~~Landfill~~~~— Detroit Edison owns~~ Any significant change in assumptions, such as remediation techniques, nature and ~~operates a permitted engineered ash storage facility at~~extent of contamination and regulatory requirements, could impact the ~~Monroe Power Plant to dispose~~estimate of ~~fly ash from~~remedial action costs for these sites and affect the ~~coal fired power plant. Detroit Edison performed an engineering analysis in 2009~~Company's financial position and ~~identified~~cash flows and the ~~need for embankment side slope repairs and reconstruction.~~rates we charge our customers.

The EPA has ~~expressed its intentions to develop new federal regulations for coal ash under the authority of the Resources Conservation and Recovery Act (RCRA). A~~published proposed regulation is expected in the first quarter of 2010. Among the options EPA is currently considering, is a ruling that may designate coal ash as a “Hazardous Waste” as defined by RCRA. However, agencies and legislatures have urged EPArules to regulate coal ash, aswhich may result in a ~~non-hazardous waste. If EPA were to designate coal ash~~designation as a hazardous ~~waste, the agency~~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 ~~material adverse~~significant impact on our operations and financial position and the rates we charge our customers.

~~Global Climate Change~~— Climate regulation and/or legislation is being proposed and discussed within the U.S. Congress and the EPA. On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act (ACESA). The ACESA includes a cap and trade program that would start in 2012 and provides for costs to emit greenhouse gases. Despite action by the Senate Environmental and Public Works Committee to pass a similar but more stringent bill in October 2009, full Senate action on a climate bill is not expected before the spring of 2010. Meanwhile, the EPA is beginning to implement regulatory actions under the Clean Air Act to address emission of greenhouse gases. Pending or future legislation or other regulatory actions could have a material impact on our operations and financial position and the rates we charge our customers. Impacts include expenditures for environmental equipment beyond what is currently planned, financing costs related to additional capital expenditures and the purchase of emission allowances from market sources. We would seek to recover these incremental costs through increased rates charged to our utility customers. Increased costs for energy produced from traditional sources could also increase the economic viability of energy produced from renewable and/or nuclear sources and energy efficiency initiatives and the development of market-based trading of carbon offsets providing business opportunities for our utility and non-utility segments. It is not possible to quantify ~~these impacts on Detroit Edison or its customers~~the impact of those expected rulemakings at this time.

See Notes 108 and 1714 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

EMPLOYEES

We had ~~4,864~~approximately 4,800 employees as of December 31, ~~2009,~~2012, of which ~~2,782~~approximately 2,700 were represented by unions. The majority of our union employees are under ~~contracts~~a contract that ~~expire~~expires in June ~~2010 and August 2012.~~2013.

Item 1A. Risk Factors

There are various risks associated with the operations of ~~Detroit Edison.~~DTE Electric. To provide a framework to understand the operating environment of the Company, we are providing a brief explanation of the more significant risks associated with our business. Although we have tried to identify and discuss key risk factors, others could emerge in the future. Each of the following risks could affect our performance.

~~Regional~~

We are subject to rate regulation. Our electric rates are set by the MPSC and ~~national economic conditions~~the FERC and cannot be changed without regulatory authorization. We may be negatively impacted by new regulations or interpretations by the MPSC, the FERC or other regulatory bodies. Our ability to recover costs may be impacted by the time lag between the incurrence of costs and the recovery of the costs in customers' rates. Our regulators also may decide to disallow recovery of certain costs in customers' rates if they determine that those costs do not meet the standards for recovery under our governing laws and regulations. We typically self-implement base rate changes six months after rate case filings in accordance with Michigan law. However, if the

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

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

Environmental laws and liability may be costly. We are subject to and affected by numerous environmental regulations. These regulations govern air emissions, water quality, wastewater discharge and disposal of solid and hazardous waste. Compliance with these regulations can significantly increase capital spending, operating expenses and plant down times and can negatively affect the affordability of the rates we charge to our customers.

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

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

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

The supply and/or price of energy commodities and/or related services may impact our financial results. We are dependent on coal for much of our electrical generating capacity. Price fluctuations, fuel supply disruptions and changes in transportation costs could have ~~an unfavorable~~a negative impact on ~~us.Our business follows~~ the ~~economic cycles~~amounts we charge our utility customers for electricity. We have hedging strategies and regulatory recovery mechanisms in place to mitigate some of the negative fluctuations in commodity supply prices, but there can be no assurances that our financial performance will not be negatively impacted by price fluctuations.

The supply and/or price of other industrial raw and finished inputs and/or related services may impact our financial results. We are dependent on supplies of certain commodities, such as copper and limestone, among others, and industrial materials and services in order to maintain day-to-day operations and maintenance of our facilities. Price fluctuations or supply

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interruptions for these commodities and other items could have a negative impact on the amounts we charge our customers we serve. 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 further decline, reduced volumes of electricity and collections of accounts receivable will result in decreased earnings and cash flow.for our products.

