18		)	(77		)
Other assets	108			(80		)	(54		)
Other liabilities	(78		)	(15		)	29
	$	258		$	(141	)	$	(253	)

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

	2012		2011			2010
Cash paid (received) for:	(In millions)
Interest (excluding interest capitalized)	$	280	$	294		$	315
Income taxes	223		(18		)	28

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

	2012			2011		2010
	(In millions)
Change in capital expenditures not paid	$	(22	)	$	47	$	27

NOTE 17 — RELATED PARTY TRANSACTIONS

The Company has agreements with affiliated companies to sell energy for resale, purchase power, provide fuel supply services, and provide power plant operation and maintenance services. The Company has agreements with certain DTE Energy affiliates where we charge them for their use of the shared capital assets of the Company. A shared services company accumulates various corporate support services expenses and charges various subsidiaries of DTE Energy, including DTE Electric. DTE Electric records federal, state and local income taxes payable to or receivable from DTE Energy based on its federal, state and local tax provisions.

The following is a summary of transactions with affiliated companies:

	2012		2011		2010
Revenues	(In millions)
Energy sales	$	2	$	1	$	1
Other services	11		4		7
Shared capital assets	26		30		29
Costs
Fuel and power purchases	5		1		4
Other services and interest	1		2		2
Corporate expenses (net)	322		304		294
Other
Dividends declared	317		305		305
Dividends paid	317		305		305

	December 31
	2012		2011
Assets	(In millions)
Accounts receivable	$	5	$	61
Income taxes receivable (included in other current assets)	—		48
Notes receivable	—		26
Liabilities
Accounts payable	52		67
Short-term borrowing	80		64
Income taxes payable (included in other current liabilities)	13
Accrued pension liability	1,368		1,231
Accrued postretirement liability	996		1,217

Our accounts receivable from affiliated companies and accounts payable to affiliated companies are payable upon demand and are generally settled in cash within a monthly business cycle.

Charitable contributions to the DTE Energy Foundation were approximately $21 million and $13 million for the years ended December 31, 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 Electric.

54

NOTE 18 — SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
									Year
2012	(In millions)
Operating Revenues	$	1,198	$	1,289	$	1,542	$	1,262	$	5,291
Operating Income (a)	213		265		378		172		1,028
Net Income	97		127		195		67		486
2011
Operating Revenues	1,192		1,240		1,517		1,203		5,152
Operating Income	205		235		335		227		1,002
Net Income	85		104		158		90		437

_______________________________________

(a) In the fourth quarter of 2012, the Company recorded an adjustment that decreased operating income by $9 million ($5 million after tax) to correct other postretirement benefit expenses reported in prior periods. This adjustment is not considered material to the operating results of any of the relevant periods.

55

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

None.

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

All omitted per General Instruction I (2) (c) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Item 14. Principal Accountant Fees and Services

For the years ended December 31, 2012 and December 31, 2011 professional services were performed by PricewaterhouseCoopers LLP (PwC). The following table presents fees for professional services rendered by PwC for the audit of DTE Electric’s annual financial statements for the years ended December 31, 2012 and December 31, 2011, respectively, and fees billed for other services rendered by PwC during those periods.

	2012		2011
Audit fees (a)	$	1,248,808	$	1,144,625
Audit-related fees (b)	39,000		36,250
All other fees (c)	375,000		210,000
Total	$	1,662,808	$	1,390,875

_______________________________________

(a) Represents the aggregate fees for the audits of DTE Electric’s annual financial statements included in the Annual Reports on Form 10-K and for the reviews of the financial statements included in the Quarterly Reports on Form 10-Q.

(b) Represents the aggregate fees billed for audit-related services for various attest services.

(c) Represents consulting services for the purpose of providing advice and recommendations.

The above listed fees were pre-approved by the DTE Energy Audit Committee. Prior to engagement, the DTE Energy Audit Committee pre-approves these services by category of service. The DTE Energy Audit Committee may delegate to the chair of the Audit Committee, or to one or more other designated members of the Audit Committee, the authority to grant pre-approvals of all permitted services or classes of these permitted services to be provided by the independent auditor up to but not exceeding a pre-defined limit. The decision of the designated member to pre-approve a permitted service will be reported to the DTE Energy Audit Committee at the next scheduled meeting.

56

Part IV

Item 15. Exhibits and Financial Statement Schedules

(a) The following documents are filed as part of this Annual Report on Form 10-K.

(1) Consolidated financial statements. See “Item 8 — Financial Statements and Supplementary Data.”

(2) Financial statement schedule. See “Item 8 — Financial Statements and Supplementary Data.”

(3) Exhibits.

(i)Exhibits filed herewith.

12-45	Computation of Ratio of Earnings to Fixed Charges.
23-27	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.

(ii)Exhibits incorporated herein by reference.

	Certain exhibits listed below refer to "The Detroit Edison Company" and were effective prior to the change to DTE Electric Company effective January 1, 2013.
3(a)	Articles of Incorporation of DTE Electric Company, as amended effective January 1, 2013. (Exhibit 3-1 to Form 8-K filed January 2, 2013).
3(b)	Bylaws of The Detroit Edison Company, as amended through September 22, 1999. (Exhibit 3-14 to Form 10-Q for the quarter ended September 30, 1999).
4(a)	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 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 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 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 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 Registration Statement on Form S-1 (File No. 2-9226)). (amendment)

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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 Form 8-K dated September 11, 1957). (amendment)

Supplemental Indenture, dated as of December 1, 1966, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 2-B-32 to 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 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 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 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 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 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 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 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 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 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 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 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 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 Form 8-K dated September 29, 2005). (2005 Series C)

58

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 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 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 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 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 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 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 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 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 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 Form 10-Q for the quarter ended September 30, 2010). (2010 Series A)

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

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

Supplemental Indenture, dated as of May 15, 2011, 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 4-275 to Form 10-Q for the quarter ended June 30, 2011). (2011 Series B)

Supplemental Indenture, dated as of August 1, 2011, 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 4-276 to Form 10-Q for the quarter ended September 30, 2011). (2011 Series GT)

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

Supplemental Indenture, dated as of September 1, 2011, to Mortgage and Deed to 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 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 Form 10-Q for the quarter ended June 30, 2012). (2012 Series A and B)

59

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 Registration Statement on Form S-3 (File No. 33-50325)) and indentures supplemental thereto, dated as of the 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 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 Form 10-Q for the quarter ended September 30, 2003). (5 1/2% 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 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 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 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 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 Form 10-Q for the quarter ended September 30, 2005). (2005 Series E 5.70% Senior Notes due 2037)

60

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 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 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 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 Form 10-Q for the quarter ended June 30, 2009)

Twenty-Fifth Supplemental Indenture, dated as of June 1, 2008, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-256 to 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 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 Form 10-Q for the quarter ended June 30, 2009)

61

	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 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. (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 by and between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee. (Exhibit 4-270 to 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, 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 4-272 to Form 10-Q for the quarter ended September 30, 2010.) (2010 Series A 4.89% Senior Notes due 2020)
10(a)	Securitization Property Sales Agreement dated as of March 9, 2001, between The Detroit Edison Securitization Funding LLC and The Detroit Edison Company. (Exhibit 10-42 to Form 10-Q for the quarter ended March 31, 2001).
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 Form 10-K for 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)	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(e)	Form of Amended and Restated Five-Year Credit Agreement, dated as of August 20, 2010 and amended and restated as of October 21, 2011, by and among The Detroit Edison Company, 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 Form 8-K dated October 21, 2011).
99(a)	Belle River Participation Agreement, dated as of December 1, 1982, between The Detroit Edison Company and Michigan Public Power Agency. (Exhibit 28-5 to Registration Statement No. 2-81501).
99(b)	Belle River Transmission Ownership and Operating Agreement, dated as of December 1, 1982, between The Detroit Edison Company and Michigan Public Power Agency. (Exhibit 28-6 to Registration Statement No. 2-81501).

62

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.
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

63

DTE Electric Company

Schedule II — Valuation and Qualifying Accounts

	Year Ended December 31
	2012			2011			2010
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statements of Financial Position)	(In millions)
Balance at Beginning of Period	$	80		$	93		$	118
Additions:
Charged to costs and expenses	40			47			57
Charged to other accounts (a)	7			8			8
Deductions (b)	(92		)	(68		)	(90		)
Balance At End of Period	$	35		$	80		$	93

_______________________________________

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

64

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 ELECTRIC COMPANY (Registrant)
Date:	February 20, 2013	By	/s/ GERARD M. ANDERSON
			Gerard M. Anderson
			Chairman of the Board and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

By	/s/ GERARD M. ANDERSON	By	/s/ DAVID E. MEADOR
	Gerard M. Anderson		David E. Meador
	Chairman of the Board and		Director, Executive Vice President and Chief
	Chief Executive Officer		Financial Officer
	(Principal Executive Officer)		(Principal Financial Officer)
By	/s/ DONNA M. ENGLAND	By	/s/ LISA A. MUSCHONG
	Donna M. England		Lisa A. Muschong
	Chief Accounting Officer		Director
	(Principal Accounting Officer)
By	/s/ BRUCE D. PETERSON
	Bruce D. Peterson
	Director

Date: February 20, 2013

Supplemental Information to be Furnished With Reports Filed Pursuant to Section 15(d) of the Securities Exchange Act of 1934 by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Securities Exchange Act of 1934.

No annual report, proxy statement, form of proxy or other proxy soliciting material has been sent to security holders of DTE Electric Company during the period covered by this Annual Report on Form 10-K for the fiscal year ended December 31, 2012.

65

EX-12.45

Exhibit 12-45

THE DTE ELECTRIC 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	761	702	707	604	517
Fixed Charges	286	310	328	348	324
Net earnings	1,047	1,012	1,035	952	841
Fixed Charges:
Interest expense	269	287	310	325	293
Adjustments	17	23	18	23	31
Fixed Charges	286	310	328	348	324
Ratio of earnings to fixed charges	3.66	3.26	3.16	2.74	2.60

EX-23.27

Exhibit 23-27

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S‑3 (No. 333-183442-01) of DTE Electric Company (formerly known as The Detroit Edison Company) of our reportdated February 20, 2013 relating to the financial statements and financial statement schedule, 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 Electric 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 and Chief Executive Officer of DTE Electric 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 Electric 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 Electric 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 Electric 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 and Chief Executive Officer of DTE Electric 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 Electric 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 Electric 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

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies [Abstract]

Long-term Purchase Commitment [Table Text Block]

The Company estimates that these commitments will be approximately $0.8 billion from 2013 through 2028 as detailed in the following table:

	(In millions)
2013	$	475
2014	277
2015	88
2016	2
2017	2
2018 - 2028	4
	$	848

XML

Fair Value (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Cash Equivalents Included in Restricted Cash	$ 102,000,000	$ 113,000,000
Fair Value of Cash Equivalents Included in Other Investments	14,000,000	16,000,000
Transfers Between Levels 1, 2 and 3	0	0
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
Unrealized Losses on Available for Sale Securities	0
Trading Securities, Change in Unrealized Holding Gain (Loss)	9,000,000	3,000,000	7,000,000
Maturity in Years for Cash and Cash Equivalents	3 months
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	116,000,000	129,000,000
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	$ 4,000,000

XML

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 equivalents	$ 116	$ 129
Nuclear decommissioning trusts	1,037	937
Other investments	108	93
Derivative assets - FTRs	1	1
Derivative Assets	1,262	1,160
Current	117	130
Noncurrent	1,145	1,030
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	0
Nuclear decommissioning trusts	694	577
Other investments	64	55
Derivative assets - FTRs	0	0
Derivative Assets	758	632
Current	0	0
Noncurrent	758	632
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	116	129
Nuclear decommissioning trusts	343	360
Other investments	44	38
Derivative assets - FTRs	0	0
Derivative Assets	503	527
Current	116	129
Noncurrent	387	398
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	0
Nuclear decommissioning trusts	0	0
Other investments	0	0
Derivative assets - FTRs	1	1
Derivative Assets	1	1
Current	1	1
Noncurrent	$ 0	$ 0

