UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________________________________________

Form 10-K

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

Commission file number 1-2198

The Detroit Edison 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.

THE DETROIT EDISON 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 (§ 232.405 of this chapter) 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

The Detroit Edison Company

Annual Report on Form 10-K

Year Ended December 31, 2011

Table of Contents

	Page
Definitions	1
Forward-Looking Statements	3
Part I
Items 1. & 2. Business and Properties	4
Items 1A. Risk Factors	7
Items 1B. Unresolved Staff Comments	10
Item 3. Legal Proceedings	10
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	61
Item 9A. Controls and Procedures	61
Item 9B. Other Information	61
Part III
Item 10. Directors, Executive Officers and Corporate Governance	61
Item 11. Executive Compensation	61
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	61
Item 13. Certain Relationships and Related Transactions, and Director Independence	61
Item 14. Principal Accountant Fees and Services	61
Part IV
Item 15. Exhibits and Financial Statement Schedules	62
Signatures	70
EX-12.42
EX-23.26
EX-31.71
EX-31.72
EX-32.71
EX-32.72
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 Detroit Edison to recover or refund non-fuel revenues lost or gained as a result of fluctuations in electric Customer Choice sales.
CTA	Costs to achieve, consisting of project management, consultant support and employee severance, related to the Performance Excellence Process.
Customer Choice	Michigan legislation giving customers the option to choose alternative suppliers for electricity.
Detroit Edison	The Detroit Edison Company ( a direct wholly owned subsidiary of DTE Energy) and subsidiary companies
DTE Energy	DTE Energy Company, directly or indirectly the parent of Detroit Edison, Michigan Consolidated 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 Detroit Edison to recover through rates its fuel, fuel-related and purchased power costs.
RDM	A Revenue Decoupling Mechanism authorized by the MPSC that is designed to minimize the impact on revenues of changes in average customer usage of electricity
Securitization	Detroit Edison financed specific stranded costs at lower interest rates through the sale of rate reduction bonds by a wholly-owned special purpose entity, The Detroit Edison Securitization Funding LLC.

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VIE Variable Interest Entity

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

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FORWARD-LOOKING STATEMENTS

Certain information presented herein includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 with respect to the financial condition, results of operations and business of Detroit Edison. 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;

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

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

• the timing and extent of changes in interest rates;

• the level of borrowings;

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

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

• 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 refer only as of the date on which such statements are made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.

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Part I

Items 1. and 2. Business and Properties

General

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

References in this report to “we,” “us,” “our” or “Company” are to Detroit Edison.

Our generating plants are regulated by numerous federal and state governmental agencies, including, but not limited to, the MPSC, the FERC, the NRC, the EPA and the MDEQ. Electricity is generated from our fossil-fuel plants, a hydroelectric pumped storage plant and a nuclear plant, and is purchased from electricity generators, suppliers and wholesalers. The electricity we produce and purchase is sold to three major classes of customers: residential, commercial and industrial, principally throughout southeastern Michigan.

Revenue by Service

(in Millions)	2011		2010		2009
Residential	$	2,182	$	2,052	$	1,820
Commercial	1,704		1,629		1,702
Industrial	692		688		730
Other	456		479		299
Subtotal	5,034		4,848		4,551
Interconnection sales (1)	118		145		163
Total Revenue	$	5,152	$	4,993	$	4,714

_________________________________

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

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

Fuel Supply and Purchased Power

Our power is generated from a variety of fuels and is supplemented with purchased power. We expect to have an adequate supply of fuel and purchased power to meet our obligation to serve customers. Our generating capability is heavily dependent upon the availability of coal. Coal is purchased from various sources in different geographic areas under agreements that vary in both pricing and terms. We expect to obtain the majority of our coal requirements through long-term contracts, with the balance to be obtained through short-term agreements and spot purchases. We have long-term and short term contracts for the purchase of approximately 29 million tons of low-sulfur western coal to be delivered from 2012 through 2014 and approximately 6 million tons of Appalachian coal to be delivered from 2012 through 2014. All of these contracts have pricing schedules. We have approximately 95% of our 2012 expected coal requirements under contract. Given the geographic diversity of supply, we believe we can meet our expected generation requirements. We lease a fleet of rail cars and have our expected western rail requirements under contract for the next four years. All of our expected eastern coal rail requirements are under contract through 2012 and approximately 50% of this requirement is under contract in 2013. Our expected vessel transportation requirements for delivery of purchased coal to our generating facilities are under contract through 2014.

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

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Properties

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

Generating plants owned and in service as of December 31, 2011 are as follows:

	Location by Michigan	Summer Net Rated Capability (1)
Plant Name	County	(MW)	(%)	Year in Service
Fossil-fueled Steam-Electric
Belle River (2)	St. Clair	1,047	10.0	1984 and 1985
Greenwood	St. Clair	782	7.5	1979
Harbor Beach	Huron	93	0.9	1968
Monroe (3)	Monroe	2,893	27.7	1971, 1973 and 1974
River Rouge	Wayne	525	5.0	1957 and 1958
St. Clair	St. Clair	1,382	13.3	1953, 1954, 1959, 1961 and 1969
Trenton Channel	Wayne	674	6.5	1949 and 1968
		7,396	70.9
Oil or Gas-fueled Peaking Units	Various	1,026	9.8	1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric Fermi 2 (4)	Monroe	1,086	10.4	1988
Hydroelectric Pumped Storage Ludington (5)	Mason	917	8.9	1973
		10,425	100.0

_______________________________________

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

(2) The Belle River capability represents Detroit Edison's entitlement to 81% of the capacity and energy of the plant. See Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.

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

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

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

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

In 2008, a renewable portfolio standard was established for Michigan electric providers targeting 10% of electricity sold to retail customers from renewable energy by 2015. Detroit Edison has approximately 500 MW of owned or contracted renewable energy under contract at December 31, 2011 representing approximately 6% of electricity sold to retail customers. Approximately 120 MW is in commercial operation at December 31, 2011 with an additional 380 MW expected in commercial operation in 2012 or early 2013.

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

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

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

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

Regulation

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

See Notes 3, 7, 9 and 15 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Energy Assistance Programs

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

Strategy and Competition

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

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

The electric Customer Choice program in Michigan allows all of our electric customers to purchase their electricity from alternative electric suppliers of generation services, subject to limits. Customers choosing to purchase power from alternative electric suppliers represented approximately 10% of retail sales in 2011 and 2010 and 3% of retail sales in 2009. Customers participating in the electric Customer Choice program consist primarily of industrial and commercial customers whose MPSC-authorized full service rates exceed market costs. MPSC rate orders and 2008 energy legislation enacted by the State of Michigan are adjusting the pricing disparity over five years and have placed a 10% cap on the total potential Customer Choice related migration, mitigating some of the unfavorable effects of electric Customer Choice on our financial performance. In addition, we had a Choice Incentive Mechanism, which was an over/under recovery mechanism that measured non-fuel revenues lost or gained as a result of fluctuations in electric Customer Choice sales. Effective with the October 2011 MPSC rate order, this mechanism has been terminated and our customer rates reflect the current level of electric Customer Choice sales. We expect that in 2012 customers choosing to purchase power from alternative electric suppliers will represent approximately 10% of retail sales.

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

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ENVIRONMENTAL MATTERS

We are subject to extensive environmental regulation. Additional costs may result as the effects of various substances on the environment are studied and governmental regulations are developed and implemented. Actual costs to comply could vary substantially. We expect to continue recovering environmental costs through rates charged to our customers. The following table summarizes our estimated significant future environmental expenditures based upon current regulations:

(in Millions)
Air	$	1,921
Water	80
Contaminated and other sites	17
Estimated total future expenditures through 2021	$	2,018
Estimated 2012 expenditures	$	255
Estimated 2013 expenditures	$	311

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

Water - In response to an EPA regulation, Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of completed studies and expected future studies, Detroit Edison may be required to install additional control technologies to reduce the impacts of the water intakes. In addition, there are proposed rules that may require the installation of cooling towers at some facilities at a cost substantially greater than was initially estimated for other mitigative technologies. The EPA has also issued an information collection request to begin a review of steam electric effluent guidelines.

Contaminated and Other Sites - Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. The facilities, which produced gas, have been designated as manufactured gas plant (MGP) sites. Detroit Edison 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, 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.

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 9 and 15 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

EMPLOYEES

We had approximately 4,800 employees as of December 31, 2011, of which approximately 2,800 were represented by unions. The majority of our union employees are under contracts that expire in August 2012 and June 2013.

Item 1A. Risk Factors

There are various risks associated with the operations of Detroit Edison. 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

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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 final rates authorized by our regulators in the final rate order are lower than the amounts we collected during the self-implementation period, we must refund the difference with interest. Our regulators may also disagree with our rate calculations under the various tracking and decoupling mechanisms that are intended to mitigate the risk of certain aspects of our business. If we cannot agree with our regulators on an appropriate reconciliation of those mechanisms, it may impact our ability to recover certain costs through our customer rates. Our regulators may also decide to eliminate more of these mechanisms in future rate cases, which may make it more difficult for us to recover our costs in the rates we charge customers. We cannot predict what rates an MPSC order will adopt in future rate cases.New legislation, regulations or interpretations could change how our business operates, impact our ability to recover costs through rates or require us to incur additional expenses.