Adverse changes in our credit ratings may negatively affect us.Regional and national economic conditions, increased scrutiny of the energy industry and regulatory changes, as well as changes in our economic performance, could result in credit agencies reexamining our credit rating. While credit ratings reflect the opinions of the credit agencies issuing such ratings and may not necessarily reflect actual performance, a downgrade in our credit rating below investment grade could restrict or discontinue our ability to access capital markets and could result in an increase in our borrowing costs, a reduced level of capital expenditures and could impact future earnings and cash flows. In addition, a reduction in our credit rating may require us to post collateral related to various physical or financially settled contracts for the purchase of energy-related commodities, products and services, which could impact our liquidity.

~~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. We have a five-year credit facility that expires in 2010. We intend to seek to renew the facility on or before the expiration date. However, we cannot predict the outcome of these efforts, which could result in a decrease in amounts available and/or an increase in our borrowing costs and negatively impact our financial performance.

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.~~Detroit Edison participates in various plans that provide pension and other postretirement benefits for DTE Energy and its affiliates.Our~~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, ~~potentially~~resulting in increasing benefit expense and funding requirements. Also, if future increases in pension and postretirement benefit costs as a result of reduced plan assets are not recoverable from ~~Detroit Edison~~our customers, the results of operations and financial position of our company could be negatively affected. Without sustained growth in the plan investments over time to increase the value of our plan assets, we could be required to fund our plans with significant amounts of cash. Such cash funding obligations could have a material impact on our cash flows, financial position, or results of operations.

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

~~We are subject to rate regulation~~. Our electric rates are set by the MPSC and the FERC and cannot be increased without regulatory authorization. We may be negatively impacted by new regulations or interpretations by the MPSC, the FERC or other regulatory bodies. Our ability to ~~recover costs~~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 ~~be impacted~~again in the future constrain, our ability to issue new debt, including commercial paper, and refinance existing debt at reasonable interest rates. In addition, the level of borrowing by ~~the time lag between the incurrence of costs~~other energy companies and the ~~recovery of the costs in customers’ rates.~~market as a whole could limit our access to capital markets. Our ~~regulators also may decide~~long term revolving credit facility does not expire until 2016, but we regularly access capital markets 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. The State of Michigan will elect arefinance existing debt or fund new ~~governor and legislature in 2010~~projects, and we cannot predict the ~~outcome of that election. We cannot predict whether election results~~pricing or changes in political conditions will affect the regulations or interpretations affecting Detroit Edison. New legislation, regulations or interpretations could change how our business operates, impact our ability to recover costs through rate increases or require us to incur additional expenses.demand for those future transactions.

~~We may be required to refund amounts we collect under self-implemented rates.~~Michigan law allows our utilities to self-implement rate changes six months after a rate filing, subject to certain limitations. However, if the final rate case order provides for lower rates than we have self-implemented, we must refund the difference, with interest. We have self-implemented rates in the past and have been ordered to make refunds to customers. Our financial performance may be negatively affected if the MPSC sets lower rates in future rate cases than those we have self-implemented, thereby requiring us to issue refunds. We cannot predict what rates an MPSC order will adopt in future rate cases.

~~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 recent energy legislation enacted by the State of Michigan are phasing out the pricing disparity over five years and have placed a 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 financial risk associated with the electric Customer Choice program. Electric Customer Choice migration is sensitive to market price and bundled electric service price increases.

~~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.

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

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 ~~delay~~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.

~~The supply and/or price of energy commodities and/or related service may impact~~

Weather significantly affects operations. Deviations from normal hot and cold weather conditions affect our ~~financial results.~~~~We are dependent on coal for much~~earnings and cash flow. Mild temperatures can result in decreased utilization of our ~~electrical generating capacity. Price fluctuations, fuel supply disruptions~~assets, lowering income and ~~increases in transportation costs could have a negative impact on~~cash flow. Ice storms, tornadoes, or high winds can damage the ~~amounts we charge our customers for~~

~~electricity. We have hedging strategies~~electric distribution system infrastructure and ~~regulatory recovery mechanisms in place~~power generation facilities and require us to ~~mitigate negative fluctuations in commodity supply prices, but there can be no assurances that our financial performance will~~perform emergency repairs and incur material unplanned expenses. The expenses of storm restoration efforts may not be ~~negatively impacted by price fluctuations.~~fully recoverable through the regulatory process.

~~The supply and/or price 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.

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.

~~Environmental laws and liability may be costly.~~We are subject to numerous environmental regulations. These regulations govern air emissions, water quality, wastewater discharge and disposal of solid and hazardous waste. Compliance with these regulations can significantly increase capital spending, operating expenses and plant down times. These laws and regulations require us to seek a variety of environmental licenses, permits, inspections and other regulatory approvals. 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.

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~~implementing a strategy for complying with the existing state legislation, but we do not know what requirements may be added by federal legislation. In addition, there could be additional state requirements

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increasing the percentage of power required to be provided by renewable energy sources. We are actively engaged in developing renewable energy projects and identifying third party projects in which we can invest. We cannot predict the financial impact or costs associated with these future projects.