XML

Long-Term Debt (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Long-term Debt	$ 4,963	$ 5,051
Less amount due within one year	(263)	(303)
Long-term Debt, Excluding Current Maturities	4,221	4,105
Securitization bonds	302	479
Less amount due within one year	(177)	(164)
Detroit Edison 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%
Long-term Debt	3,777	3,515
Detroit Edison 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%
Long-term Debt	707	893
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	479	643
Long-Term Debt Gross [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 4,484	$ 4,408

XML

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	$ 1

XML

Commitments and Contingencies (Details Textuals) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2012 facilities dte_instances	Dec. 31, 2010
Loss Contingencies [Line Items]
Payment from the DOE for Delaying Acceptance of Spent Nuclear Fuel		$ 48,000,000
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
The Re-Proposed Regulations will Provide Minimum Period for Compliance		3 years
Waiting Period of Policy		P12W
Insurance Coverage for Extra Expense When to Necessitate Power Plant when Unavailable		490,000,000
Period of Coverage of Policy for Extra Expenses		P3Y
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
NEIL Policies Against Terroism Loss		3,200,000,000
Amount per Event Loss Associated with Nuclear Power Plants		31,000,000
Maintenance of Public Liability Insurance for Nuclear Power Plants		375,000,000
Aggregate Limit of Liabilities Arises From Terroist Act Outside Scope of Trials Subject to One Industry		300,000,000
Deferred premium charges levied 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
Contract Ratified by Electrical Linemen		4,800
Number of Represented Employees		2,700
Long-term Purchase Commitment, Amount		800,000,000
estimated future capital expenditures for next year		1,600,000,000
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
Site Contingency, Accrual, Undiscounted Amount		$ 9,000,000	$ 8,000,000

XML

Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Comprehensive Income [Line Items]
Change in Benefit Obligations for the Period	$ (2)
Beginning balance	(20)
Ending balance	$ (22)

XML

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]

Ownership information of the two utility plants as of December 31, 2012 was as follows:

				Ludington Hydroelectric
	Belle River			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

XML

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	$ 800
2013 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	475
2014 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	277
2015 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	88
2016 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	2
2017 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	2
2018 - 2028 [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	4
Total [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	$ 848

XML

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	$ 440
Long-term Debt, Maturities, Repayments of Principal in Year Two	500
Long-term Debt, Maturities, Repayments of Principal in Year Three	315
Long-term Debt, Maturities, Repayments of Principal in Year Four	151
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	3,565
Long-term Debt, Gross	$ 4,971

XML

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]
Net actuarial loss	$ (14)	$ 139
Amortization of net actuarial loss	(58)	(40)
Prior service credit	(207)	(3)
Amortization of prior service cost	16	15
Amortization of transition (asset)	(2)	(2)
Total recognized Regulatory assets and Other comprehensive income	(265)	109
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive icnome	(140)	214
Net actuarial loss	50	55
Prior service credit	(69)	(16)
Net transition obligation	$ 0	$ 2

XML

Financial and Other Derivative Instruments (Details Textuals) (FTR [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
FTR [Member]
Derivative [Line Items]
Derivative Instruments Recoverable Through PSCR Mechanism	$ 15	$ 3

XML

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	$ 3
Operating Leases Payments in 2013	26
Capital Lease Payments in 2014	1
Operating Lease Payments in 2014	21
Capital Lease Payments in 2015	0
Operating Lease Payments in 2015	18
Capital Lease Payments in 2016	0
Operating Lease Payments in 2016	16
Capital Lease Payments in 2017	0
Operating Lease Payments in 2017	16
Capital Lease Payments Thereafter	0
Operating Lease Payments Thereafter	66
Capital Lease - Total minimum payments	4
Operating Lease - Total minimum payments	163
Less imputed interest	0
Present value of net minimum lease payments	4
Less current portion	(3)
Non-current portion	$ 1	$ 9

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	$ 2,211	$ 1,957	$ 1,936
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	1,166	1,015
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	682	621
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	363	321
Short-term investments [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	16	23
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	16	23
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	509	467
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	478	440
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	31	27
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	111	114
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	108	110
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	3	4
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	457	351
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	372	272
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	85	79
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	552	509
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	61	61
Fixed income securities [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	491	448
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	441	377
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	147	132
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	56	40
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	238	205
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	125	116
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	$ 125	$ 116

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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	$ 289	$ 437
Amortization of net actuarial loss	(125)	(99)
Amortization of prior service cost	(1)	(4)
Total recognized Regulatory assets and Other comprehensive income	163	334
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	343	480
Net actuarial loss	143	120
Prior service credit	$ 1	$ 1

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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	$ 1	$ 2
Ending Balance	1	1
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	1	1
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	321	324
Realized gains (losses)	9	1
Unrealized gains (losses)	5	(20)
Purchases	199	60
Sales	(171)	(44)
Ending Balance	363	321
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	15	(17)
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	205	206
Realized gains (losses)	13	(3)
Unrealized gains (losses)	(3)	1
Purchases	176	44
Sales	(153)	(43)
Ending Balance	238	205
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	11	3
Pension Plans, Defined Benefit [Member] | Private Equity and Other [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	116	118
Realized gains (losses)	(4)	4
Unrealized gains (losses)	8	(21)
Purchases	23	16
Sales	(18)	(1)
Ending Balance	125	116
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	$ 4	$ (20)

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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	$ 29	$ 27	$ 22
Capital Leases, Contingent Rental Payments Due	$ 27

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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	$ 500
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

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Related Party Transactions

12 Months Ended

Dec. 31, 2012

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

RELATED PARTY TRANSACTIONS

The Company has agreements with affiliated companies to sell energy for resale, purchase power, provide fuel supply services, and provide power plant operation and maintenance services. The Company has agreements with certain DTE Energy affiliates where we charge them for their use of the shared capital assets of the Company. A shared services company accumulates various corporate support services expenses and charges various subsidiaries of DTE Energy, including DTE Electric. DTE Electric records federal, state and local income taxes payable to or receivable from DTE Energy based on its federal, state and local tax provisions.

The following is a summary of transactions with affiliated companies:

	2012		2011		2010
Revenues	(In millions)
Energy sales	$	2	$	1	$	1
Other services	11		4		7
Shared capital assets	26		30		29
Costs
Fuel and power purchases	5		1		4
Other services and interest	1		2		2
Corporate expenses (net)	322		304		294
Other
Dividends declared	317		305		305
Dividends paid	317		305		305

	December 31
	2012		2011
Assets	(In millions)
Accounts receivable	$	5	$	61
Income taxes receivable (included in other current assets)	—		48
Notes receivable	—		26
Liabilities
Accounts payable	52		67
Short-term borrowing	80		64
Income taxes payable (included in other current liabilities)	13
Accrued pension liability	1,368		1,231
Accrued postretirement liability	996		1,217

Our accounts receivable from affiliated companies and accounts payable to affiliated companies are payable upon demand and are generally settled in cash within a monthly business cycle.

Charitable contributions to the DTE Energy Foundation were approximately $21 million and $13 million for the years ended December 31, 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 Electric.

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Fair Value Fair Value (Details 2) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Fair Value of Financial Instruments [Line Items]
Notes receivable, excluding capital leases	$ 5	$ 6
Notes receivable, excluding capital leases		6
Notes receivable - affiliates	0	26
Notes receivable - affiliates		26
Short-term borrowings - affiliates	80	64
Short-term borrowings affiliates		64
Other Short-term Borrowings	130	0
Short-term Debt, Fair Value		0
Long-term debt	4,963	5,051
Long-term debt		5,740
Fair Value, Inputs, Level 1 [Member]
Fair Value of Financial Instruments [Line Items]
Notes receivable, excluding capital leases	0
Notes receivable - affiliates	0
Short-term borrowings affiliates	0
Short-term Debt, Fair Value	0
Long-term debt	0
Fair Value, Inputs, Level 2 [Member]
Fair Value of Financial Instruments [Line Items]
Notes receivable, excluding capital leases	0
Notes receivable - affiliates	0
Short-term borrowings affiliates	0
Short-term Debt, Fair Value	130
Long-term debt	5,021
Fair Value, Inputs, Level 3 [Member]
Fair Value of Financial Instruments [Line Items]
Notes receivable, excluding capital leases	5
Notes receivable - affiliates	0
Short-term borrowings affiliates	80
Short-term Debt, Fair Value	0
Long-term debt	$ 620

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Related Party Transactions Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2012

Related Party Transactions [Abstract]

Schedule of Related Party Transactions [Table Text Block]

The following is a summary of transactions with affiliated companies:

	2012		2011		2010
Revenues	(In millions)
Energy sales	$	2	$	1	$	1
Other services	11		4		7
Shared capital assets	26		30		29
Costs
Fuel and power purchases	5		1		4
Other services and interest	1		2		2
Corporate expenses (net)	322		304		294
Other
Dividends declared	317		305		305
Dividends paid	317		305		305

	December 31
	2012		2011
Assets	(In millions)
Accounts receivable	$	5	$	61
Income taxes receivable (included in other current assets)	—		48
Notes receivable	—		26
Liabilities
Accounts payable	52		67
Short-term borrowing	80		64
Income taxes payable (included in other current liabilities)	13
Accrued pension liability	1,368		1,231
Accrued postretirement liability	996		1,217

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Short-Term Credit Arrangements and Borrowings (Details Textuals) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 300
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
Total Funded Debt to Total Capitalization Ratio	0.52
Total Funded Debt to Total Capitalization Ratio Denominator	1
Short-term Debt, Weighted Average Interest Rate	0.40%
DTE Electric [Member]
Short-term Debt [Line Items]
Long-term Commercial Paper, Current	$ (130)	$ 0

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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	$ 24	$ (62)	$ 0
Inventories	7	(53)	(71)
Recoverable pension and postretirement costs	106	(436)	(26)
Accrued pension liability - affiliates	137	271	(27)
Accounts payable	(64)	41	47
Income taxes payable/receivable	114	54	(77)
Accrued postretirement liability - affiliates	(221)	157	3
Regulatory assets	125	(18)	(77)
Other assets	108	(80)	(54)
Other liabilities	(78)	(15)	29
Total Changes in Assets and Liabilities, Exclusive of Changes Shown Separately	$ 258	$ (141)	$ (253)

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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]

The Company's long-term debt outstanding and weighted average interest rates(a) of debt outstanding at December 31 were:

	2012			2011
Taxable Debt, Principally Secured	(In millions)
5.0% due 2013 to 2042	$	3,777		$	3,515
Tax- Exempt Revenue Bonds (b)
5.3% due 2014 to 2038	707			893
	4,484			4,408
Less amount due within one year	(263		)	(303		)
	$	4,221		$	4,105
Securitization Bonds
6.6% due 2013 to 2015	$	479		$	643
Less amount due within one year	(177		)	(164		)
	$	302		$	479

Schedule of Issued Debt [Table Text Block]

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

Month	Type	Interest Rate		Maturity	Amount
					(In millions)
June	Mortgage Bonds (a)	2.65	%	2022	$	250
June	Mortgage Bonds (a)	3.95	%	2042	250
					$	500

Schedule of Extinguishment of Debt [Table Text Block]

Month	Type	Interest Rate	Maturity	Amount
				(In millions)
March/September	Securitization Bonds	6.42%	2012	$	164
April	Mortgage Bonds	7.90%	2012	10
April	Mortgage Bonds	8.36%	2012	3
July	Senior Notes	5.20%	2012	225
December	Tax Exempt Bonds	3.05%	2024	65
December	Tax Exempt Bonds	5.45%	2032	64
December	Tax Exempt Bonds	5.25%	2032	56
				$	587

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

											2018 &
	2013		2014		2015		2016		2017		thereafter		Total
	(In millions)
Amount to mature	$	440	$	500	$	315	$	151	$	—	$	3,565	$	4,971