Changes to Michigan's electric Customer Choice program could negatively impact our financial performance.  The electric Customer Choice program, as originally contemplated in Michigan, anticipated an eventual transition to a totally deregulated and competitive environment where customers would be charged market-based rates for their electricity. The State of Michigan currently experiences a hybrid market, where the MPSC continues to regulate electric rates for our customers, while alternative electric suppliers charge market-based rates. In addition, such regulated electric rates for certain groups of our customers exceed the cost of service to those customers. Due to distorted pricing mechanisms during the initial implementation period of electric Customer Choice, many commercial customers chose alternative electric suppliers. MPSC rate orders and 2008 energy legislation enacted by the State of Michigan are phasing out the pricing disparity over five years and have placed a 10 percent cap on the total potential Customer Choice related migration. However, even with the electric Customer Choice-related relief received in recent Detroit Edison rate orders and the legislated 10 percent cap on participation in the electric Customer Choice program, there continues to be legislative and financial risk associated with the electric Customer Choice program. Electric Customer Choice migration is sensitive to market price and full service electric price changes.

Regional and national economic conditions can have an unfavorable impact on us.  Our business follows the economic cycles of the customers we serve and the credit risk of counterparties we do business with. We provide services to the domestic automotive and steel industries which have undergone considerable financial distress, exacerbating the decline in regional economic conditions. Should national or regional economic conditions deteriorate, reduced volumes of electricity, collections of accounts receivable, and reductions in federal and state energy assistance funding could result in decreased earnings and cash flow.

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.

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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 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 credit rating may require us to post collateral related to various physical or financially settled contracts for the purchase of energy-related commodities, products and services, which could impact our liquidity.

Our ability to access capital markets is important.  Our ability to access capital markets is important to operate our businesses. In the past, turmoil in credit markets has constrained, and may again in the future constrain, our ability as well as the ability of our subsidiaries to issue new debt, including commercial paper, and refinance existing debt at reasonable interest rates. In addition, the level of borrowing by other energy companies and the market as a whole could limit our access to capital markets. Our long term revolving credit facility does not expire until 2015, 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.

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

Construction and capital improvements to our power facilities 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 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.

9

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

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

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

In addition, our generation plants 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 Detroit Edison 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 2,800 of our employees. Our contract with one union representing about 500 of our electrical linemen is due to expire in August 2012. We cannot predict the outcome of those negotiations. A union choosing to strike would have an impact on our business. We are unable to predict the effect a work stoppage would have on our costs of operation and financial performance.

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

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

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

10

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

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

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

DTE Energy and Detroit Edison believe that the plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of discussions with the EPA regarding the two NOVs/FOVs, Detroit Edison could 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 Detroit Edison cannot predict the financial impact or outcome of these matters, or the timing of its resolution.

For additional discussion on legal matters, see Notes 9 and 15 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 Detroit Edison, par value $10 per share, are owned by DTE Energy, and constitute 100% of the voting securities of Detroit Edison. Therefore, no market exists for our common stock.

We paid cash dividends on our common stock of $305 million in 2011, 2010, and 2009.

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 Detroit Edison is presented in accordance with General Instruction I (2) (a) of Form 10-K for wholly-owned subsidiaries (reduced disclosure format).

(in Millions)	2011		2010			2009
Operating Revenues	$	5,152	$	4,993		$	4,714
Fuel and purchased power	1,716		1,580			1,491
Gross margin	3,436		3,413			3,223
Operation and maintenance	1,369		1,305			1,277
Depreciation and amortization	813		849			844
Taxes other than income	240		237			205
Asset (gains) losses and reserves, net	12		(6		)	(2		)
Operating Income	1,002		1,028			899
Other (Income) and Deductions	298		317			295
Income Tax Expense	267		270			228
Net Income	$	437	$	441		$	376

Gross margin increased $23 million in 2011 and increased $190 million in 2010. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statement of Operations. The following table details changes in various gross margin components relative to the comparable prior period:

(in Millions)	2011			2010
Rate case and Choice Incentive mechanism, net of Revenue Decoupling mechanism and sales volume	$	29		$	84
Restoration tracker	27			35
Securitization bond and tax surcharge	(39		)	40
Low Income Energy Efficiency Fund revenue deferral	(23		)	—
Energy optimization performance incentive	17			—
Regulatory mechanisms and other	12			31
Increase in gross margin	$	23		$	190

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

_________________________________

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

12

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

_________________________________

(1) Represents fuel costs associated with power plants.

Operation and maintenance expense increased $64 million in 2011 and increased $28 million in 2010. The increase in

2011 is primarily due to higher restoration and line clearance expenses of $41 million, higher generation

maintenance and outage expenses of $25 million, higher energy optimization and renewable energy expenses of $19 million,

higher employee benefit expense of $9 million, partially offset by reduced contributions of $23 million to the Low Income

Energy Efficiency Fund due to a court order, and reduced uncollectible expenses of $7 million. The increase in 2010 is

primarily due to higher restoration and line clearance expenses of $40 million, higher energy optimization and renewable

energy expenses of $18 million, higher legal expenses of $15 million, partially offset by reduced uncollectible expenses of

$20 million, lower generation expenses of $18 million and lower employee benefit-related expenses of $6 million.

Depreciation and amortization expense decreased $36 million in 2011 due primarily to reduced amortization of regulatory assets, partially offset by expense related to higher depreciable base. Depreciation and amortization expense was $5 million higher in 2010 due primarily to expense related to higher depreciable base and increased amortization of regulatory assets.

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

Asset (gains) and losses, reserves and impairments, net increased $18 million in 2011 principally attributable to an accrual of $19 million resulting from management's revisions of the timing and estimate of cash flows for the decommissioning of Fermi 1, partially offset by a revision of $6 million in the timing and estimate of cash flows for the Fermi 1 asbestos removal obligation and other items. See Note 7 of the Notes to the Consolidated Financial Statements.

Outlook  - The base rate and rehearing orders approved by the MPSC in fourth quarter 2011 provide for an annual revenue increase of $188 million and an authorized return on equity of 10.5%. The base rate order terminated Detroit Edison's Restoration, Line Clearance and Uncollectible Expense tracking mechanisms. Termination of these trackers may result in increased volatility in Detroit Edison's results due to weather, the number of storms and uncollectible accounts receivable. The Choice Incentive Mechanism was also terminated in the base rate order. Base rates included electric Customer Choice sales at the capped 10 percent level. See Note 9 of Notes to the Consolidated Financial Statements for further discussion of the rate orders received by Detroit Edison.

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

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

Detroit Edison had an uncollectible expense tracking mechanism that enabled it to recover or refund 80 percent of the difference between the actual uncollectible expense each year and the level established in its last rate case. In October 2011, Detroit Edison's electric rate order terminated its uncollectible expense tracking mechanism. See Note 9 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

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

Interest Rate Risk

Detroit Edison 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, 2011 would decrease $167 million and increase $179 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 Cash Flows	19
Consolidated Statements of Financial Position	20
Consolidated Statements of Changes in Shareholder’s Equity and Comprehensive Income	22
Notes to Consolidated Financial Statements	23
Financial Statement Schedule
Schedule II — Valuation and Qualifying Accounts	69

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 Detroit Edison’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2011, which is the end of the period covered by this report. Based on this evaluation, the Company’s CEO and CFO have concluded that such disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) is accumulated and communicated to the Company’s management, including its CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.

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

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Internal control over financial reporting is a process designed by, or under the supervision of, our CEO and CFO, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

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

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

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, 2011 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 The Detroit Edison Company:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of The Detroit Edison Company and its subsidiaries at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying indexpresents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. 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 16, 2012

17

The Detroit Edison Company

Consolidated Statements of Operations

	Year Ended December 31
(in Millions)	2011			2010			2009
Operating Revenues	$	5,152		$	4,993		$	4,714
Operating Expenses
Fuel and purchased power	1,716			1,580			1,491
Operation and maintenance	1,369			1,305			1,277
Depreciation and amortization	813			849			844
Taxes other than income	240			237			205
Asset (gains) losses and reserves, net	12			(6		)	(2		)
	4,150			3,965			3,815
Operating Income	1,002			1,028			899
Other (Income) and Deductions
Interest expense	289			313			325
Interest income	—			(1		)	(2		)
Other income	(47		)	(39		)	(39		)
Other expenses	56			44			11
	298			317			295
Income Before Income Taxes	704			711			604
Income Tax Expense	267			270			228
Net Income	$	437		$	441		$	376

See Notes to Consolidated Financial Statements

18

The Detroit Edison Company

Consolidated Statements of Cash Flows

	Year Ended December 31
(in Millions)	2011			2010			2009
Operating Activities
Net income	$	437		$	441		$	376
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	813			849			844
Deferred income taxes	231			322			15
Asset (gains) losses and reserves, net	13			(6		)	(2		)
Changes in assets and liabilities, exclusive of changes shown separately (Note 17)	(141		)	(253		)	(39		)
Net cash from operating activities	1,353			1,353			1,194
Investing Activities
Plant and equipment expenditures	(1,202		)	(864		)	(793		)
Restricted cash for debt redemption	(3		)	(25		)	5
Notes receivable from affiliate	77			(21		)	(42		)
Proceeds from sale of nuclear decommissioning trust fund assets	80			377			295
Investment in nuclear decommissioning trust funds	(97		)	(410		)	(315		)
Other investments	(32		)	(60		)	(46		)
Net cash used for investing activities	(1,177		)	(1,003		)	(896		)
Financing Activities
Issuance of long-term debt	609			614			129
Redemption of long-term debt	(554		)	(652		)	(278		)
Short-term borrowings, net	—			—			(75		)
Short-term borrowings from affiliate	64			—			—
Capital contribution by parent company	—			—			250
Dividends on common stock	(305		)	(305		)	(305		)
Other	(7		)	(11		)	(15		)
Net cash used for financing activities	(193		)	(354		)	(294		)
Net Increase (Decrease) in Cash and Cash Equivalents	(17		)	(4		)	4
Cash and Cash Equivalents at Beginning of the Period	30			34			30
Cash and Cash Equivalents at End of the Period	$	13		$	30		$	34