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Fair Value (Details 4) (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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Income Taxes (Details 2) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Deferred Tax Liability Not Recognized [Line Items]
Property, plant and equipment	$ (2,578)	$ (2,285)
Securitized regulatory assets	(261)	(384)
Pension and benefits	73	67
Other comprehensive income	15	15
Other, net	(24)	(182)
Deferred Tax Assets Liabilities Gross	(2,775)	(2,769)
Current deferred income tax Liability (included in Current Liabilities - Other)	(14)	(68)
Long-term deferred income tax liability	(2,761)	(2,701)
Deferred income tax assets	557	608
Deferred income tax liabilities	$ (3,332)	$ (3,377)

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Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Asset Retirement Obligations [Line Items]
Asset retirement obligations at January 1, 2012	$ 1,442
Accretion	91
Liabilities incurred	26
Liabilities settled	(4)
Asset retirement obligations at December 31, 2012	$ 1,557

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Significant Accounting Policies (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Significant Accounting Policies [Line Items]
Excise Sales Tax Net Impact on Statement of Operations	$ 0
Maturities on Temporary Investments	3 months
Restricted Cash Time Period to be Classified as Current	1 year
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
Unbilled Contracts Receivable	275	264
Notes Receivable Considered Delinquent Minimum Due Date	60 days
Notes Receivable Considered Delinquent Maximum Due Date	120 days
Expense Related to Refueling Outages	12	23
Period Expenses Related To Refueling Outages Are Accrued	18 months
Intangible Asset Emission Allowance	6	9
Intangible Assets Renewable Energy Credits	44	39
Allocated Share-based Compensation Expense	$ 42	$ 30	$ 23

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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]

BASIS OF PRESENTATION

Corporate Structure

DTE Electric is an electric utility engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan. DTE Electric is regulated by the MPSC and the FERC. In addition, we are regulated by other federal and state regulatory agencies including the NRC, the EPA and the MDEQ.

References in this report to “we,” “us,” “our” or “Company” are to DTE Electric 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.

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 related to Securitization is reflected on the Company’s Consolidated Statements of Financial Position.

The following table summarizes the major balance sheet items at December 31, 2012 and 2011 restricted for Securitization that are either (1) assets that can be used only to settle their obligations or (2) liabilities for which creditors do not have recourse to the general credit of the primary beneficiary.

	December 31,		December 31,
	2012		2011
	(In millions)
ASSETS
Restricted cash	$	102	$	107
Accounts receivable	34		34
Securitized regulatory assets	413		577
Other assets	7		10
	$	556	$	728
LIABILITIES
Accounts payable and accrued current liabilities	$	11	$	14
Other current liabilities	50		55
Current portion long-term debt, including capital leases	177		164
Securitization bonds	302		479
Other long term liabilities	7		7
	$	547	$	719

As of December 31, 2012 and December 31, 2011, DTE Electric had $3 million and $4 million in Notes receivable, related to non-consolidated VIEs, respectively.

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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	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

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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]

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
									Year
2012	(In millions)
Operating Revenues	$	1,198	$	1,289	$	1,542	$	1,262	$	5,291
Operating Income (a)	213		265		378		172		1,028
Net Income	97		127		195		67		486
2011
Operating Revenues	1,192		1,240		1,517		1,203		5,152
Operating Income	205		235		335		227		1,002
Net Income	85		104		158		90		437

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

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

	Benefit			Accumulated Other Comprehensive
	Obligations			Loss
	(In millions)
Beginning balance January 1, 2012	$	(20	)	$	(20	)
Current period change	(2		)	(2		)
Ending balance December 31, 2012	$	(22	)	$	(22	)

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Basis of Presentation (Tables)

12 Months Ended

Dec. 31, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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

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

Schedule of Variable Interest Entities [Table Text Block]

	December 31,		December 31,
	2012		2011
	(In millions)
ASSETS
Restricted cash	$	102	$	107
Accounts receivable	34		34
Securitized regulatory assets	413		577
Other assets	7		10
	$	556	$	728
LIABILITIES
Accounts payable and accrued current liabilities	$	11	$	14
Other current liabilities	50		55
Current portion long-term debt, including capital leases	177		164
Securitization bonds	302		479
Other long term liabilities	7		7
	$	547	$	719

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Related Party Transactions Related Party Transactions (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Revenues [Abstract]
Energy sales	$ 2	$ 1	$ 1
Other services	11	4	7
Shared capital assets	26	30	29
Costs and Expenses [Abstract]
Fuel and power purchases	5	1	4
Other services and interest	1	2	2
Corporate expenses (net)	322	304	294
Other [Abstract]
Dividends declared	(317)	(306)	(305)
Dividends paid	$ 317	$ 305	$ 305
Assets [Abstract]
Accounts receivable	5	61
Income Taxes Receivable, Current	0	48
Notes receivable	0	26
Liabilities [Abstract]
Accounts payable	52	67
Short-term borrowing	80	64
Taxes Payable, Current	13
Accrued pension liability	1,368	1,231
Accrued postretirement liability	996	1,217
DTE Energy [Member]
Other [Abstract]
Dividends declared	$ 317	$ 305	$ 305

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Financial and Other Derivative Instruments (Details 1) (FTR [Member])	Dec. 31, 2012 dte.volumes
FTR [Member]
Derivative [Line Items]
Investment Contract Volume	49,411

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Basis of Presentation (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 customers	Dec. 31, 2011
Legal Entities [Line Items]
Number of Electric Customers	2,100,000
Notes receivable	$ 3	$ 4
Significant Potential Exposure to Loss Due to VIE Long-Term Purchase Contracts	$ 0

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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 [Table Text Block]

	December 31, 2012								December 31, 2011
	Level 1		Level 2		Level 3		Net Balance		Level 1		Level 2		Level 3		Net Balance
	(In millions)
Assets:
Cash equivalents (a)	$	—	$	116	$	—	$	116	$	—	$	129	$	—	$	129
Nuclear decommissioning trusts	694		343		—		1,037		577		360		—		937
Other investments (b)	64		44		—		108		55		38		—		93
Derivative assets — FTRs	—		—		1		1		—		—		1		1
Total	$	758	$	503	$	1	$	1,262	$	632	$	527	$	1	$	1,160
Assets:
Current	$	—	$	116	$	1	$	117	$	—	$	129	$	1	$	130
Noncurrent	758		387		—		1,145		632		398		—		1,030
Total Assets	$	758	$	503	$	1	$	1,262	$	632	$	527	$	1	$	1,160

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

The following table presents 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			2011
	(In millions)
Net Assets as of January 1	$	1		2
Change in fair value recorded in regulatory assets/liabilities	15			2
Purchases, issuances and settlements:
Settlements	(15		)	(3		)
Net Assets as of December 31	$	1		$	1
The amount of total gains (losses) included in regulatory assets and liabilities attributed to the change in unrealized gains (losses) related to regulatory assets and liabilities held at December 31, 2012 and 2011	$	1		$	1

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 December 31, 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	$	5	$	—	$	—	$	5	$	6	$	6
Notes receivable — affiliates	—		—		—		—		26		26
Short-term borrowings — affiliates	80		—		—		80		64		64
Short-term borrowings — other	130		—		130		—		—		—
Long-term debt	4,963		—		5,021		620		5,051		5,740

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

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

	December 31		December 31
	2012		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]

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

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

The following table sets forth the fair value and unrealized gains for the nuclear decommissioning trust funds:

	December 31, 2012				December 31, 2011
	Fair		Unrealized		Fair		Unrealized
	Value		Gains		Value		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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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 represents the fair value of derivative instruments as of December 31, 2012 and 2011:

	December 31
	2012		2011
	(In millions)
FTRs — Other current assets	$	1	$	1
Total derivatives not designated as hedging instrument	$	1	$	1

Volume of Commodity Contracts [Table Text Block]

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

Commodity	Number of Units
FTRs (MWh)	49,411

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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	Additional Paid-in Capital [Member]
Beginning Balance, shares at Dec. 31, 2009		138,632,000
Net Income	$ 441		$ 441
Dividends declared on common stock	(305)		(305)
Ending Balance at Dec. 31, 2010	4,009	1,386	829	(16)	1,810
Ending Balance, shares at Dec. 31, 2010		138,632,000
Net Income	437		437
Dividends declared on common stock	(306)		(306)
Benefit obligations, net of tax	(4)			(4)
Ending Balance at Dec. 31, 2011	4,136	1,386	960	(20)	1,810
Ending Balance, shares at Dec. 31, 2011	138,632,324	138,632,000
Net Income	486		486
Dividends declared on common stock	(317)		(317)
Benefit obligations, net of tax	2			(2)
Ending Balance at Dec. 31, 2012	$ 4,303	$ 1,386	$ 1,129	$ (22)	$ 1,810
Ending Balance, shares at Dec. 31, 2012	138,632,324	138,632,000

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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]

Summary of property by classification as of December 31:

	2012			2011
Property, Plant and Equipment	(In millions)
Generation	$	10,383		$	9,785
Distribution	7,306			7,003
Total	17,689			16,788
Less Accumulated Depreciation and Amortization
Generation	(3,880		)	(3,946		)
Distribution	(2,837		)	(2,580		)
Total	(6,717		)	(6,526		)
Net Property, Plant and Equipment	$	10,972		$	10,262

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Retirement Benefits and Trusteed Assets (Details 3) (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	$ 182
Defined Benefit Plan, Expected Future Benefit Payments in 2014	187
Defined Benefit Plan, Expected Future Benefit Payments in 2015	193
Defined Benefit Plan, Expected Future Benefit Payments in 2016	200
Defined Benefit Plan, Expected Future Benefit Payments in 2017	208
Defined Benefit Plan, Expected Future Benefit Payments in 2018-2022	1,145
Other Postretirement Benefit 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	78
Defined Benefit Plan, Expected Future Benefit Payments in 2014	82
Defined Benefit Plan, Expected Future Benefit Payments in 2015	87
Defined Benefit Plan, Expected Future Benefit Payments in 2016	91
Defined Benefit Plan, Expected Future Benefit Payments in 2017	97
Defined Benefit Plan, Expected Future Benefit Payments in 2018-2022	556
Total Defined Benefit Pension Plan Expected Future Payments	$ 2,115

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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	$	64		$	55		$	52
Interest cost	155			154			153
Expected return on plan assets	(166		)	(168		)	(171		)
Amortization of:
Net loss	124			99			70
Prior service cost	1			4			5
Settlements	2			2			—
Net pension cost	$	180		$	146		$	109

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	$	289		$	437
Amortization of net actuarial loss	(125		)	(99		)
Amortization of prior service cost	(1		)	(4		)
Total recognized in Regulatory assets and Other comprehensive income	$	163		$	334
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	343		$	480
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	$	143		$	120
Prior service cost	$	1		$	1

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

The following table reconciles the obligations, assets and funded status of the plan as well as the amount 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	$	3,307		$	2,963
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	3,196		$	2,899
Service cost	64			55
Interest cost	155			154
Actuarial loss	342			251
Settlements	2			2
Benefits paid	(174		)	(165		)
Projected benefit obligation, end of year	$	3,585		$	3,196
Change in plan assets
Plan assets at fair value, beginning of year	$	1,957		$	1,936
Actual return on plan assets	220			(18		)
Company contributions	208			204
Benefits paid	(174		)	(165		)
Plan assets at fair value, end of year	$	2,211		$	1,957
Funded status of the plan	$	(1,374	)	$	(1,239	)
Amount recorded as:
Current liabilities	$	(6	)	$	(8	)
Noncurrent liabilities	(1,368		)	(1,231		)
	$	(1,374	)	$	(1,239	)
Amounts recognized in Regulatory assets (see Note 8)
Net actuarial loss	$	1,805		$	1,645
Prior service cost	10			11
	$	1,815		$	1,656

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	$	182
2014	187
2015	193
2016	200
2017	208
2018 - 2022	1,145
Total	$	2,115

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 December 31, 2011 (a):

	December 31, 2012								December 31, 2011
(in Millions)	Level 1		Level 2		Level 3		Net Balance		Level 1		Level 2		Level 3		Net Balance
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	16	$	—	$	16	$	—	$	23	$	—	$	23
Equity securities
U.S. Large Cap (c)	478		31		—		509		440		27		—		467
U.S. Small/Mid Cap (d)	108		3		—		111		110		4		—		114
Non U.S. (e)	372		85		—		457		272		79		—		351
Fixed income securities (f)	61		491		—		552		61		448		—		509
Hedge Funds and Similar Investments (g)	147		56		238		441		132		40		205		377
Private Equity and Other (h)	—		—		125		125		—		—		116		116
Total	$	1,166	$	682	$	363	$	2,211	$	1,015	$	621	$	321	$	1,957

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			Private Equity						Hedge Funds and Similar			Private Equity
	Investments			and Other			Total			Investments			and Other			Total
	(In millions)
Beginning Balance	$	205		$	116		$	321		$	206		$	118		324
Total realized/unrealized gains (losses):
Realized gains (losses)	13			(4		)	9			(3		)	4			1
Unrealized gains (losses)	(3		)	8			5			1			(21		)	(20		)
Purchases, sales and settlements:
Purchases	176			23			199			44			16			60
Sales	(153		)	(18		)	(171		)	(43		)	(1		)	(44		)
Ending Balance	$	238		$	125		$	363		$	205		$	116		$	321
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	$	11		$	4		$	15		$	3		$	(20	)	$	(17	)

Schedule of Net Postretirement Costs [Table Text Block]

Net postretirement cost includes the following components:

	2012			2011			2010
	(In millions)
Service cost	$	51		$	49		$	47
Interest cost	91			91			95
Expected return on plan assets	(61		)	(62		)	(52		)
Amortization of:
Net loss	58			40			38
Prior service costs (credit)	(16		)	(15		)	2
Net transition asset	2			2			2
Net postretirement cost	$	125		$	105		$	132

Schedule of Postretirement Plan Amounts Recognized in Regulatory Assets [Table Text Block]

	2012			2011
	(In millions)
Other changes in plan assets and APBO recognized in Regulatory assets
Net actuarial loss (gain)	$	(14	)	$	139
Amortization of net actuarial loss	(58		)	(40		)
Prior service cost (credit)	(207		)	(3		)
Amortization of prior service credit	16			15
Amortization of transition asset	(2		)	(2		)
Total recognized in Regulatory assets	$	(265	)	$	109
Total recognized in net periodic pension cost and Regulatory assets	$	(140	)	$	214
Estimated amounts to be amortized from Regulatory assets into net periodic benefit cost during next fiscal year
Net actuarial loss	$	50		$	55
Prior service credit	$	(69	)	$	(16	)
Net transition obligation	$	—		$	2

Schedule of Other Postretirement Benefit Plans Disclosures [Table Text Block]

	2012			2011
Change in accumulated postretirement benefit obligation	(In millions)
Accumulated postretirement benefit obligation, beginning of year	$	1,868		$	1,742
Service cost	51			49
Interest cost	91			91
Plan amendments	(207		)	(3		)
Actuarial loss	12			60
Medicare Part D subsidy	5			4
Benefits paid	(68		)	(75		)
Accumulated postretirement benefit obligation, end of year	$	1,752		$	1,868
Change in plan assets
Plan assets at fair value, beginning of year	$	651		$	682
Actual return on plan assets	88			(17		)
Company contributions	95			66
Benefits paid	(78		)	(80		)
Plan assets at fair value, end of year	$	756		$	651
Funded status, end of year	$	(996	)	$	(1,217	)
Amount recorded as:
Non-current liabilities	$	(996	)	$	(1,217	)
Amounts recognized in Regulatory assets (see Note 8)
Net actuarial loss	$	560		$	633
Prior service cost	(244		)	(53		)
Net transition obligation	—			2
	$	316		$	582

Schedule of Expected Benefit Payments OPEB [Table Text Block]

	(In millions)
2013	$	78
2014	82
2015	87
2016	91
2017	97
2018-2022	556
	$	991

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. 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 December 31, 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	$	1	$	—	$	2	$	1	$	8	$	—	$	9
Equity securities
U.S. Large Cap (c)	122		2		—		124		116		10		—		126
U.S. Small/Mid Cap (d)	70		—		—		70		46		4		—		50
Non U.S. (e)	151		4		—		155		116		10		—		126
Fixed income securities (f)	25		162		—		187		15		156		—		171
Hedge Funds and Similar Investments (g)	68		15		78		161		53		14		63		130
Private Equity and Other (h)	—		—		57		57		—		—		39		39
Total	$	437	$	184	$	135	$	756	$	347	$	202	$	102	$	651

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	$	63		$	39		$	102		$	52		$	36		$	88
Total realized/unrealized gains (losses):
Realized gains (losses)	4			(7		)	(3		)	(1		)	1			—
Unrealized gains (losses)	—			9			9			2			(14		)	(12		)
Purchases, sales and settlements:
Purchases	56			25			81			45			31			76
Sales	(45		)	(9		)	(54		)	(35		)	(15		)	(50		)
Ending Balance	$	78		$	57		$	135		$	63		$	39		$	102
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	4		$	1		$	5		$	3		$	(11	)	$	(8	)

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Fair Value (Details 5) (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]
Available-for-sale Securities, Equity Securities, Noncurrent	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

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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 2 [Member]	Dec. 31, 2012 Mortgage Bonds 3 [Member]	Dec. 31, 2012 Senior Notes [Member]	Dec. 31, 2012 Tax Exempt Revenue Bonds [Member]	Dec. 31, 2012 Tax-Exempt Revenue Bonds 1 [Member]	Dec. 31, 2012 Tax-Exempt Revenue Bonds 2 [Member]
Extinguishment of Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.42%	7.90%	8.36%	5.20%	3.05%	5.45%	5.25%
Extinguishment of Debt, Amount	$ 587	$ 164	$ 10	$ 3	$ 225	$ 65	$ 64	$ 56

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Consolidated Statements of Operations (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Revenues	$ 5,291	$ 5,152	$ 4,993
Operating Expenses
Fuel, purchased power and gas	1,758	1,716	1,580
Operation and maintenance	1,429	1,369	1,305
Depreciation, depletion and amortization	822	813	849
Taxes other than income	256	240	237
Asset (gains) losses and reserves, net	(2)	12	(6)
Total operating expenses	4,263	4,150	3,965
Operating Income	1,028	1,002	1,028
Other (Income) and Deductions
Interest expense	272	289	313
Interest income	(1)	0	(1)
Other income	(53)	(47)	(39)
Other expenses	42	56	44
Total Other (Income) and Deductions	260	298	317
Income Before Income Taxes	768	704	711
Income Tax Expense	282	267	270
Net Income	$ 486	$ 437	$ 441

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Basis of Presentation (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Assets [Abstract]
Restricted cash	$ 102	$ 127
Accounts receivable	697	709
Securitized regulatory assets	413	577
Other assets	138	142
Total Assets	17,651	17,493
Liabilities [Abstract]
Other current liabilities	166	230
Current portion long-term debt, including, capital leases	443	470
Securitization bonds	302	479
Other long term liabilities	103	115
Variable Interest Entity Securitization [Member]
Assets [Abstract]
Restricted cash	102	107
Accounts receivable	34	34
Securitized regulatory assets	413	577
Other assets	7	10
Total Assets	556	728
Liabilities [Abstract]
Accounts payable and accrued current liabilities	11	14
Other current liabilities	50	55
Current portion long-term debt, including, capital leases	177	164
Securitization bonds	302	479
Other long term liabilities	7	7
Total Liabilities	$ 547	$ 719

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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]	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]
Transfers between Level 2 and Level 3					$ 0			$ 0
Transfers between Level 1 and Level 2					0			0
Health Care Trend Increase in Percentage Point	0.00%
Defined Benefit Plan, Effect of One Percentage Point Increase On Service and Interest	21,000,000
Company contributions				275,000,000	208,000,000	204,000,000	120,000,000	95,000,000	66,000,000
Defined Contribution Plan, Cost Recognized	19,000,000	18,000,000	17,000,000
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year								120,000,000
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	218,000,000
Health Care Trend Decrease in Percentage Point	0.00%
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components	13,000,000
Prescription Drug Benefit, Effect of Subsidy on Net Periodic Postretirement Benefit Cost	4,000,000	5,000,000	5,000,000
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
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	0
Company Retiree New Coverage Minimum	3,250
Company Retiree New Coverage after a Certain Date Maximum	4,000
Defined Benefit Plan Effect of One Percentage Point on Post Retirement Obligation	$ 185,000,000

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Consolidated Statements of Financial Position (Parentheticals) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Current Assets	$ 1,577	$ 1,796
Allowance for Doubtful Accounts	35	80
Allowance for Doubtful Accounts Receivable	$ 35	$ 80
Statement of Stockholders' Equity [Abstract]
Common Stock, Par or Stated Value Per Share	$ 10	$ 10
Common Stock, Shares Authorized	400,000,000	400,000,000
Common Stock, Shares, Issued	138,632,324	138,632,324
Common Stock, Shares, Outstanding	138,632,324	138,632,324

XML

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	$ 756	$ 651	$ 682
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	437	347
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	184	202
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	135	102
Short-term investments [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2	9
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	1
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	1	8
Short-term investments [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Us Large Cap Equity Securities [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	124	126
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	122	116
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	2	10
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	70	50
US Small Cap and Mid Cap Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	70	46
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	4
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	155	126
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	151	116
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	4	10
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	187	171
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	25	15
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	162	156
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	161	130
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	68	53
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	15	14
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	78	63
Equity Securities, Other [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	57	39
Equity Securities, 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
Equity Securities, 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
Equity Securities, 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	$ 57	$ 39

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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	$ 19	$ 9
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	3.30%
Capitalized Software Amortization Minimum Period	5 years
Capitalized Software Amortization Maximum Period	15 years
Capitalized Computer Software, Amortization	62	58	55
Capitalized Computer Software, Gross	479	501
Capitalized Computer Software, Accumulated Amortization	245	218
Capitalized Computer Software Future Amortization Expense	40
Capital Leased Assets, Gross	6	26
Capital Leases, Lessee Balance Sheet, Assets by Major Class, Accumulated Depreciation	$ 3	$ 14
Electric Generation Equipment [Member]
Public Utility Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P40Y
Electric Distribution [Member]
Public Utility Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	P41Y

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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]
Change in capital expenditures not paid	$ (22)	$ 47	$ 27

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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
Assets	(In millions)
Recoverable pension and postretirement costs:
Pension	$	1,815		$	1,656
Postretirement costs	316			582
Asset retirement obligation	424			420
Recoverable Michigan income taxes	253			270
Recoverable income taxes related to securitized regulatory assets	226			316
Accrued PSCR revenue	87			147
Cost to achieve Performance Excellence Process	82			100
Other recoverable income taxes	76			81
Choice incentive mechanism	66			166
Recoverable restoration expense	49			58
Unamortized loss on reacquired debt	37			36
Enterprise Business Systems costs	16			18
Other	63			40
	3,510			3,890
Less amount included in current assets	(162		)	(272		)
	$	3,348		$	3,618
Securitized regulatory assets	$	413		$	577
Liabilities
Renewable energy	$	230		$	192
Refundable revenue decoupling / deferred gain	127			127
Asset removal costs	81			73
Over recovery of Securitization	54			53
Energy Optimization	26			24
Fermi 2 refueling outage	12			23
Refundable uncollectible expense	10			13
Low Income Energy Efficiency Fund	—			23
Other	9			6
	549			534
Less amount included in current liabilities	(66		)	(80		)
	$	483		$	454

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Reconciliation of Income Tax Expense to Federal Tax Rate [Line Items]
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest	$ 768	$ 704	$ 711
Income tax expense at 35% statutory rate	269	246	249
Investment tax credits	(6)	(6)	(6)
Depreciation	3	3	3
Employee Stock Ownership Plan dividends	(3)	(3)	(3)
Domestic production activities deduction	(16)	(6)	(6)
State and other income taxes, net of federal benefit	40	39	40
Other, net	(5)	(6)	(7)
Income Tax Expense	$ 282	$ 267	$ 270
Effective Income Tax Rate	36.70%	38.00%	38.00%

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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

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.