See Notes to Consolidated Financial Statements

19

The Detroit Edison Company

Consolidated Statements of Financial Position

	December 31
(in Millions)	2011			2010
ASSETS
Current Assets
Cash and cash equivalents	$	13		$	30
Restricted cash, principally Securitization	127			104
Accounts receivable (less allowance for doubtful accounts of $80 and $93, respectively)
Customer	709			690
Affiliates	61			8
Other	76			204
Inventories
Fuel	264			224
Materials and supplies	183			170
Notes receivable
Affiliates	26			97
Other	2			—
Regulatory assets	272			58
Other	63			51
	1,796			1,636
Investments
Nuclear decommissioning trust funds	937			939
Other	121			118
	1,058			1,057
Property
Property, plant and equipment	16,788			16,068
Less accumulated depreciation and amortization	(6,526		)	(6,418		)
	10,262			9,650
Other Assets
Regulatory assets	3,618			3,277
Securitized regulatory assets	577			729
Intangible assets	36			25
Notes receivable
Affiliates	—			6
Other	4			—
Other	142			142
	4,377			4,179
Total Assets	$	17,493		$	16,522

See Notes to Consolidated Financial Statements

20

The Detroit Edison Company

Consolidated Statements of Financial Position

	December 31
(in Millions, Except Shares)	2011			2010
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Accounts payable
Affiliates	$	67		$	50
Other	421			349
Accrued interest	69			81
Current portion long-term debt, including capital leases	470			308
Regulatory liabilities	27			60
Short-term borrowing - affiliates	64			—
Other	283			279
	1,401			1,127
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	4,105			4,046
Securitization bonds	479			643
Capital lease obligations	9			20
	4,593			4,709
Other Liabilities
Deferred income taxes	2,701			2,235
Regulatory liabilities	454			714
Asset retirement obligations	1,440			1,354
Unamortized investment tax credit	57			67
Nuclear decommissioning	148			149
Accrued pension liability — affiliates	1,231			960
Accrued postretirement liability — affiliates	1,217			1,060
Other	115			138
	7,363			6,677
Commitments and Contingencies (Notes 9 and 15)
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	960			829
Accumulated other comprehensive income (loss)	(20		)	(16		)
	4,136			4,009
Total Liabilities and Shareholder’s Equity	$	17,493		$	16,522

See Notes to Consolidated Financial Statements

21

The Detroit Edison Company

Consolidated Statements of Changes in Shareholder’s Equity and Comprehensive income

				Additional					Accumulated Other
	Common Stock			Paid-in		Retained			Comprehensive
(Dollars in Millions, Shares in Thousands)	Shares	Amount		Capital		Earnings			Income (Loss)			Total
Balance, December 31, 2008	138,632	$	1,386	$	1,560	$	622		$	(12	)	$	3,556
Net income	—	—		—		376			—			376
Dividends declared on common stock	—	—		—		(305		)	—			(305		)
Net change in unrealized gains on investments, net of tax	—	—		—		—			(2		)	(2		)
Benefit obligations, net of tax	—	—		—		—			(2		)	(2		)
Capital contribution by parent company	—	—		250		—			—			250
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

The following table displays comprehensive income:

(in Millions)	2011			2010		2009
Net income	$	437		$	441	$	376
Other comprehensive income:
Net change in unrealized gains (losses) on investments, net of tax of $—, $— and $(1)	—			—		(2		)
Benefit obligations, net of tax of $(2), $— and $(1)	(4		)	—		(2		)
Comprehensive income	$	433		$	441	$	372

See Notes to Consolidated Financial Statements

22

The Detroit Edison Company

Notes to Consolidated Financial Statements

NOTE 1 — BASIS OF PRESENTATION

Corporate Structure

Detroit Edison is an electric utility engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan. Detroit Edison 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 Detroit Edison and its subsidiaries, collectively.

Basis of Presentation

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

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

Principles of Consolidation

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

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

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

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

In 2001, Detroit Edison financed a regulatory asset related to Fermi 2 and certain other regulatory assets through the sale of rate reduction bonds by a wholly-owned special purpose entity, Securitization. Detroit Edison performs servicing activities including billing and collecting surcharge revenue for Securitization. This entity is a VIE, and is consolidated by the Company. 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, 2011 and December 31, 2010 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,
(in Millions)	2011		2010
ASSETS
Restricted cash	$	107	$	104
Accounts receivable	34		42
Securitized regulatory assets	577		729
Other assets	10		13
	$	728	$	888
LIABILITIES
Accounts payable and accrued current liabilities	$	14	$	17
Other current liabilities	55		62
Current portion long-term debt, including capital leases	164		150
Securitization bonds	479		643
Other long term liabilities	7		6
	$	719	$	878

As of December 31, 2011 and December 31, 2010, Detroit Edison had $4 million and $6 million in Notes receivable, respectively, related to non-consolidated VIEs.

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 Detroit Edison 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 and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are recorded on the Consolidated Statement of Financial Position and are recovered or returned to customers through adjustments to the billing factors.

Detroit Edison had a CIM, which was an over/under recovery mechanism that measured non-fuel revenues lost or gained as a result of fluctuations in electric Customer Choice sales. If annual electric Customer Choice sales exceeded the baseline amount from Detroit Edison's most recent rate case, 90 percent of its lost non-fuel revenues associated with sales above that level may be recovered from full service customers. If annual electric Customer Choice sales decreased below the baseline, the Company must refund 90 percent of its increase in non-fuel revenues associated with sales below that level to full service customers. The CIM was terminated effective with the October 20, 2011 MPSC rate order. On January 17, 2012, Detroit Edison filed an application with the MPSC for approval of its CIM reconciliation for 2011.

Detroit Edison had an RDM in place in 2011, designed to minimize the impact on revenues of changes in average customer usage of electricity. The RDM enabled Detroit Edison to recover or refund the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established in the MPSC order. The 2011 pilot RDM established in Detroit Edison's 2009 rate case was terminated by the MPSC in October 2011, but the Company has requested rehearing on this point asserting the termination should have occurred in April 2011. Detroit Edison will have a newly designed RDM that will be effective in April 2012. See Note 9 for further discussion of the newly designed RDM.

See Note 9 for further discussion of recovery mechanisms authorized by the MPSC.

Accounting for ISO Transactions

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

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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, 2011 reflected changes in benefit obligations.

	Benefit			Accumulated Other Comprehensive
(in Millions)	Obligations			Loss
Beginning balance	$	(16	)	$	(16	)
Current period change	(4		)	(4		)
Ending balance	$	(20	)	$	(20	)

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. Detroit Edison 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, generally one year after service has been terminated.

Unbilled revenues of $264 million and $236 million are included in customer accounts receivable at December 31, 2011 and 2010, respectively.

Notes Receivable

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

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

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

Inventories

The Company generally values inventory at average cost.

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, including the cost of removal, less salvage value is charged to

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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.

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

Approximately $23 million and $3 million of expenses related to Fermi 2 refueling outages were accrued at December 31, 2011 and December 31, 2010, respectively. Amounts are accrued on a pro-rata basis over an 18-month period that coincides with scheduled refueling outages at Fermi 2. This accrual of outage costs matches the regulatory recovery of these costs in rates set by the MPSC. See Note 5.

The cost of nuclear fuel is capitalized. The amortization of nuclear fuel is included within Fuel and purchased power in the Consolidated Statement 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 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 $9 million at December 31, 2011 and 2010. The Company’s intangible assets related to renewable energy credits were $27 million and $17 million at December 31, 2011 and December 31, 2010, 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 2011, 2010 and 2009 for stock-based compensation expense was approximately $30 million, $23 million and $24 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
9	Regulatory Matters
10	Income Taxes
16	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, 2011 and December 31, 2010. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

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

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

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

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

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

							Net Balance at
(in Millions)	Level 1		Level 2		Level 3		December 31, 2011
Assets:
Nuclear decommissioning trusts	$	577	$	360	$	—	$	937
Other investments	55		54		—		109
Derivative assets — FTRs	—		—		1		1
Total	$	632	$	414	$	1	$	1,047

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							Net Balance at
(in Millions)	Level 1		Level 2		Level 3		December 31, 2011
Assets:
Current	$	—	$	—	$	1	$	1
Noncurrent(1)	632		414		—		1,046
Total Assets	$	632	$	414	$	1	$	1,047

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

								Net Balance at
(in Millions)	Level 1		Level 2			Level 3		December 31, 2010
Assets:
Nuclear decommissioning trusts	$	599	$	340		$	—	$	939
Other investments	52		55			—		107
Derivative assets — FTRs	—		—			2		2
Total	$	651	$	395		$	2	$	1,048
Liabilities:
Derivative liabilities — Emissions	—		(3		)	—		(3		)
Total	$	—	$	(3	)	$	—	$	(3	)
Net Assets at December 31, 2010	$	651	$	392		$	2	$	1,045

								Net Balance at
(in Millions)	Level 1		Level 2			Level 3		December 31, 2010
Assets:
Current	$	—	$	—		$	2	$	2
Noncurrent(1)	651		395			—		1,046
Total Assets	$	651	$	395		$	2	$	1,048
Liabilities:
Current	$	—	$	(3	)	$	—	$	(3	)
Total Liabilities	$	—	$	(3	)	$	—	$	(3	)
Net Assets at December 31, 2010	$	651	$	392		$	2	$	1,045

_________________________________

(1) Includes $109 and $107 million of other investments that are included in the Consolidated Statements of Financial Position in Other Investments at December 31, 2011 and December 31, 2010, respectively.