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 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 Electric 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. The state implementation plan process is in the preliminary stage and any required emission reductions for DTE Electric 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 three-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.

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.

Labor Contracts

We had approximately 4,800 employees as of December 31, 2012, of which approximately 2,700 were represented by unions. The majority of our union employees are under a contract that expires in June 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. The Company estimates that these commitments will be approximately $0.8 billion from 2013 through 2028 as detailed in the following table:

	(In millions)
2013	$	475
2014	277
2015	88
2016	2
2017	2
2018 - 2028	4
	$	848

The Company also estimates that 2013 capital expenditures will be approximately $1.6 billion. The Company has made certain commitments in connection with expected capital expenditures.

Bankruptcies

The Company purchases and sells electricity from and to governmental entities and numerous companies operating in the steel, automotive, energy, retail 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 Note 8 for a discussion of contingencies related to Regulatory Matters.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

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

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	$	768		$	704		$	711
Income tax expense at 35% statutory rate	$	269		$	246		$	249
Investment tax credits	(6		)	(6		)	(6		)
Depreciation	3			3			3
Employee Stock Ownership Plan dividends	(3		)	(3		)	(3		)
Domestic production activities deduction	(16		)	(6		)	(6		)
State and other income taxes, net of federal benefit	40			39			40
Other, net	(5		)	(6		)	(7		)
Income Tax Expense	$	282		$	267		$	270
Effective income tax rate	36.7		%	38.0		%	38.0		%

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

Components of income tax expense (benefits) were as follows:

	2012			2011		2010
Current income tax expense (benefit)	(In millions)
Federal	$	267		$	15	$	(89	)
State and other income tax	67			21		37
Total current income taxes	334			36		(52		)
Deferred income tax expense (benefit)
Federal	(47		)	193		297
State and other income tax	(5		)	38		25
Total deferred income taxes	(52		)	231		322
Total	$	282		$	267	$	270

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	$	(2,578	)	$	(2,285	)
Securitized regulatory assets	(261		)	(384		)
Pension and benefits	73			67
Other comprehensive income	15			15
Other, net	(24		)	(182		)
	$	(2,775	)	$	(2,769	)
Current deferred income tax liability (included in Current Liabilities — Other)	$	(14	)	$	(68	)
Long-term deferred income tax liabilities	$	(2,761	)	$	(2,701	)
	$	(2,775	)	$	(2,769	)
Deferred income tax assets	$	557		$	608
Deferred income tax liabilities	(3,332		)	(3,377		)
	$	(2,775	)	$	(2,769	)

Summary of Positions for which Significant Change in Unrecognized Tax Benefits is Reasonably Possible [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	$	59		$	18		$	96
Additions for tax positions of prior years	—			45			1
Reductions for tax positions of prior years	(3		)	(5		)	—
Additions for tax positions of current year	—			1			6
Settlements	(52		)	—			(85		)
Balance at December 31	$	4		$	59		$	18

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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)	$ 280	$ 294	$ 315
Income taxes	$ 223	$ (18)	$ 28

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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
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately	(In millions)
Accounts receivable, net	$	24		$	(62	)	$	—
Inventories	7			(53		)	(71		)
Recoverable pension and postretirement costs	106			(436		)	(26		)
Accrued pension liability — affiliates	137			271			(27		)
Accounts payable	(64		)	41			47
Income taxes payable/receivable	114			54			(77		)
Accrued postretirement liability — affiliates	(221		)	157			3
Regulatory assets	125			(18		)	(77		)
Other assets	108			(80		)	(54		)
Other liabilities	(78		)	(15		)	29
	$	258		$	(141	)	$	(253	)

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

	2012		2011			2010
Cash paid (received) for:	(In millions)
Interest (excluding interest capitalized)	$	280	$	294		$	315
Income taxes	223		(18		)	28

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

	2012			2011		2010
	(In millions)
Change in capital expenditures not paid	$	(22	)	$	47	$	27

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Income Taxes (Details 3) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits	$ 4	$ 59	$ 18	$ 96
Additions for tax positions of current years	0	1	6
Additions for tax positions of prior years	0	45	1
Reductions for tax positions of prior years	(3)	(5)	0
Settlements	$ (52)	$ 0	$ (85)

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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	$ 486	$ 437	$ 441
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	822	813	849
Deferred income taxes	(52)	231	322
Asset (gains), losses and reserves, net	(2)	13	(6)
Changes in assets and liabilities, exclusive of changes shown separately (Note 17)	258	(141)	(253)
Net cash from operating activities	1,512	1,353	1,353
Investing Activities
Plant and equipment expenditures	(1,230)	(1,202)	(864)
Restricted cash for debt redemption, principally Securitization	5	(3)	(25)
Notes receivable from affiliate	26	77	(21)
Proceeds from sale of nuclear decommissioning trust fund assets	97	80	377
Investment in nuclear decommissioning trust funds	(102)	(97)	(410)
Other investments	(26)	(32)	(60)
Net cash used for investing activities	(1,230)	(1,177)	(1,003)
Financing Activities
Issuance of long-term debt	496	609	614
Redemption of long-term debt	(587)	(554)	(652)
Short-term borrowings, net	130	0	0
Short-term borrowings from affiliate	16	64	0
Dividends on common stock	(317)	(305)	(305)
Other	(3)	(7)	(11)
Net cash used for financing activities	(265)	(193)	(354)
Net Increase (Decrease) in Cash and Cash Equivalents	17	(17)	(4)
Cash and Cash Equivalents at Beginning of Period	13	30	34
Cash and Cash Equivalents at End of Period	$ 30	$ 13	$ 30

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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
Benefit Obligations Net Of Tax	$ (2)	$ (4)	$ 0
Net Income	486	437	441
Other comprehensive income (loss), net of tax:
Comprehensive income	$ 484	$ 433	$ 441

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Income Taxes (Notes)

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

INCOME TAXES

Income Tax Summary

We are part of the consolidated federal income tax return of DTE Energy. The federal income tax expense for DTE Electric is determined on an individual company basis with no allocation of tax expenses or benefits from other affiliates of DTE Energy. We had an income tax payable to DTE Energy of $13 million at December 31, 2012 and we had an income tax receivable from DTE Energy of $48 million at December 31, 2011.

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	$	768		$	704		$	711
Income tax expense at 35% statutory rate	$	269		$	246		$	249
Investment tax credits	(6		)	(6		)	(6		)
Depreciation	3			3			3
Employee Stock Ownership Plan dividends	(3		)	(3		)	(3		)
Domestic production activities deduction	(16		)	(6		)	(6		)
State and other income taxes, net of federal benefit	40			39			40
Other, net	(5		)	(6		)	(7		)
Income Tax Expense	$	282		$	267		$	270
Effective income tax rate	36.7		%	38.0		%	38.0		%

Components of income tax expense (benefits) were as follows:

	2012			2011		2010
Current income tax expense (benefit)	(In millions)
Federal	$	267		$	15	$	(89	)
State and other income tax	67			21		37
Total current income taxes	334			36		(52		)
Deferred income tax expense (benefit)
Federal	(47		)	193		297
State and other income tax	(5		)	38		25
Total deferred income taxes	(52		)	231		322
Total	$	282		$	267	$	270

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	$	(2,578	)	$	(2,285	)
Securitized regulatory assets	(261		)	(384		)
Pension and benefits	73			67
Other comprehensive income	15			15
Other, net	(24		)	(182		)
	$	(2,775	)	$	(2,769	)
Current deferred income tax liability (included in Current Liabilities — Other)	$	(14	)	$	(68	)
Long-term deferred income tax liabilities	$	(2,761	)	$	(2,701	)
	$	(2,775	)	$	(2,769	)
Deferred income tax assets	$	557		$	608
Deferred income tax liabilities	(3,332		)	(3,377		)
	$	(2,775	)	$	(2,769	)

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.

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	$	59		$	18		$	96
Additions for tax positions of prior years	—			45			1
Reductions for tax positions of prior years	(3		)	(5		)	—
Additions for tax positions of current year	—			1			6
Settlements	(52		)	—			(85		)
Balance at December 31	$	4		$	59		$	18

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 our effective tax rate. The Company does not anticipate any material decrease in unrecognized tax benefits in the next 12 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 $(3) million, $1 million and $1 million in 2012, 2011 and 2010, respectively.

In 2012, DTE Energy and its subsidiaries settled a federal tax audit for the 2009 and 2010 tax years, which resulted in the recognition of $52 million of unrecognized tax benefits by Detroit Edison. The Company's federal income tax returns for years 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 is 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 Michigan Corporate Income Tax was enacted effective January 1, 2012. The new 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 old 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 new 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 $30 million 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 net deferred tax assets of $342 million. The $342 million decrease in deferred tax assets was offset against the regulatory liabilities established upon enactment of the MBT.

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

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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	$ 80	$ 93	$ 118
Charged to cost and expenses	40	47	57
Charged to other accounts (1)	7	8	8
Deductions (2)	(92)	(68)	(90)
Balance at End of Period	$ 35	$ 80	$ 93

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Retirement Benefits and Trusteed Assets (Details 13) (Other Postretirement Benefit Plans, Defined Benefit [Member])	12 Months Ended
	Dec. 31, 2012
Other Postretirement Benefits 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]
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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Retirement Benefits and Trusteed Assets (Details 11) (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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Document Entity Information Document (USD $)	12 Months Ended
	Dec. 31, 2012	Jun. 30, 2012
Entity Registrant Name	DTE ELECTRIC CO
Entity Central Index Key	0000028385
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-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	138,632,324
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float		$ 0

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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

The Company's long-term debt outstanding and weighted average interest rates(a) of debt outstanding at December 31 were:

	2012			2011
Taxable Debt, Principally Secured	(In millions)
5.0% due 2013 to 2042	$	3,777		$	3,515
Tax- Exempt Revenue Bonds (b)
5.3% due 2014 to 2038	707			893
	4,484			4,408
Less amount due within one year	(263		)	(303		)
	$	4,221		$	4,105
Securitization Bonds
6.6% due 2013 to 2015	$	479		$	643
Less amount due within one year	(177		)	(164		)
	$	302		$	479

_________________________________

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

(b) 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:

Month	Type	Interest Rate		Maturity	Amount
					(In millions)
June	Mortgage Bonds (a)	2.65	%	2022	$	250
June	Mortgage Bonds (a)	3.95	%	2042	250
					$	500

_____________________________

(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.

Debt Redemptions

In 2012, the following debt was redeemed:

Month	Type	Interest Rate	Maturity	Amount
				(In millions)
March/September	Securitization Bonds	6.42%	2012	$	164
April	Mortgage Bonds	7.90%	2012	10
April	Mortgage Bonds	8.36%	2012	3
July	Senior Notes	5.20%	2012	225
December	Tax Exempt Bonds	3.05%	2024	65
December	Tax Exempt Bonds	5.45%	2032	64
December	Tax Exempt Bonds	5.25%	2032	56
				$	587

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

											2018 &
	2013		2014		2015		2016		2017		thereafter		Total
	(In millions)
Amount to mature	$	440	$	500	$	315	$	151	$	—	$	3,565	$	4,971

Cross Default Provisions

Substantially all of the net properties of DTE Electric are subject to the lien of its mortgage. Should DTE Electric fail to timely pay its indebtedness under this mortgage, such failure may create cross defaults in the indebtedness of DTE Energy.

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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	$ 64	$ 55	$ 52
Interest cost	155	154	153
Expected return on plan assets	(166)	(168)	(171)
Amortization of: [Abstract]
Net actuarial loss	124	99	70
Prior service cost	1	4	5
Settlements	2	2	0
Net pension cost	$ 180	$ 146	$ 109

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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		$ 3,510	$ 3,890
Other Postretirement Benefit Plans, Defined Benefit [Member]
Change in Accumulated PostRetirement Benefit Obligation [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in 2013		78
Projected benefit obligation, beginning of year	1,868	1,868	1,742
Service cost		51	49	47
Interest cost		91	91	95
Plan amendments		(207)	(3)
Actuarial loss		12	60
Medicare Part D subsidy		5	4
Benefits paid		(68)	(75)
Projected benefit obligation, end of year		1,752	1,868	1,742
Defined Benefit Plan, Fair Value of Plan Assets		756	651	682
Actual return on plan assets		88	(17)
Company contributions	120	95	66
Benefits paid		(78)	(80)
Funded status of the plan		(996)	(1,217)
Noncurrent liabilities		(996)	(1,217)
Net actuarial loss		560	633
Prior service cost		(244)	(53)
Net transition obligation		0	2
Regulatory Assets		316	582
Defined Benefit Plan, Expected Future Benefit Payments in 2014		82
Defined Benefit Plan, Expected Future Benefit Payments in 2015		87
Defined Benefit Plan, Expected Future Benefit Payments in 2016		91
Defined Benefit Plan, Expected Future Benefit Payments in 2017		97
Defined Benefit Plan, Expected Future Benefit Payments in 2018-2022		$ 556

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Consolidated Statements of Comprehensive Income (Parentheticals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	$ (1)	$ (2)	$ 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 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 fair value are recognized in earnings each period.

The Company's primary market risk exposure is associated with commodity prices, credit and interest rates. The Company has risk management policies to monitor and manage market risks. The Company uses derivative instruments to manage some of the exposure. 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.

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

	December 31
	2012		2011
	(In millions)
FTRs — Other current assets	$	1	$	1
Total derivatives not designated as hedging instrument	$	1	$	1

The effect of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position were $15 million in gains related to FTRs recognized in Regulatory liabilities for the year ended December 31, 2012, and $3 million in 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
FTRs (MWh)	49,411

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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 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		Net Balance		Level 1		Level 2		Level 3		Net Balance
	(In millions)
Assets:
Cash equivalents (a)	$	—	$	116	$	—	$	116	$	—	$	129	$	—	$	129
Nuclear decommissioning trusts	694		343		—		1,037		577		360		—		937
Other investments (b)	64		44		—		108		55		38		—		93
Derivative assets — FTRs	—		—		1		1		—		—		1		1
Total	$	758	$	503	$	1	$	1,262	$	632	$	527	$	1	$	1,160
Assets:
Current	$	—	$	116	$	1	$	117	$	—	$	129	$	1	$	130
Noncurrent	758		387		—		1,145		632		398		—		1,030
Total Assets	$	758	$	503	$	1	$	1,262	$	632	$	527	$	1	$	1,160

_______________________________________

(a) At December 31, 2012 available for sale securities of $116 million, included $102 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 $129 million, included $113 million and $16 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively.

(b) Available for sale equity securities at December 31, 2012 and December 31, 2011 of $5 million and $4 million are included in Other investments on the Consolidated Statements of Financial Position, respectively.

The following table presents 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			2011
	(In millions)
Net Assets as of January 1	$	1		2
Change in fair value recorded in regulatory assets/liabilities	15			2
Purchases, issuances and settlements:
Settlements	(15		)	(3		)
Net Assets as of December 31	$	1		$	1
The amount of total gains (losses) included in regulatory assets and liabilities attributed to the change in unrealized gains (losses) related to regulatory assets and liabilities held at December 31, 2012 and 2011	$	1		$	1

No transfers between Levels 1, 2 or 3 occurred in the years ended December 31, 2012 and December 31, 2011.

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. The Company has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, the Company 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. The Company 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. The Company 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. The Company has obtained an understanding of how these prices are derived. Additionally, the Company selectively corroborates the fair value of its transactions by comparison of market-based price sources. Mathematical valuation models are used for derivatives for which external market data is not readily observable, such as contracts which extend beyond the actively traded reporting period.

Fair Value of Financial Instruments

The fair value of 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. The Company has obtained an understanding of how the fair values are derived. The Company 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 as 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 the Company'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 December 31, 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	$	5	$	—	$	—	$	5	$	6	$	6
Notes receivable — affiliates	—		—		—		—		26		26
Short-term borrowings — affiliates	80		—		—		80		64		64
Short-term borrowings — other	130		—		130		—		—		—
Long-term debt	4,963		—		5,021		620		5,051		5,740

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 7.

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

	December 31		December 31
	2012		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		Unrealized		Fair		Unrealized
	Value		Gains		Value		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, 2011 no 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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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

DTE Electric participates in various plans that provide pension and other postretirement benefits for DTE Energy and its affiliates. The plans are sponsored by DTE Energy Corporate Services, LLC (LLC), a subsidiary of DTE Energy. DTE Electric is allocated net periodic benefit costs for its share of the amounts of the combined 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. At the discretion of management, and depending upon financial market conditions, we anticipate making up to a $275 million contribution to the pension plans in 2013.

Net pension cost includes the following components:

	2012			2011			2010
	(In millions)
Service cost	$	64		$	55		$	52
Interest cost	155			154			153
Expected return on plan assets	(166		)	(168		)	(171		)
Amortization of:
Net loss	124			99			70
Prior service cost	1			4			5
Settlements	2			2			—
Net pension cost	$	180		$	146		$	109

	2012			2011
	(In millions)
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income
Net actuarial loss	$	289		$	437
Amortization of net actuarial loss	(125		)	(99		)
Amortization of prior service cost	(1		)	(4		)
Total recognized in Regulatory assets and Other comprehensive income	$	163		$	334
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	343		$	480
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	$	143		$	120
Prior service cost	$	1		$	1

The following table reconciles the obligations, assets and funded status of the plan as well as the amount 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	$	3,307		$	2,963
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	3,196		$	2,899
Service cost	64			55
Interest cost	155			154
Actuarial loss	342			251
Settlements	2			2
Benefits paid	(174		)	(165		)
Projected benefit obligation, end of year	$	3,585		$	3,196
Change in plan assets
Plan assets at fair value, beginning of year	$	1,957		$	1,936
Actual return on plan assets	220			(18		)
Company contributions	208			204
Benefits paid	(174		)	(165		)
Plan assets at fair value, end of year	$	2,211		$	1,957
Funded status of the plan	$	(1,374	)	$	(1,239	)
Amount recorded as:
Current liabilities	$	(6	)	$	(8	)
Noncurrent liabilities	(1,368		)	(1,231		)
	$	(1,374	)	$	(1,239	)
Amounts recognized in Regulatory assets (see Note 8)
Net actuarial loss	$	1,805		$	1,645
Prior service cost	10			11
	$	1,815		$	1,656

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	$	182
2014	187
2015	193
2016	200
2017	208
2018 - 2022	1,145
Total	$	2,115

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 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 December 31, 2011 (a):

	December 31, 2012								December 31, 2011
(in Millions)	Level 1		Level 2		Level 3		Net Balance		Level 1		Level 2		Level 3		Net Balance
	(In millions)
Asset Category:
Short-term investments (b)	$	—	$	16	$	—	$	16	$	—	$	23	$	—	$	23
Equity securities
U.S. Large Cap (c)	478		31		—		509		440		27		—		467
U.S. Small/Mid Cap (d)	108		3		—		111		110		4		—		114
Non U.S. (e)	372		85		—		457		272		79		—		351
Fixed income securities (f)	61		491		—		552		61		448		—		509
Hedge Funds and Similar Investments (g)	147		56		238		441		132		40		205		377
Private Equity and Other (h)	—		—		125		125		—		—		116		116
Total	$	1,166	$	682	$	363	$	2,211	$	1,015	$	621	$	321	$	1,957

_______________________________________

(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 Electric 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 Electric 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			Private Equity						Hedge Funds and Similar			Private Equity
	Investments			and Other			Total			Investments			and Other			Total
	(In millions)
Beginning Balance	$	205		$	116		$	321		$	206		$	118		324
Total realized/unrealized gains (losses):
Realized gains (losses)	13			(4		)	9			(3		)	4			1
Unrealized gains (losses)	(3		)	8			5			1			(21		)	(20		)
Purchases, sales and settlements:
Purchases	176			23			199			44			16			60
Sales	(153		)	(18		)	(171		)	(43		)	(1		)	(44		)
Ending Balance	$	238		$	125		$	363		$	205		$	116		$	321
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	$	11		$	4		$	15		$	3		$	(20	)	$	(17	)

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 credit service. The cost of these plans was $19 million, $18 million, and $17 million in each of the years ended 2012, 2011, and 2010, respectively.

Other Postretirement Benefits

The Company participates in plans sponsored by LLC that provide 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 our postretirement benefit obligations. Separate qualified Voluntary Employees Beneficiary Association (VEBA) trusts exist for represented and non-represented employees.

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 $4,000per 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 $120 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	$	51		$	49		$	47
Interest cost	91			91			95
Expected return on plan assets	(61		)	(62		)	(52		)
Amortization of:
Net loss	58			40			38
Prior service costs (credit)	(16		)	(15		)	2
Net transition asset	2			2			2
Net postretirement cost	$	125		$	105		$	132

	2012			2011
	(In millions)
Other changes in plan assets and APBO recognized in Regulatory assets
Net actuarial loss (gain)	$	(14	)	$	139
Amortization of net actuarial loss	(58		)	(40		)
Prior service cost (credit)	(207		)	(3		)
Amortization of prior service credit	16			15
Amortization of transition asset	(2		)	(2		)
Total recognized in Regulatory assets	$	(265	)	$	109
Total recognized in net periodic pension cost and Regulatory assets	$	(140	)	$	214
Estimated amounts to be amortized from Regulatory assets into net periodic benefit cost during next fiscal year
Net actuarial loss	$	50		$	55
Prior service credit	$	(69	)	$	(16	)
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
Change in accumulated postretirement benefit obligation	(In millions)
Accumulated postretirement benefit obligation, beginning of year	$	1,868		$	1,742
Service cost	51			49
Interest cost	91			91
Plan amendments	(207		)	(3		)
Actuarial loss	12			60
Medicare Part D subsidy	5			4
Benefits paid	(68		)	(75		)
Accumulated postretirement benefit obligation, end of year	$	1,752		$	1,868
Change in plan assets
Plan assets at fair value, beginning of year	$	651		$	682
Actual return on plan assets	88			(17		)
Company contributions	95			66
Benefits paid	(78		)	(80		)
Plan assets at fair value, end of year	$	756		$	651
Funded status, end of year	$	(996	)	$	(1,217	)
Amount recorded as:
Non-current liabilities	$	(996	)	$	(1,217	)
Amounts recognized in Regulatory assets (see Note 8)
Net actuarial loss	$	560		$	633
Prior service cost	(244		)	(53		)
Net transition obligation	—			2
	$	316		$	582

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	$	78
2014	82
2015	87
2016	91
2017	97
2018-2022	556
	$	991

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 $21 million and increased the accumulated benefit obligation by $218 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 $13 million and would have decreased the accumulated benefit obligation by $185 million at December 31, 2012.

The process used in determining the long-term rate of return for assets and the investment approach for the 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. 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 December 31, 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	$	1	$	—	$	2	$	1	$	8	$	—	$	9
Equity securities
U.S. Large Cap (c)	122		2		—		124		116		10		—		126
U.S. Small/Mid Cap (d)	70		—		—		70		46		4		—		50
Non U.S. (e)	151		4		—		155		116		10		—		126
Fixed income securities (f)	25		162		—		187		15		156		—		171
Hedge Funds and Similar Investments (g)	68		15		78		161		53		14		63		130
Private Equity and Other (h)	—		—		57		57		—		—		39		39
Total	$	437	$	184	$	135	$	756	$	347	$	202	$	102	$	651

_______________________________________

(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 Electric 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 Electric 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	$	63		$	39		$	102		$	52		$	36		$	88
Total realized/unrealized gains (losses):
Realized gains (losses)	4			(7		)	(3		)	(1		)	1			—
Unrealized gains (losses)	—			9			9			2			(14		)	(12		)
Purchases, sales and settlements:
Purchases	56			25			81			45			31			76
Sales	(45		)	(9		)	(54		)	(35		)	(15		)	(50		)
Ending Balance	$	78		$	57		$	135		$	63		$	39		$	102
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	4		$	1		$	5		$	3		$	(11	)	$	(8	)

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 $4 million in 2012, $5 million in 2011 and $5 million in 2010.