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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, 2011 and 2010:

	Year Ended December 31
(in Millions)	2011			2010
Net Assets as of January 1	$	2		2
Change in fair value recorded in regulatory assets/liabilities	2			6
Purchases, issuances and settlements:
Settlements	(3		)	(6		)
Net Assets as of December 31	$	1		$	2
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, 2011 and 2010	$	1		$	2

Transfers in and transfers out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level and for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. Transfers in and transfers out of Level 3 are reflected as if they had occurred at the beginning of the period. No transfers between Levels 1, 2 or 3 occurred in the years ended December 31, 2011 and December 31, 2010.

Nuclear Decommissioning Trusts and Other Investments

The nuclear decommissioning trusts and other investments hold debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices in actively traded markets. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued based on the underlying securities, using quoted prices in actively traded markets. Non-exchange-traded fixed income securities are valued based upon quotations available from brokers or pricing services. A primary price source is identified by asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustees determine that another price source is considered to be preferable. 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 long-term debt is determined by using quoted market prices when available and a discounted cash flow analysis based upon estimated current borrowing rates when quoted market prices are not available. The table below shows the fair value and the carrying value for long-term debt securities. Certain other financial instruments, such as notes payable, customer deposits and notes receivable are not shown as carrying value approximates fair value. See Note 4 for further fair value information on financial and derivative instruments.

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	December 31, 2011		December 31, 2010
	Fair Value	Carrying Value	Fair Value	Carrying Value
Long-Term Debt	$5.7 billion	$5.1 billion	$5.3 billion	$5.0 billion

Nuclear Decommissioning Trust Funds

Detroit Edison has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. This obligation is reflected as an asset retirement obligation on the Consolidated Statements of Financial Position. Rates approved by the MPSC provide for the recovery of decommissioning costs of Fermi 2 and the disposal of low-level radioactive waste. Detroit Edison is continuing to fund FERC jurisdictional amounts for decommissioning even though explicit provisions are not included in FERC rates. See Note 7.

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

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

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

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

	Year Ended December 31
(in Millions)	2011			2010			2009
Realized gains	$	46		$	192		$	37
Realized losses	$	(38	)	$	(83	)	$	(55	)
Proceeds from sales of securities	$	80		$	377		$	295

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

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

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

Unrealized losses incurred by the Fermi 2 trust are recognized as a Regulatory asset. Detroit Edison recognized $67 million and $26 million of unrealized losses as Regulatory assets at December 31, 2011 and 2010, respectively. Since the decommissioning of Fermi 1 is funded by Detroit Edison rather than through a regulatory recovery mechanism, there is no corresponding regulatory asset treatment. Therefore, unrealized losses incurred by the Fermi 1 trust are recognized in earnings immediately. There were no unrealized losses recognized in 2011, 2010 and 2009 for Fermi 1.

Other Available-For-Sale Securities

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

	December 31, 2011				December 31, 2010
(in Millions)	Fair Value		Carrying value		Fair Value		Carrying Value
Cash equivalents	$	129	$	129	$	125	$	125
Equity securities	4		4		4		4

As of December 31, 2011 and 2010, these securities are comprised primarily of money-market and equity securities. Gains related to trading securities held at December 31, 2011, 2010 and 2009 were $3 million, $7 million and $8 million, respectively.

NOTE 4 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

The Company recognizes all derivatives at their fair value 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.

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Detroit Edison’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. Detroit Edison generates, purchases, distributes and sells electricity. Detroit Edison uses forward energy and capacity contracts to manage changes in the price of electricity and fuel. Substantially all of these contracts meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. Other derivative contracts are recoverable through the PSCR mechanism when settled. This results in the deferral of unrealized gains and losses as Regulatory assets or liabilities, until realized.

The following represents the fair value of derivative instruments as of December 31, 2011 and 2010:

	Year Ended December 31
(in Millions)	2011		2010
FTRs — Other current assets	$	1	$	2
Emissions — Other current liabilities	—		(3		)
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 $3 million in gains related to FTRs recognized in Regulatory Liabilities for the year ended December 31, 2011, and $1 million in losses related to Emissions recognized in Regulatory assets and $6 million in gains related to FTRs recognized in Regulatory liabilities for the year ended December 31, 2010.

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

Commodity	Number of Units
FTRs (MW)	36,219

NOTE 5 — PROPERTY, PLANT AND EQUIPMENT

Summary of property by classification as of December 31:

(in Millions)	2011			2010
Property, Plant and Equipment
Generation	$	9,785		$	9,268
Distribution	7,003			6,800
Total	16,788			16,068
Less Accumulated Depreciation and Amortization
Generation	(3,946		)	(3,850		)
Distribution	(2,580		)	(2,568		)
Total	(6,526		)	(6,418		)
Net Property, Plant and Equipment	$	10,262		$	9,650

AFUDC capitalized during 2011 and 2010 was approximately $9 million and $10 million, respectively.

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

The average estimated useful life for our generation and distribution property was 46 years and 43 years, respectively, at December 31, 2011.

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.

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Capitalized software costs amortization expense was $58 million in 2011, $55 million in 2010 and 2009. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2011 were $501 million and $218 million, respectively. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2010 were $479 million and $175 million, respectively. Amortization expense of capitalized software costs is estimated to be approximately $55 million annually for 2012 through 2016.

Gross property under capital leases was $26 million and $121 million at December 31, 2011 and December 31, 2010, respectively. Accumulated amortization of property under capital leases was $14 million and $96 million at December 31, 2011 and December 31, 2010, respectively.

NOTE 6 — JOINTLY OWNED UTILITY PLANT

Detroit Edison has joint ownership interest in two power plants, Belle River and Ludington Hydroelectric Pumped Storage. Detroit Edison’s share of direct expenses of the jointly owned plants are included in Fuel 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, 2011 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			*	49		%
Investment (in millions)	$	1,645		$	199
Accumulated depreciation (in millions)	$	943		$	158

_________________________________

* Detroit Edison’s ownership interest is 63% in Unit No. 1, 81% of the facilities applicable to Belle River used jointly by the Belle River and St. Clair Power Plants and 75% in common facilities used at Unit No. 2.

Belle River

The Michigan Public Power Agency (MPPA) has an ownership interest in Belle River Unit No. 1 and other related facilities. The MPPA is entitled to 19% of the total capacity and energy of the plant and is responsible for the same percentage of the plant’s operation, maintenance and capital improvement costs.

Ludington Hydroelectric Pumped Storage

Consumers Energy Company has an ownership interest in the Ludington Hydroelectric Pumped Storage Plant. Consumers Energy is entitled to 51% of the total capacity and energy of the plant and is responsible for the same percentage of the plant’s operation, maintenance and capital improvement costs.

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. The Company has conditional retirement obligations for disposal of asbestos at certain of its power plants, certain service centers and disposal costs for PCB contained within transformers and circuit breakers. The Company recognizes such obligations as liabilities at fair market value when they are incurred, which generally is at the time the associated assets are placed in service. Fair value is measured using expected future cash outflows discounted at our credit-adjusted risk-free rate. The Company defers timing differences that arise in the expense recognition of legal asset retirement costs that are currently recovered in rates.

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

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

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A reconciliation of the asset retirement obligations for 2011 follows:

(in Millions)
Asset retirement obligations at January 1, 2011	$	1,366
Accretion	84
Liabilities incurred	8
Liabilities settled	(16		)
Asset retirement obligations at December 31, 2011	1,442
Less amount included in current liabilities	(2		)
	$	1,440

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

Detroit Edison has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. This obligation is reflected as an asset retirement obligation on the Consolidated Statements of Financial Position. In October 2011, the MPSC approved Detroit Edison's request for a reduction to the nuclear decommissioning surcharge under the assumption that it would request an extension of the Fermi 2 license for an additional 20 years beyond the term of the existing license which expires in 2025. Detroit Edison expects to request the license extension in 2014. This proposed extension of the license, including the associated impact on spent nuclear fuel, resulted in a revision in estimated cash flows for the Fermi 2 asset retirement obligation of approximately $22 million. It is estimated that the cost of decommissioning Fermi 2 is $1.4 billion in 2011 dollars and $10 billion in 2045 dollars, using a 6% inflation rate. Approximately $1.4 billion of the asset retirement obligations represent nuclear decommissioning liabilities that are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear plant.

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

A portion of the funds recovered through the Fermi 2 decommissioning surcharge and deposited in external trust accounts is designated for the removal of non-radioactive assets and the clean-up of the Fermi site. This removal and clean-up is not considered a legal liability. Therefore, it is not included in the asset retirement obligation, but is reflected as the nuclear decommissioning liability. The decommissioning of Fermi 1 is funded by Detroit Edison. Contributions to the Fermi 1 trust are discretionary. See Note 3 for additional discussion of Nuclear Decommissioning Trust Fund Assets.