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Preferred and Preferenced Securities (Notes)

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

At December 31, 2012, DTE Electric had approximately 6.75 million shares of preferred stock with a par value of $100 per share and 30 million shares of preference stock with a par value of $1 per share authorized, with no shares issued.

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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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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 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. 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 January 1, 2012	$	1,442
Accretion	91
Revision in estimated cash flows	2
Liabilities incurred	26
Liabilities settled	(4		)
Asset retirement obligations at December 31, 2012	$	1,557

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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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 [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 1 [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership interest	63.00%
Belle River Unit 2 [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership interest	75.00%

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Property, Plant and Equipment (Notes)

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)
Generation	$	10,383		$	9,785
Distribution	7,306			7,003
Total	17,689			16,788
Less Accumulated Depreciation and Amortization
Generation	(3,880		)	(3,946		)
Distribution	(2,837		)	(2,580		)
Total	(6,717		)	(6,526		)
Net Property, Plant and Equipment	$	10,972		$	10,262

The Allowance for Funds used During Construction (AFUDC) capitalized during 2012 and 2011 was approximately $19 million and $9 million, respectively.

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

The average estimated useful life for our generation and distribution property was 40 years and 41 years, respectively, at December 31, 2012.

Capitalized software costs are classified as Property, plant and equipment and the related amortization is included in Accumulated depreciation 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 5 to 15 years.

Capitalized software costs amortization expense was $62 million in 2012, $58 million in 2011 and $55 million in 2010. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2012 were $479 million and $245 million, respectively. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2011 were $501 million and $218 million, respectively. Amortization expense of capitalized software costs is estimated to be approximately $40 million annually for 2013 through 2017.

Gross property under capital leases was $6 million and $26 million at December 31, 2012 and December 31, 2011, respectively. Accumulated amortization of property under capital leases was $3 million and $14 million at December 31, 2012 and December 31, 2011, respectively.

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Jointly Owned Utility Plant (Notes)

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 and purchased power 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:

				Ludington Hydroelectric
	Belle River			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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Regulatory Matters (Notes)

12 Months Ended

Dec. 31, 2012

Public Utilities, General Disclosures [Abstract]

REGULATORY MATTERS

REGULATORY MATTERS

Regulation

DTE Electric is 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 is 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
Assets	(In millions)
Recoverable pension and postretirement costs:
Pension	$	1,815		$	1,656
Postretirement costs	316			582
Asset retirement obligation	424			420
Recoverable Michigan income taxes	253			270
Recoverable income taxes related to securitized regulatory assets	226			316
Accrued PSCR revenue	87			147
Cost to achieve Performance Excellence Process	82			100
Other recoverable income taxes	76			81
Choice incentive mechanism	66			166
Recoverable restoration expense	49			58
Unamortized loss on reacquired debt	37			36
Enterprise Business Systems costs	16			18
Other	63			40
	3,510			3,890
Less amount included in current assets	(162		)	(272		)
	$	3,348		$	3,618
Securitized regulatory assets	$	413		$	577
Liabilities
Renewable energy	$	230		$	192
Refundable revenue decoupling / deferred gain	127			127
Asset removal costs	81			73
Over recovery of Securitization	54			53
Energy Optimization	26			24
Fermi 2 refueling outage	12			23
Refundable uncollectible expense	10			13
Low Income Energy Efficiency Fund	—			23
Other	9			6
	549			534
Less amount included in current liabilities	(66		)	(80		)
	$	483		$	454

As noted below, regulatory assets for which costs have been incurred have been included (or are expected to be included, for costs incurred subsequent to the most recently approved rate case) in DTE Electric'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 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. The Company records the impact of actuarial gains and losses and prior service 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 MBT was enacted by the State of Michigan. A State deferred tax liability was established, and an offsetting regulatory asset was recorded as the impact of the deferred tax liability will be reflected in rates as the related taxable temporary difference reverses and flows through current income tax expense. In May 2011, the MBT was repealed and the 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)

• Accrued PSCR 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.

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

• Other recoverable income taxes — Income taxes receivable from DTE Electric 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) — 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.

• 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 MPSC authorization. The restoration expense tracking mechanism 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.

• 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

• 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.

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

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

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

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

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

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

2009 Electric Rate Case Filing - Court of Appeals Decision

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 Court 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 case. 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 filed an application for approval of its reconciliation of its 2011 EO plan expenses. On October 31, 2012, the MPSC approved DTE Electric's reconciliation. The MPSC order also approved performance incentive surcharges for DTE Electric of $8.4 million to be applied to customer bills rendered on and after January 1, 2013.

In August 2012, DTE Electric filed an amended EO plan with the MPSC. The plan application proposed the recovery of EO expenditures for the period 2013-2015 of $224 million and further requested approval of a surcharge to recover these costs. On December 20, 2012, the MPSC approved DTE Electric's EO plan.

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 4.74mills/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.

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Regulatory Matters (Details Textuals) (USD $)	3 Months Ended	12 Months Ended		3 Months Ended		9 Months Ended		12 Months Ended
	Mar. 31, 2012	Dec. 31, 2012 people	Dec. 31, 2011	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]
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
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
Requested Recovery of Enery Optimization Expenses for Future Period Revised							224,000,000
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

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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%

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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	$ 267	$ 15	$ (89)
State and other income tax	67	21	37
Total current income taxes	334	36	(52)
Federal	(47)	193	297
State and other income tax	(5)	38	25
Total deferred income taxes	(52)	231	322
Total	$ 282	$ 267	$ 270

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Supplementary Quarterly Financial Information (Unaudited) (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
Quarterly Information [Line Items]
Other Postretirment Benefit Expense Adjustment	$ 9
Operating Revenues	1,262	1,542	1,289	1,198	1,203	1,517	1,240	1,192	5,291	5,152	4,993
Operating Income (Loss)	172	378	265	213	227	335	235	205	1,028	1,002	1,028
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 67	$ 195	$ 127	$ 97	$ 90	$ 158	$ 104	$ 85	$ 486	$ 437	$ 441

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Regulatory Matters (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Regulatory Asset and Liability [Line Items]
Regulatory Assets	$ 3,510	$ 3,890
Regulatory Assets, Current	(162)	(272)
Regulatory Assets, Noncurrent	3,348	3,618
Securitized Regulatory Assets, Noncurrent	413	577
Regulatory Liabilities	549	534
Regulatory Liability, Current	(66)	(80)
Regulatory Liability, Noncurrent	483	454
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
Asset Removal Costs [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	81	73
Over Recovery of Securitization [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	54	53
Energy Optimization [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	26	24
Refueling Outage [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	12	23
Refundable Uncollectible Expense [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	10	13
Low Income Energy Efficiency Fund [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	0	23
Other Liabilities [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Liabilities	9	6
Pension [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	1,815	1,656
Postretirment costs [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	316	582
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	253	270
Recoverable income taxes related to securitized regulatory assets [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	226	316
Accrued PSCR Revenue [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	87	147
Cost to Achieve Performance Excellence Process [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	82	100
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
Recoverable restoration expense [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	49	58
Unamortized loss on reacquired debt [Member]
Regulatory Asset and Liability [Line Items]
Regulatory Assets	37	36
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	$ 63	$ 40

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Retirement Benefits and Trusteed Assets (Details 12) (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	$ 78
Defined Benefit Plan, Expected Future Benefit Payments in 2014	82
Defined Benefit Plan, Expected Future Benefit Payments in 2015	87
Defined Benefit Plan, Expected Future Benefit Payments in 2016	91
Defined Benefit Plan, Expected Future Benefit Payments in 2017	97
Defined Benefit Plan, Expected Future Benefit Payments in 2018-2022	556
Total Expected Future Benefit Payments	$ (2,115)

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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 January 1, 2012	$	1,442
Accretion	91
Revision in estimated cash flows	2
Liabilities incurred	26
Liabilities settled	(4		)
Asset retirement obligations at December 31, 2012	$	1,557

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Fair Value (Details 3) (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

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Capital and Operating Leases (Notes)

12 Months Ended

Dec. 31, 2012

CAPITAL AND OPERATING LEASES [Abstract]

Capital and OPERATING LEASES [Text Block]

CAPITAL AND OPERATING LEASES

The Company leases various assets under capital and operating leases, including coal railcars, computers, vehicles and other equipment. The lease arrangements expire at various dates through 2023.

Future minimum lease payments under non-cancelable leases at December 31, 2012 were:

	Capital			Operating
	Leases			Leases
	(In millions)
2013	$	3		$	26
2014	1			21
2015	—			18
2016	—			16
2017	—			16
Thereafter	—			66
Total minimum lease payments	4			$	163
Less imputed interest	—
Present value of net minimum lease payments	4
Less current portion	(3		)
Non-current portion	$	1

Rental expense for operating leases was $29 million in 2012, $27 million in 2011, and $22 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.

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Supplementary Quarterly Financial Information (Unaudited) (Notes)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
									Year
2012	(In millions)
Operating Revenues	$	1,198	$	1,289	$	1,542	$	1,262	$	5,291
Operating Income (a)	213		265		378		172		1,028
Net Income	97		127		195		67		486
2011
Operating Revenues	1,192		1,240		1,517		1,203		5,152
Operating Income	205		235		335		227		1,002
Net Income	85		104		158		90		437

_______________________________________

(a) In the fourth quarter of 2012, the Company recorded an adjustment that decreased operating income by $9 million ($5 million after tax) to correct other postretirement benefit expenses reported in prior periods. This adjustment is not considered material to the operating results of any of the relevant periods.

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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	$ 1	$ 2
Ending Balance	1	1
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	1	1
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	102	88
Realized gains (losses)	(3)	0
Unrealized gains (losses)	9	(12)
Purchases	81	76
Sales	(54)	(50)
Ending Balance	135	102
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	5	(8)
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	63	52
Realized gains (losses)	4	(1)
Unrealized gains (losses)	0	2
Purchases	56	45
Sales	(45)	(35)
Ending Balance	78	63
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	4	3
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	39	36
Realized gains (losses)	(7)	1
Unrealized gains (losses)	9	(14)
Purchases	25	31
Sales	(9)	(15)
Ending Balance	57	39
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	1	(11)
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	321	324
Realized gains (losses)	9	1
Unrealized gains (losses)	5	(20)
Purchases	199	60
Sales	(171)	(44)
Ending Balance	363	321
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	15	(17)
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	205	206
Realized gains (losses)	13	(3)
Unrealized gains (losses)	(3)	1
Purchases	176	44
Sales	(153)	(43)
Ending Balance	238	205
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	11	3
Pension Plans, Defined Benefit [Member] | Private Equity and Other [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	116	118
Realized gains (losses)	(4)	4
Unrealized gains (losses)	8	(21)
Purchases	23	16
Sales	(18)	(1)
Ending Balance	125	116
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	$ 4	$ (20)

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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	$ 1	$ 2
Recorded in regulatory assets/liabilities	15	2
Purchases issuances and settlements [Abstract]
Settlements	(15)	(3)
Ending Balance	1	1
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	$ 1	$ 1

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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
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately	(In millions)
Accounts receivable, net	$	24		$	(62	)	$	—
Inventories	7			(53		)	(71		)
Recoverable pension and postretirement costs	106			(436		)	(26		)
Accrued pension liability — affiliates	137			271			(27		)
Accounts payable	(64		)	41			47
Income taxes payable/receivable	114			54			(77		)
Accrued postretirement liability — affiliates	(221		)	157			3
Regulatory assets	125			(18		)	(77		)
Other assets	108			(80		)	(54		)
Other liabilities	(78		)	(15		)	29
	$	258		$	(141	)	$	(253	)

Additional Supplementary Cash Flow Information [Table] [Table Text Block]

	2012		2011			2010
Cash paid (received) for:	(In millions)
Interest (excluding interest capitalized)	$	280	$	294		$	315
Income taxes	223		(18		)	28

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)
Change in capital expenditures not paid	$	(22	)	$	47	$	27

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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	$ 30	$ 13
Restricted cash, principally Securitization	102	127
Accounts receivable (less allowance for doubtful accounts of $XX and $80, respectively)
Customer	697	709
Affiliates	5	61
Other	63	76
Inventories
Fuel and gas	246	264
Materials and supplies	193	183
Notes receivable
Affiliates	0	26
Other	2	2
Regulatory assets	162	272
Other	77	63
Total Current Assets	1,577	1,796
Investments
Nuclear decommissioning trust funds	1,037	937
Other	133	121
Total Investments	1,170	1,058
Property
Property, plant and equipment	17,689	16,788
Less accumulated depreciation and amortization	(6,717)	(6,526)
Property, plant and equipment, net	10,972	10,262
Other Assets
Regulatory assets	3,348	3,618
Securitized regulatory assets	413	577
Intangible assets	30	36
Notes receivable	3	4
Other	138	142
Total Noncurrent Assets	3,932	4,377
Total Assets	17,651	17,493
Accounts payable
Affiliates	52	67
Accounts payable	350	421
Accrued interest	61	69
Current portion long-term debt, including capital leases	443	470
Regulatory liabilities	66	80
Short-term borrowing - affiliates	80	64
Short-term borrowing - other	130	0
Other	166	230
Total Current Liabilities	1,348	1,401
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	4,221	4,105
Securitization bonds	302	479
Capital lease obligations	1	9
Total Long-Term Debt (net of current portion)	4,524	4,593
Other Liabilities
Deferred income taxes	2,761	2,701
Regulatory liabilities	483	454
Asset retirement obligations	1,557	1,440
Unamortized investment tax credit	49	57
Nuclear decommissioning	159	148
Accrued pension liability — affiliates	1,368	1,231
Accrued postretirement liability — affiliates	996	1,217
Other	103	115
Total Noncurrent Liabilities	7,476	7,363
Shareholder’s Equity
Common stock, $10 par value, 400,000,000 shares authorized, and 138,632,324 shares issued and outstanding	3,196	3,196
Retained earnings	1,129	960
Accumulated other comprehensive loss	(22)	(20)
Total Shareholder's Equity	4,303	4,136
Total Liabilities and Shareholder's Equity	$ 17,651	$ 17,493

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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	$ 51	$ 49	$ 47
Interest cost	91	91	95
Expected return on plan assets	(61)	(62)	(52)
Net loss	58	40	38
Prior service cost	(16)	(15)	2
Net transition obligation	2	2	2
Net postretirement cost	$ 125	$ 105	$ 132

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Significant Accounting Policies (Note)

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 are recognized as services are provided. The Company records revenues for electricity provided but unbilled at the end of each month. Rates for DTE Electric include provisions to adjust billings for fluctuations in fuel and purchased power costs, 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 8 for further discussion of recovery mechanisms authorized by the MPSC.

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 and purchased power and net sales in Operating revenues on the Consolidated Statements of Operations. DTE Electric records net sale billing adjustments when invoices are received. DTE Electric records expense accruals for future net purchases adjustments based on historical experience, and reconciles accruals to actual expenses when invoices are received from MISO.

Comprehensive Income

Comprehensive income is the change in common shareholder’s 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 reflected changes in benefit obligations.

	Benefit			Accumulated Other Comprehensive
	Obligations			Loss
	(In millions)
Beginning balance January 1, 2012	$	(20	)	$	(20	)
Current period change	(2		)	(2		)
Ending balance December 31, 2012	$	(22	)	$	(22	)

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 agreements, related to Securitization bonds. 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 is generally calculated using the aging approach that utilizes rates developed in reserve studies. DTE Electric establishes 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.

Unbilled revenues of $275 million and $264 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 loans and 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.

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

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

Utility property is depreciated over its estimated useful life using straight-line rates approved by the MPSC.

Depreciation 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 8.

The cost of nuclear fuel is capitalized. The amortization of nuclear fuel is included within Fuel and purchased power 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 and renewable energy credits. 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’s intangible assets related to emission allowances were $6 million at December 31, 2012 and $9 million at December 31, 2011. The Company’s intangible assets related to renewable energy credits were $44 million and $39 million at December 31, 2012 and December 31, 2011, respectively.

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, the unamortized discount, premium and expense related to debt redeemed with a refinancing are amortized over the life of the replacement issue.

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.

Stock-Based Compensation

The Company received an allocation of costs from DTE Energy associated with stock-based compensation. Our allocation for 2012, 2011 and 2010 for stock-based compensation expense was approximately $42 million, $30 million and $23 million, respectively.

Government Grants

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

Other Accounting Policies

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

Note	Title
3	Fair Value
4	Financial and Other Derivative Instruments
7	Asset Retirement Obligations
8	Regulatory Matters
9	Income Taxes
15	Retirement Benefits and Trusteed Assets

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Property, Plant and Equipment (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment [Line Items]
Generation	$ 10,383	$ 9,785
Distribution	7,306	7,003
Total	17,689	16,788
Generation	(3,880)	(3,946)
Distribution	(2,837)	(2,580)
Total	(6,717)	(6,526)
Net Property, Plant and Equipment	$ 10,972	$ 10,262

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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	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Regulatory Assets		$ 3,510	$ 3,890
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Accumulated benefit obligation, end of year		3,307	2,963
Projected benefit obligation, beginning of year	3,196	3,196	2,899
Service cost		64	55	52
Interest cost		155	154	153
Actuarial loss		342	251
Settlements		2	2	0
Benefits paid		(174)	(165)
Projected benefit obligation, end of year		3,585	3,196	2,899
Plan assets at fair value, beginning of the yeard Benefit Plan, Fair Value of Plan Assets	1,957	1,957	1,936
Actual return on plan assets		220	(18)
Company contributions	275	208	204
Plan assets at fair value, end of the yeard Benefit Plan, Fair Value of Plan Assets		2,211	1,957	1,936
Funded status of the plan		(1,374)		(1,239)
Current liabilities		(6)	(8)
Noncurrent liabilities		(1,368)	(1,231)
Pension and Other Postretirement Defined Benefit Plans, Liabilities		(1,374)	(1,239)
Net actuarial loss		1,805	1,645
Prior service cost		10	11
Regulatory Assets		1,815	1,656
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Projected benefit obligation, beginning of year	1,868	1,868	1,742
Service cost		51	49	47
Interest cost		91	91	95
Actuarial loss		12	60
Benefits paid		(68)	(75)
Projected benefit obligation, end of year		1,752	1,868	1,742
Plan assets at fair value, beginning of the yeard Benefit Plan, Fair Value of Plan Assets	651	651	682
Actual return on plan assets		88	(17)
Company contributions	120	95	66
Plan assets at fair value, end of the yeard Benefit Plan, Fair Value of Plan Assets		756	651	682
Funded status of the plan		(996)	(1,217)
Noncurrent liabilities		(996)	(1,217)
Net actuarial loss		560	633
Prior service cost		(244)	(53)
Regulatory Assets		$ 316	$ 582

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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]
Tax Payable to or Receivable from Parent		$ 13,000,000	$ 48,000,000
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
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		(3,000,000)	1,000,000	1,000,000
Unrecognized Tax Benefits, Increases Resulting from Prior Period Tax Positions		0	45,000,000	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					30,000,000
Reduction of Net Deferred Tax Assets	0
Decrease in Deferred Tax Liabilities Attributaable to Regulated Utilities	342,000,000
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		$ 52,000,000

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Significant Accounting Policies Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Revenues [Policy Text Block]

Revenues

Revenues from the sale and delivery of electricity are recognized as services are provided. The Company records revenues for electricity provided but unbilled at the end of each month. Rates for DTE Electric include provisions to adjust billings for fluctuations in fuel and purchased power costs, 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 8 for further discussion of recovery mechanisms authorized by the MPSC.

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 and purchased power and net sales in Operating revenues on the Consolidated Statements of Operations. DTE Electric records net sale billing adjustments when invoices are received. DTE Electric records expense accruals for future net purchases adjustments based on historical experience, and reconciles accruals to actual expenses when invoices are received from MISO.

Comprehensive Income [Policy Text Block]

Comprehensive Income

Comprehensive income is the change in common shareholder’s equity during a period from transactions and events from non-owner sources, including net income.

Cash Equivalents and Restricted Cash [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 agreements, related to Securitization bonds. 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 is generally calculated using the aging approach that utilizes rates developed in reserve studies. DTE Electric establishes 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.

Unbilled revenues of $275 million and $264 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 loans and 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.

Property, Retirement, and Maintenance, and 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 an allowance for funds used during construction (AFUDC). The cost of properties retired is charged to accumulated depreciation. Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2.

Utility property is depreciated over its estimated useful life using straight-line rates approved by the MPSC.

Depreciation 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 8.

The cost of nuclear fuel is capitalized. The amortization of nuclear fuel is included within Fuel and purchased power 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 [Policy Text Block]

Intangible Assets

The Company has certain intangible assets relating to emission allowances and renewable energy credits. 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’s intangible assets related to emission allowances were $6 million at December 31, 2012 and $9 million at December 31, 2011. The Company’s intangible assets related to renewable energy credits were $44 million and $39 million at December 31, 2012 and December 31, 2011, respectively.

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, the unamortized discount, premium and expense related to debt redeemed with a refinancing are amortized over the life of the replacement issue.

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.

Government Grants [Policy Text Block]

Government Grants

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

Other Accounting Policies [Policy Text Block]

Other Accounting Policies

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

Note	Title
3	Fair Value
4	Financial and Other Derivative Instruments
7	Asset Retirement Obligations
8	Regulatory Matters
9	Income Taxes
15	Retirement Benefits and Trusteed Assets

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Preferred and Preferenced Securities (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2012
Preferred and Preferenced Securities [Line Items]
Preferred	6.75
Preferred	$ 100
Preference	30
Preference	$ 1
Preferred Stock, Shares Issued	0

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Capital and Operating Leases (Tables)

12 Months Ended

Dec. 31, 2012

CAPITAL AND OPERATING LEASES [Abstract]

Capital and Operating Leases [Table Text Block]

Future minimum lease payments under non-cancelable leases at December 31, 2012 were:

	Capital			Operating
	Leases			Leases
	(In millions)
2013	$	3		$	26
2014	1			21
2015	—			18
2016	—			16
2017	—			16
Thereafter	—			66
Total minimum lease payments	4			$	163
Less imputed interest	—
Present value of net minimum lease payments	4
Less current portion	(3		)
Non-current portion	$	1

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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 Electric has a $300 million unsecured revolving credit agreement with a syndicate of 20 banks that may be used for general corporate borrowings, but is intended to provide liquidity support for the Company's commercial paper program. No one bank provides more than 8.5% of the commitment in the facility. Borrowings under the facility are available at prevailing short-term interest rates. The facility will expire in October 2016. At December 31, 2012, there was $130 million outstanding against this facility, while there were no amounts outstanding against this facility at December 31, 2011.

The agreement requires 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 consolidatedsubsidiaries, including capital lease obligations, hedge agreements and guarantees of third parties' debt, but excluding contingent obligations and nonrecourse and junior subordinated 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 ratio for DTE Electric was 0.52 to 1.

The weighted average interest rate for short-term borrowings was 0.4% at December 31, 2012.

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Related Party Transactions Related Party Transactions (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Related Party Transaction [Line Items]
Charitable Contributions to a Foundation	$ 21	$ 13