NOTE 8 — RESTRUCTURING

Restructuring Costs

In 2005, the Company initiated a company-wide review of its operations called the Performance Excellence Process. The Company incurred CTA restructuring expense. In September 2006, the MPSC issued an order approving a settlement agreement that allowed Detroit Edison, commencing in 2006, to defer the incremental CTA. Further, the order provided for Detroit Edison to amortize the CTA deferrals over a ten-year period beginning with the year subsequent to the year the CTA was deferred. Detroit Edison amortized deferred CTA costs of $18 million in 2011, 2010 and 2009. Amounts expensed are

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recorded in Operation and maintenance expense on the Consolidated Statements of Operations. Deferred amounts are recorded in Regulatory assets on the Consolidated Statements of Financial Position.

NOTE 9 — REGULATORY MATTERS

Regulation

Detroit Edison 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. Detroit Edison is also regulated by the FERC with respect to financing authorization and wholesale electric activities. Regulation results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses.

Regulatory Assets and Liabilities

Detroit Edison 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.

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

(in Millions)	2011			2010
Assets
Recoverable pension and postretirement costs:
Pension	$	1,656		$	1,329
Postretirement costs	582			472
Asset retirement obligation	420			336
Recoverable income taxes related to securitized regulatory assets	316			400
Recoverable Michigan income taxes	270			319
Choice incentive mechanism	166			105
Accrued PSCR revenue	147			52
Cost to achieve Performance Excellence Process	100			118
Other recoverable income taxes	81			85
Recoverable restoration expense	58			19
Unamortized loss on reacquired debt	36			35
Enterprise Business Systems costs	18			21
Other	40			44
	3,890			3,335
Less amount included in current assets	(272		)	(58		)
	$	3,618		$	3,277
Securitized regulatory assets	$	577		$	729
Liabilities
Renewable energy	$	192		$	125
Refundable revenue decoupling	127			47
Asset removal costs	73			132
Energy Optimization	24			21
Low Income Energy Efficiency Fund	23			—
Fermi 2 refueling outage	23			3
Refundable uncollectible expense	13			—
Refundable Michigan income taxes	—			362
Refundable costs under PA 141	—			33
Refundable self implemented rates	—			27
Refundable restoration expense	—			15
Other	6			9
	481			774
Less amount included in current liabilities	(27		)	(60		)
	$	454		$	714

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

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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. (1)

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

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

• Recoverable 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.(1)

• 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 Detroit Edison.

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

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

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

• 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 Detroit Edison.

• 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 10 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.

_________________________________

(1) Regulatory assets not earning a return.

LIABILITIES

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

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

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

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

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

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• 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 Detroit Edison.

• Refundable Michigan income taxes — In July 2007, the MBT was enacted by the State of Michigan. State deferred tax assets were established for the Company's utilities, and offsetting regulatory liabilities were recorded as the impacts of the deferred tax assets will be reflected in rates. In May 2011, the MBT was repealed and the MCIT was enacted. The state deferred tax assets were eliminated under the MCIT and related regulatory liabilities were remeasured to zero.

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

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

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

2010 Electric Rate Case Filing

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

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

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

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

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

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

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

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

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2009 Detroit Edison Depreciation Filing

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

Renewable Energy Plan (REP)

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

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

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

Energy Optimization (EO) Plans

In April 2011, Detroit Edison filed an application for approval of its reconciliation for 2010 EO plan expenses. Specifically, Detroit Edison's EO reconciliation includes a cumulative $21 million net over-recovery at year end 2010 for the 2010 EO plan. In November 2011, the MPSC approved a settlement agreement for Detroit Edison which authorized the over-recovery balances be included in the 2011 reconciliations.

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

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

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

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

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

Detroit Edison Revenue Decoupling Mechanism (RDM)

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

In addition, Detroit Edison has accrued a pilot RDM liability for February 2011 through October 2011 of approximately $71 million, plus interest. Detroit Edison terminated the pilot RDM effective October 2011, and has requested a rehearing on this

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

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

Detroit Edison Uncollectible Expense True-Up Mechanism (UETM)

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

Detroit Edison Choice Incentive Mechanism (CIM)

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

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

Power Supply Cost Recovery Proceedings

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

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

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

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

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Low Income Energy Efficiency Fund

The Customer Choice and Electricity Reliability Act of 2000 authorized the creation of the LIEEF administered by the MPSC. The purpose of the fund is to provide shut-off and other protection for low income customers and to promote energy efficiency by all customer classes. Detroit Edison collects funding for the LIEEF as part of its base rates and remits the funds to the State of Michigan monthly. In July 2011, the Michigan Court of Appeals issued a decision reversing the portion of MichCon's June 2010 MPSC rate order that permitted MichCon to recover funding for the LIEEF in base rates. In response to the Court of Appeals decision, Detroit Edison ceased remitting payments for LIEEF funding to the State of Michigan. In October 2011, the MPSC issued an order directing Detroit Edison to continue collecting funds for LIEEF in rates and to escrow the collected funds pending further order by the MPSC. On January 26, 2012, the MPSC issued an order directing Detroit Edison to file a comprehensive plan by March 1, 2012 for refunding previously escrowed LIEEF funds of $23 million. On December 20, 2011, The Vulnerable Household Warmth Fund (VHWF) was created under Michigan law. The purpose of the fund is to provide payment or partial payment of bills for electricity, natural gas, propane, heating oil, or any other type of fuel used to heat the primary residence of a vulnerable customer during the 2011-2012 heating season. Effective with the new law, Detroit Edison is to contribute the amount collected in its base rates, previously remitted for the LIEEF, to the new VHWF. The monthly payments into the VHWF will cease on the earlier of September 30, 2012 or when $48 million has been is accumulated in the fund from payments by major Michigan electric and gas utilities.

Other

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

NOTE 10 — INCOME TAXES

Income Tax Summary

We are part of the consolidated federal income tax return of DTE Energy. The federal income tax expense for Detroit Edison is determined on an individual company basis with no allocation of tax benefits or expenses from other affiliates of DTE Energy. We had an income tax receivable of $48 million at December 31, 2011 and $152 million at December 31, 2010 due from DTE Energy.

Total income tax expense varied from the statutory federal income tax rate for the following reasons:

(Dollars in Millions)	2011			2010			2009
Income tax expense at 35% statutory rate	$	246		$	249		$	211
Investment tax credits	(6		)	(6		)	(6		)
Depreciation	3			3			3
Employee Stock Ownership Plan dividends	(3		)	(3		)	(4		)
Medicare Part D subsidy	—			—			(5		)
Domestic production activities deduction	(6		)	(6		)	(5		)
State and other income taxes, net of federal benefit	39			40			36
Other, net	(6		)	(7		)	(2		)
Income Tax Expense	$	267		$	270		$	228
Effective income tax rate	38.0		%	38.0		%	37.7		%

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

(in Millions)	2011		2010			2009
Current income tax expense (benefit)
Federal	$	15	$	(89	)	$	168
State and other income tax	21		37			45
Total current income taxes	36		(52		)	213
Deferred income tax expense (benefit)
Federal	193		297			4
State and other income tax	38		25			11
Total deferred income taxes	231		322			15
Total	$	267	$	270		$	228

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:

(in Millions)	2011			2010
Property, plant and equipment	$	(2,285	)	$	(1,819	)
Securitized regulatory assets	(384		)	(396		)
Pension and benefits	67			57
Other comprehensive income	15			10
Other, net	(182		)	(112		)
	$	(2,769	)	$	(2,260	)

(in Millions)	2011			2010
Deferred income tax liabilities	$	(3,377	)	$	(3,175	)
Deferred income tax assets	608			915
	$	(2,769	)	$	(2,260	)
Current deferred income tax liability (included in Current Liabilities — Other)	$	(68	)	$	(25	)
Long-term deferred income tax liabilities	(2,701		)	(2,235		)
	$	(2,769	)	$	(2,260	)

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:

(in Millions)	2011			2010			2009
Balance at January 1	$	18		$	96		$	70
Additions for tax positions of current years	1			6			10
Additions for tax positions of prior years	45			1			24
Reductions for tax positions of prior years	(5		)	—			(8		)
Settlements	—			(85		)	—
Balance at December 31	$	59		$	18		$	96

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The Company had $4 million and $3 million of unrecognized tax benefits at December 31, 2011 and at December 31, 2010, respectively, that, if recognized, would favorably impact our effective tax rate. During the next twelve months, it is reasonably possible that the Company will settle certain federal and state tax examinations and audits. As a result, the Company believes that it is possible that there will be a decrease in unrecognized tax benefits of up to $54 million within the next twelve months.

The Company recognizes interest and penalties pertaining to income taxes in Interest expense and Other expenses, respectively, on its Consolidated Statements of Operations. Accrued interest pertaining to income taxes totaled $2 million and $1 million at December 31, 2011 and December 31, 2010, respectively. The Company had no accrued penalties pertaining to income taxes. The Company recognized $1 million for interest expense related to income taxes during 2011 and during 2010.

In 2010, DTE Energy and its subsidiaries settled a federal tax audit for the 2007 and 2008 tax years, which resulted in the recognition of $85 million of unrecognized tax benefits by Detroit Edison. The Company's federal income tax returns for years 2009 and subsequent years remain subject to examination by the IRS. The Company's Michigan Business Tax 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. The $30 million decrease in deferred tax liabilities 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 11 — LONG-TERM DEBT

The Company's long-term debt outstanding and weighted average interest rates(1) of debt outstanding at December 31 were:

(in Millions)	2011			2010
Taxable Debt, Principally Secured
5.3% due 2012 to 2041	$	3,515		$	2,915
Tax- Exempt Revenue Bonds (2)
5.1% due 2012 to 2038	893			1,283
	4,408			4,198
Less amount due within one year	(303		)	(152		)
	$	4,105		$	4,046
Securitization Bonds
6.5% due 2012 to 2015	$	643		$	793
Less amount due within one year	$	(164	)	$	(150	)
	$	479		$	643

_________________________________

(1) Weighted average interest rates as of December 31, 2011 are shown below the description of each category of debt.

(2) Tax-Exempt Revenue Bonds are issued by a public body that loans the proceeds to Detroit Edison on terms substantially mirroring the Revenue Bonds.

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Debt Issuances

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

(in Millions)

Month Issued	Type	Interest Rate		Maturity	Amount
April	Tax-Exempt Revenue Bonds (1)	2.35	%	2024	$	31
May	Mortgage Bonds (2)	3.90	%	2021	250
September	Mortgage Bonds (3)	4.31	%	2023	102
September	Mortgage Bonds (3)	4.46	%	2026	77
September	Mortgage Bonds (3)	5.67	%	2041	46
September	Tax-Exempt Revenue Bonds (4)	2.13	%	2030	82
September	Mortgage Bonds (5)	4.50	%	2041	140
					$	728

_________________________________

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

(2) Proceeds were used for general corporate purposes.

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

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

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

Debt Retirements and Redemptions

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

(in Millions)

Month Retired	Type	Interest Rate		Maturity	Amount
May	Tax-Exempt Revenue Bonds	6.95	%	2011	$	26
September	Tax-Exempt Revenue Bonds	5.55	%	2029	118
September	Tax-Exempt Revenue Bonds	5.65	%	2029	67
September	Tax-Exempt Revenue Bonds	5.65	%	2029	40
September	Tax-Exempt Revenue Bonds	5.45	%	2029	140
					$	391

_________________________________

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

											2017 &
(in Millions)	2012		2013		2014		2015		2016		thereafter		Total
Amount to mature	$	303	$	263	$	304	$	210	$	151	$	3,185	$	4,416

Cross Default Provisions

Substantially all of the net properties of Detroit Edison are subject to the lien of its mortgage. Should Detroit Edison 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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NOTE 12 — PREFERRED AND PREFERENCE SECURITIES

At December 31, 2011, Detroit Edison 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 13 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

In October 2011, Detroit Edison, entered into an amended and restated $300 million five-year 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 any facility. Borrowings under the facility are available at prevailing short-term interest rates.

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

The above agreements require the Company to maintain a total funded debt to capitalization ratio of no more than 0.65 to 1. In the agreements, “total funded debt” means all indebtedness of the Company and its consolidated subsidiaries, including capital lease obligations, hedge agreements and guarantees of third parties’ debt, but excluding contingent obligations 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, 2011, the total funded debt to total capitalization ratio for Detroit Edison was 0.52 to 1. Should Detroit Edison have delinquent obligations of at least $50 million to any creditor, such delinquency will be considered a default under its credit agreements. Detroit Edison had no outstanding short-term borrowings at December 31, 2011 and 2010.

NOTE 14 — CAPITAL AND OPERATING LEASES

Lessee — 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, 2011 were:

	Capital			Operating
(in Millions)	Leases			Leases
2012	$	4		$	28
2013	2			23
2014	5			18
2015	2			17
2016	—			16
Thereafter	—			52
Total minimum lease payments	13			$	154
Less imputed interest	1
Present value of net minimum lease payments	12
Less current portion	(3		)
Non-current portion	$	9

Rental expense for operating leases was $57 million in 2011, $44 million in 2010, and $48 million in 2009.

NOTE 15 — COMMITMENTS AND CONTINGENCIES

Environmental

Air - Detroit Edison is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze, mercury, and other air pollution. These rules have led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, mercury and other emissions. To comply with these requirements, Detroit Edison has spent approximately $1.7 billion through 2011. The

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Company estimates Detroit Edison will make capital expenditures of approximately $255 million in 2012 and up to approximately $1.9 billion of additional capital expenditures through 2021 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants. The Cross State Air Pollution Rule (CSAPR), finalized in July 2011, requires further reductions of sulfur dioxide and nitrogen oxides emissions beginning in 2012. On December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit granted the motions to stay the rule, leaving Detroit Edison temporarily subject to the previously existing Clean Air Interstate Rule (CAIR). The Electric Generating Unit Maximum Achievable Control Technology (EGU MACT) Rule was finalized on December 16, 2011. The EGU MACT requires reductions of mercury and other hazardous air pollutants beginning in 2015. Because these rules were recently finalized and technologies to comply are still being tested, it is not possible to quantify the impact of these rulemakings.

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

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

On August 23, 2011, the U.S. District judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy.On October 20, 2011, the EPA caused to be filed a Notice of Appeal. A decision by the Court of Appeals is not expected until late 2012. DTE Energy and Detroit Edison believe that the plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of discussions with the EPA regarding the NOV/FOV and the result of the appeals process, the Company could also be required to install additional pollution control equipment at some or all of the power plants in question, implement early retirement of facilities where control equipment is not economical, engage in supplemental environmental programs, and/or pay fines. The Company cannot predict the financial impact or outcome of this matter, or the timing of its resolution.

Water - In response to an EPA regulation, Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of completed studies and expected future studies, Detroit Edison may be required to install additional control technologies to reduce the impacts of the water intakes. Initially, it was estimated that Detroit Edison could incur up to approximately $55 million in additional capital expenditures over the four to six years subsequent to 2008 to comply with these requirements. However, a January 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation that has resulted in a delay in compliance dates. The decision also raised the possibility that Detroit Edison may have to install cooling towers at some facilities at a cost substantially greater than was initially estimated for other mitigative technologies. In 2008, the Supreme Court agreed to review the remanded cost-benefit analysis provision of the rule and in April 2009 upheld the EPA's use of this provision in determining best technology available for reducing environmental impacts. The EPA published a proposed rule in 2011 that extended the time line to 2020 with an estimated expected increase in costs to $80 million. A final rule is expected in mid-2012.The EPA has also issued an information collection request to begin a review of steam electric effluent guidelines. It is not possible at this time to quantify the impacts of these developing requirements.

Contaminated and Other Sites - Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. The facilities, which produced gas, have been designated as manufactured gas plant (MGP) sites. Detroit Edison conducted remedial investigations at contaminated sites, including three former MGP sites. The investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites, including the area surrounding an ash landfill, electrical distribution substations, and underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is expected to be incurred over the next several years. At December 31, 2011 and December 31, 2010, the Company had $8 million and $9 million, respectively, accrued for remediation. Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company's financial position and cash flows.

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

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

Nuclear Operations

Property Insurance

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

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

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

In 2007, the Terrorism Risk Insurance Extension Act of 2005 (TRIA) was extended through December 31, 2014. A major change in the extension is the inclusion of “domestic” acts of terrorism in the definition of covered or “certified” acts. For multiple terrorism losses caused by acts of terrorism not covered under the TRIA occurring within one year after the first loss from terrorism, the NEIL policies would make available to all insured entities up to $3.2 billion, plus any amounts recovered from reinsurance, government indemnity, or other sources to cover losses.

Under the NEIL policies, Detroit Edison could be liable for maximum assessments of up to approximately $29 million per event if the loss associated with any one event at any nuclear plant in the United States should exceed the accumulated funds available to NEIL.

Public Liability Insurance

As of January 1, 2012, as required by federal law, Detroit Edison maintains $375 million of public liability insurance for a nuclear incident. For liabilities arising from a terrorist act outside the scope of TRIA, the policy is subject to one industry aggregate limit of $300 million. Further, under the Price-Anderson Amendments Act of 2005, deferred premium charges up to $117.5 million could be levied against each licensed nuclear facility, but not more than $17.5 million per year per facility. Thus, deferred premium charges could be levied against all owners of licensed nuclear facilities in the event of a nuclear incident at any of these facilities.

Nuclear Fuel Disposal Costs

In accordance with the Federal Nuclear Waste Policy Act of 1982, Detroit Edison has a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. Detroit Edison is obligated to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold. The fee is a component of nuclear fuel expense. The DOE's Yucca Mountain Nuclear Waste Repository program for the acceptance and disposal of spent nuclear fuel was terminated in 2011. Detroit Edison is a party in the litigation against the DOE for both past and future costs associated with the DOE's failure to accept spent nuclear fuel under the timetable set forth in the Federal Nuclear Waste Policy Act of 1982. Detroit Edison currently employs a spent nuclear fuel storage strategy utilizing a fuel pool. The Company continues to develop its on-site dry cask storage facility and has postponed the initial offload from the spent fuel pool until 2013. The dry cask storage facility is expected to provide sufficient spent fuel storage capability for the life of the plant as defined by the original operating license. Issues relating to long-term waste disposal policy and to the disposition of funds contributed by Detroit Edison ratepayers to the federal waste fund await future governmental action.

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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

There are several bargaining units for the Company’s approximately 2,800 represented employees. The majority of represented employees are under contracts that expire in August 2012 and June 2013.

Purchase Commitments

As of December 31, 2011, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments. The Company estimates that these commitments will be approximately $1.4 billion from 2012 through 2027 as detailed in the following table.

(in Millions)
2012	$	747
2013	360
2014	228
2015	74
2016	2
2017 - 2027	6
	$	1,417

The Company also estimates that 2012 capital expenditures will be approximately $1.3 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 9 for a discussion of contingencies related to Regulatory Matters.

NOTE 16 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

Pension Plan Benefits

Detroit Edison 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. Detroit Edison is allocated net periodic benefit costs for its share of the amounts of the combined plans.

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

Net pension cost includes the following components:

(in Millions)	2011			2010			2009
Service cost	$	55		$	52		$	43
Interest cost	154			153			158
Expected return on plan assets	(168		)	(171		)	(165		)
Amortization of:
Net actuarial loss	99			70			38
Prior service cost	4			5			7
Special termination benefits	2			—			—
Net pension cost	$	146		$	109		$	81

(in Millions)	2011			2010
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income
Net actuarial loss	$	437		$	145
Amortization of net actuarial loss	(99		)	(70		)
Amortization of prior service cost	(4		)	(5		)
Total recognized in Regulatory assets and Other comprehensive income	$	334		$	70
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	480		$	178
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	$	120		$	93
Prior service cost	1			4

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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:

(in Millions)	2011			2010
Accumulated benefit obligation, end of year	$	2,963		$	2,697
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	2,899		$	2,677
Service cost	55			52
Interest cost	154			153
Actuarial loss	251			180
Special termination benefits	2			—
Benefits paid	(165		)	(163		)
Projected benefit obligation, end of year	$	3,196		$	2,899
Change in plan assets
Plan assets at fair value, beginning of year	$	1,936		$	1,687
Actual return on plan assets	(18		)	207
Company contributions	204			205
Benefits paid	(165		)	(163		)
Plan assets at fair value, end of year	$	1,957		$	1,936
Funded status of the plan	$	(1,239	)	$	(963	)
Amount recorded as:
Current liabilities	$	(8	)	$	(3	)
Noncurrent liabilities	(1,231		)	(960		)
	$	(1,239	)	$	(963	)
Amounts recognized in Regulatory assets (see Note 9)
Net actuarial loss	$	1,645		$	1,314
Prior service cost	11			15
	$	1,656		$	1,329

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

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

The Company employs a formal process in determining the long-term rate of return for various asset classes. Management reviews historic financial market risks and returns and long-term historic relationships between the asset classes of equities, fixed income and other assets, consistent with the widely accepted capital market principle that asset classes with higher volatility generate a greater return over the long-term. Current market factors such as inflation, interest rates, asset class risks and asset class returns are evaluated and considered before long-term capital market assumptions are determined. The long-term portfolio return is also established employing a consistent formal process, with due consideration of diversification, active investment management and rebalancing. Peer data is reviewed to check for reasonableness. As a result of this process, the Company is lowering its long-term rate of return assumptions for its pension and OPEB plans to 8.25% for 2012. The Company believes this rate is a reasonable assumption for the long-term rate of return on its plan assets for 2012 given its investment strategy.

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At December 31, 2011, the benefits related to the Company’s qualified and nonqualified pension plans expected to be paid in each of the next five years and in the aggregate for the five fiscal years thereafter are as follows:

(in Millions)
2012	$	179
2013	182
2014	186
2015	193
2016	199
2017 - 2021	1,107
Total	$	2,046

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, 2011 are listed below:

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

Fair Value Measurements at December 31, 2011(a)

							Balance at
(in Millions)	Level 1		Level 2		Level 3		December 31, 2011
Asset Category:
Short-term investments(b)	$	—	$	23	$	—	$	23
Equity securities
U.S. Large Cap(c)	440		27		—		467
U.S. Small/Mid Cap(d)	110		4		—		114
Non U.S(e)	272		79		—		351
Fixed income securities(f)	61		448		—		509
Other types of investments
Hedge Funds and Similar Investments(g)	132		40		205		377
Private Equity and Other(h)	—		—		116		116
Total	$	1,015	$	621	$	321	$	1,957

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Fair Value Measurements at December 31, 2010(a)

							Balance at
(in Millions)	Level 1		Level 2		Level 3		December 31, 2010
Asset Category:
Short-term investments (b)	$	—	$	23	$	—	$	23
Equity securities
U.S. Large Cap(c)	461		26		—		487
U.S. Small/Mid Cap(d)	123		5		—		128
Non U.S(e)	194		151		—		345
Fixed income securities(f)	42		409		—		451
Other types of investments
Hedge Funds and Similar Investments(g)	128		50		206		384
Private Equity and Other(h)	—		—		118		118
Total	$	948	$	664	$	324	$	1,936

_________________________________

(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. Detroit Edison has obtained an understanding of how these prices are

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derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Detroit Edison selectively corroborates the fair values of securities by comparison of market-based price sources.

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

	Hedge Funds and Similar			Private Equity
(in Millions)	Investments			and Other			Total
Beginning Balance at January 1, 2011	$	206		$	118		$	324
Total realized/unrealized gains (losses):
Realized gains (losses)	(3		)	4			1
Unrealized gains (losses)	1			(21		)	(20		)
Purchases, sales and settlements:
Purchases	44			16			60
Sales	(43		)	(1		)	(44		)
Settlements
Ending Balance at December 31, 2011	$	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	$	3		$	(20	)	$	(17	)

	Hedge Funds and Similar			Private Equity
(in Millions)	Investments			and Other			Total
Beginning Balance at January 1, 2010	$	320		$	106		$	426
Total realized/unrealized gains (losses)	34			16			50
Purchases, sales and settlements	(148		)	(4		)	(152		)
Ending Balance at December 31, 2010	$	206		$	118		$	324
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	$	20		$	9		$	29

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

The Company also sponsors defined contribution retirement savings plans. Participation in one of these plans is available to substantially all represented and non-represented employees. The Company matches employee contributions up to certain predefined limits based upon eligible compensation, the employee’s contribution rate and, in some cases, years of credit service. The cost of these plans was $18 million, $17 million, and $16 million in each of the years ended 2011, 2010, and 2009, 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. The Company contributed $66 million to its postretirement medical and life insurance benefit plans during 2011.

In January 2012, the Company contributed $95 million to its other postretirement benefit plans. At the discretion of management, the Company may make up to an additional $120 million contribution to its VEBA trusts in 2012.

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Net postretirement cost includes the following components:

(in Millions)	2011			2010			2009
Service cost	$	49		$	47		$	45
Interest cost	91			95			102
Expected return on plan assets	(62		)	(52		)	(42		)
Amortization of:
Net loss	40			38			53
Prior service costs (credit)	(15		)	2			2
Net transition obligation	2			2			2
Net postretirement cost	$	105		$	132		$	162

(in Millions)	2011			2010
Other changes in plan assets and APBO recognized in Regulatory assets
Net actuarial loss (gain)	$	139		$	62
Amortization of net actuarial loss	(40		)	(38		)
Prior service cost (credit)	(3		)	(63		)
Amortization of prior service credit	15			(2		)
Amortization of transition (asset)	(2		)	(2		)
Total recognized in regulatory assets	$	109		$	(43	)
Total recognized in net periodic pension cost and Regulatory assets	$	214		$	89

Estimated amounts to be amortized from Regulatory assets into net periodic benefit cost during next fiscal year

	2011			2010
Net actuarial loss	$	55		$	42
Prior service cost (credit)	(16		)	(16		)
Net transition obligation	2			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:

(in Millions)	2011			2010
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation, beginning of year	$	1,742		$	1,650
Service cost	49			47
Interest cost	91			95
Plan amendments	(3		)	(62		)
Actuarial loss	60			86
Medicare Part D subsidy	4			5
Benefits paid	(75		)	(79		)
Accumulated postretirement benefit obligation, end of year	$	1,868		$	1,742
Change in plan assets
Plan assets at fair value, beginning of year	$	682		$	593
Actual return on plan assets	(17		)	76
Company contributions	66			90
Benefits paid	(80		)	(77		)
Plan assets at fair value, end of year	$	651		$	682
Funded status, end of year	$	(1,217	)	$	(1,060	)
Amount recorded as:
Non-current liabilities	$	(1,217	)	$	(1,060	)
Amounts recognized in Regulatory assets (see Note 9)
Net actuarial loss	$	633		$	534
Prior service cost	(53		)	(66		)
Net transition obligation	2			4
	$	582		$	472

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

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

A one-percentage-point increase in health care cost trend rates would have increased the total service cost and interest cost components of benefit costs by $28 million and increased the accumulated benefit obligation by $247 million at December 31, 2011. A one-percentage-point decrease in the health care cost trend rates would have decreased the total service and interest cost components of benefit costs by $17 million and would have decreased the accumulated benefit obligation by $208 million at December 31, 2011.

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At December 31, 2011, the benefits expected to be paid, including prescription drug benefits, in each of the next five years and in the aggregate for the five fiscal years thereafter are as follows:

(in Millions)
2012	$	82
2013	87
2014	93
2015	99
2016	106
2017-2021	636
	$	1,103

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, 2011 are listed below:

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

Fair Value Measurements at December 31, 2011(a)

							Balance at
(in Millions)	Level 1		Level 2		Level 3		December 31, 2011
Asset Category:
Short-term investments(b)	$	1	$	8	$	—	$	9
Equity securities
U.S. Large Cap(c)	116		10		—		126
U.S. Small/Mid Cap(d)	46		4		—		50
Non U.S(e)	116		10		—		126
Fixed income securities(f)	15		156		—		171
Other types of investments
Hedge Funds and Similar Investments(g)	53		14		63		130
Private Equity and Other(h)	—		—		39		39
Total	$	347	$	202	$	102	$	651

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Fair Value Measurements at December 31, 2010(a)

							Balance at
(in Millions)	Level 1		Level 2		Level 3		December 31, 2010
Asset Category:
Short-term investments(b)	$	—	$	5	$	—	$	5
Equity securities
U.S. Large Cap(c)	83		41		—		124
U.S. Small/Mid Cap(d)	40		39		—		79
Non U.S(e)	52		81		—		133
Fixed income securities(f)	3		167		—		170
Other types of investments
Hedge Funds and Similar Investments(g)	51		32		52		135
Private Equity and Other(h)	—		—		36		36
Total	$	229	$	365	$	88	$	682

_________________________________

(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. Detroit Edison has obtained an understanding of how these prices are

57

derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Detroit Edison selectively corroborates the fair values of securities by comparison of market-based price sources.

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

(in Millions)	Hedge Funds and Similar Investments			Private Equity and Other			Total
Beginning Balance at January 1, 2011	$	52		$	36		$	88
Total realized/unrealized gains (losses):
Realized gains (losses)	(1		)	1			—
Unrealized gains (losses)	2			(14		)	(12		)
Purchases, sales and settlements:							—
Purchases	45			31			76
Sales	(35		)	(15		)	(50		)
Settlements	—			—			—
Ending Balance at December 31, 2011	$	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	$	3		$	(11	)	$	(8	)

(in Millions)	Hedge Funds and Similar Investments			Private Equity and Other			Total
Beginning Balance at January 1, 2010	$	63		$	32		$	95
Total realized/unrealized gains (losses)	7			6			13
Purchases, sales and settlements	(18		)	(2		)	(20		)
Ending Balance at December 31, 2010	$	52		$	36		$	88
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		$	5		$	9

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

Healthcare Legislation

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

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

This change in tax law required a remeasurement of the Deferred tax asset related to the OPEB obligation and the Deferred tax liability related to the OPEB Regulatory asset in 2010. The net impact of the remeasurement was $18 million and has been deferred as a Regulatory asset as the traditional rate setting process allows for the recovery of income tax costs.

In December 2003, the Medicare Act was signed into law which provides for a non-taxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least “actuarially equivalent” to the benefit established by law. The effects of the subsidy reduced net periodic postretirement benefit costs by $5 million in 2011, $5 million in 2010 and $17 million in 2009. At December 31, 2011, the gross amount of federal subsidies expected to be received is estimated to be $5 million in 2012.

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NOTE 17 — 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:

(in Millions)	2011			2010			2009
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	(62	)	$	—		$	16
Inventories	(53		)	(71		)	30
Recoverable pension and postretirement costs	(436		)	(26		)	(13		)
Accrued pension liability — affiliates	271			(27		)	9
Accounts payable	41			47			(56		)
Income taxes payable/receivable	54			(77		)	(109		)
Accrued postretirement liability — affiliates	157			3			(17		)
Other assets	(98		)	(131		)	(5		)
Other liabilities	(15		)	29			106
	$	(141	)	$	(253	)	$	(39	)

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

(in Millions)	2011			2010		2009
Cash Paid (Received) For:
Interest (excluding interest capitalized)	$	294		$	315	$	328
Income taxes	(18		)	28		319

NOTE 18 — 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 Detroit Edison.

The following is a summary of transactions with affiliated companies:

(in Millions)	2011		2010		2009
Revenues
Energy sales	$	1	$	1	$	1
Other services	4		7		4
Shared capital assets	30		29		28
Costs
Fuel and power purchases	1		4		3
Other services and interest	2		2		3
Corporate expenses (net)	304		294		313
Other
Dividends declared	305		305		305
Dividends paid	305		305		305
Capital contribution	—		—		250

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	December 31,
(in Millions)	2011		2010
Assets
Accounts receivable	$	61	$	8
Notes receivable	26		103
Liabilities & Equity
Accounts payable	67		50
Short-term borrowing	64		—
Other liabilities
Accrued pension liability	1,231		960
Accrued postretirement liability	1,217		1,060

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.

NOTE 19 — SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

	First	Second	Third	Fourth
(in Millions)	Quarter	Quarter	Quarter	Quarter	Year
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
2010
Operating Revenues	1,146	1,208	1,444	1,195	4,993
Operating Income	226	221	351	230	1,028
Net Income	91	87	165	98	441

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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, 2011 and December 31, 2010 professional services were performed by PricewaterhouseCoopers LLP (PwC). The following table presents fees for professional services rendered by PwC for the audit of Detroit Edison’s annual financial statements for the years ended December 31, 2011 and December 31, 2010, respectively, and fees billed for other services rendered by PwC during those periods.

	2011		2010
Audit fees (1)	$	1,144,625	$	1,217,885
Audit-related fees (2)	36,250		37,000
All other fees (3)	210,000		410,498
Total	$	1,390,875	$	1,665,383

_________________________________

(1) Represents the aggregate fees for the audits of Detroit Edison’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.

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

(3) 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.

61

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.

12-42	Computation of Ratio of Earnings to Fixed Charges.
23-26	Consent of PricewaterhouseCoopers LLP.
31-71	Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report.
31-72	Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report.

(ii)Exhibits incorporated herein by reference.

3(a)	Restated Articles of Incorporation of The Detroit Edison Company, as filed December 10, 1991. (Exhibit 3-13 to Form 10-Q for the quarter ended June 30, 1999).
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)

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)

62

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, C, E and F)

Supplemental Indenture, dated as of May 1, 1991, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-178 to 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 December 1, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-232 to Form 10-K for the year ended December 31, 2002). (2002 Series C and D)

Supplemental Indenture, dated as of August 1, 2003, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-235 to 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)

63

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 December 1, 2007, 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 December 18, 2007). (2007 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, providing for General and Refunding Mortgage Bonds. (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 November 1, 2009 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 4-267 to Form 10-K for the year ended December 31, 2009). (2009 Series CT)

Supplemental Indenture, dated as of August 1, 2010, to the Mortgage and Deed of Trust, dated as of October 1, 1924, by and 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, by and 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, between 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)

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Supplemental Indenture, dated as of March 1, 2011, between 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, 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, 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, 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, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-278 to Form 10-Q for the quarter ended September 30, 2011). (2011 Series H)

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)).

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). (5.20% Senior Notes due 2012 and 6.35% Senior Notes due 2032)

Eleventh Supplemental Indenture, dated as of December 1, 2002, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-233 to Form 10-Q for the quarter ended March 31, 2003). (5.45% Senior Notes due 2032 and 5.25% Senior Notes due 2032)

Twelfth Supplemental Indenture, dated as of August 1, 2003, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-236 to 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)

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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)

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 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)

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)

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	Thirtieth Supplemental Indenture, dated as of November 1, 2009 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee. (Exhibit 4-268 to Form 10-K for the year ended December 31, 2009). (2009 Series CT Variable Rate Senior Notes due 2024).
	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, by and 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)
4(c)	Trust Agreement of Detroit Edison Trust I. (Exhibit 4.9 to Registration Statement on Form S-3 (File No. 333-100000)).
4(d)	Trust Agreement of Detroit Edison Trust II. (Exhibit 4.10 to Registration Statement on Form S-3 (File No. 333-100000)).
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 Anthony F. Earley, Jr. with The Detroit Edison Company, dated April 25, 1994. (Exhibit 10-53 to Form 10-Q for the quarter ended March 31, 1994).
10(c)	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(d)	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(e)	Amended and Restated Post-Employment Income Agreement, dated March 23, 1998, between The Detroit Edison Company and Anthony F. Earley, Jr. (Exhibit 10-21 to Form 10-Q for the quarter ended March 31, 1998).
10(f)	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(g)	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).

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iii.Exhibits furnished herewith.

32-71	Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report.
32-72	Chief Financial Officer Section 906 Form 10-K Certification of Periodic Report.
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

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The Detroit Edison Company

Schedule II — Valuation and Qualifying Accounts

	Year Ended December 31
(in Millions)	2011			2010			2009
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statements of Financial Position)
Balance at Beginning of Period	$	93		$	118		$	121
Additions:
Charged to costs and expenses	47			57			62
Charged to other accounts (1)	8			8			7
Deductions (2)	(68		)	(90		)	(72		)
Balance At End of Period	$	80		$	93		$	118

_________________________________

(1) Collection of accounts previously written off.

(2) Non-collectible accounts written off.

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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.

		THE DETROIT EDISON COMPANY (Registrant)
Date:	February 16, 2012	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/ PETER B. OLEKSIAK
	Gerard M. Anderson		Peter B. Oleksiak
	Chairman of the Board and		Vice President, Controller and
	Chief Executive Officer		Chief Accounting Officer
By	/s/ DAVID E. MEADOR	By	/s/ LISA A. MUSCHONG
	David E. Meador		Lisa A. Muschong
	Director, Executive Vice President and Chief		Director
	Financial Officer
By	/s/ BRUCE D. PETERSON
	Bruce D. Peterson
	Director

Date: February 16, 2012

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