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

Regional and national economic conditions can have an unfavorable impact on us. Our business follows the economic cycles of the customers we serve and the credit risk of counterparties we do business with. Should national or regional economic conditions deteriorate, reduced volumes of electricity, collections of accounts receivable, and reductions in federal and state energy assistance funding, and potentially higher levels of stolen electricity could result in decreased earnings and cash flow.

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

In addition, our generation plants and electrical distribution facilities in particular may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products. We have

increased security as a result of past events and we may be required by our regulators or by the future terrorist threat environment to make investments in security that we cannot currently predict.

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

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

A work interruption may adversely affect us. Unions represent approximately 2,700 of our employees. The majority of our union employees are under a contract that expires in June 2013. We cannot predict the outcome of those negotiations. A union choosing to strike would have an impact on our business. We are unable to predict the effect a work stoppage would have on our costs of operation and financial performance.

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

~~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 and employees. Our customers 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, employee or Detroit Edison data by cybercrime or otherwise could adversely impact our reputation and could result in significant costs, fines and litigation.

~~Benefits of continuous improvement initiatives could be less than we expect~~~~. We have a continuous improvement program that is expected to result in significant cost savings. Actual results achieved through this program could be less than our expectations.~~

~~A work interruption may adversely affect us.~~Unions represent approximately 2,800 of our employees. A union choosing to strike would have an impact on our business. A contract with our largest union expires in June 2010. In addition, our contracts with unions representing two small groups of employees expired on December 31, 2009 and another union is currently negotiating its first contract. We cannot predict the outcome of any of these contract negotiations, some of which have not yet commenced. We are unable to predict the effect a work stoppage would have on our costs of operation and financial performance.

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

Item 1B. Unresolved Staff Comments

None.

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Item 3. Legal Proceedings

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

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

In August 2010, the United States Department of Justice, at the request of EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and DTE Electric, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require DTE Electric to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require DTE Electric to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from DTE Electric's fleet of coal-fired power plants until the new control equipment is operating. On August 23, 2011, the U.S. District Court judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy and DTE Electric. On October 20, 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit. Oral arguments at the Court of Appeals were held on November 27, 2012 and a decision is expected in early 2013.

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

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


~~Note~~Item 4.	~~Title~~

10	~~Regulatory Matters~~
16	~~Commitments and Contingencies~~	Mine Safety Disclosures

Not applicable.

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

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

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,~~DTE Electric, par value $10 per share, are owned by DTE Energy, and constitute 100% of the voting securities of ~~Detroit Edison.~~DTE Electric. Therefore, no market exists for our common stock.

We paid cash dividends on our common stock of $317 million in 2012 and $305 million in ~~2009, 2008,~~2011, and ~~2007.~~2010.

~~month~~18-month period, that coincides with scheduled refueling outages at Fermi 2. This accrual of outage costs matches the regulatory recovery of these costs in rates set by the MPSC. See Note 8.

The ~~Company bases depreciation provisions for utility property on straight-line rates approved by the MPSC.~~

cost of nuclear fuel is capitalized. The ~~average estimated useful life for our generation and distribution property was 40 years and 37 years, respectively, at December 31, 2009.~~

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

~~Capitalized software is classified as Property, plant and equipment and the related amortization~~of nuclear fuel is included within Fuel and purchased power in ~~Accumulated depreciation on~~ the Consolidated Statements of ~~Financial Position. The Company capitalizes~~Operations and is recorded using the ~~costs associated with computer software the Company develops or obtains for use in our business. The Company amortizes Intangible assets on a straight-line basis over the expected period~~units-of-production method.

Table of ~~benefit, ranging from 5 to 15 years.~~Contents

~~See Note 6.~~

Long-Lived Assets

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

Intangible Assets

The Company has certain intangible assets relating to emission ~~allowances.~~allowances and renewable energy credits. Emission allowances and renewable energy credits are charged to ~~fuel~~ expense, using average cost, as the allowances and credits are consumed in the operation of the business. The Company’s intangible assets related to emission allowances were $6 million at December 31, 2012 and $9 million at December 31, 2011. The Company’s intangible assets related to renewable energy credits were $44 million and $39 million at December 31, 2012 and December 31, 2011, respectively.

Excise and Sales Taxes

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

Deferred Debt Costs

The costs related to the issuance of long-term debt are deferred and amortized over the life of each debt issue. In accordance with MPSC regulations, the unamortized discount, premium and expense related to debt redeemed with a refinancing are amortized over the life of the replacement issue.

Investments in Debt and Equity Securities

The Company generally classifies investments in debt and equity securities as either trading or available-for-sale and has recorded such investments at market value with unrealized gains or losses included in earnings or in other comprehensive income or loss, respectively. Changes in the fair value of Fermi 2 nuclear decommissioning investments are recorded as adjustments to regulatory assets or liabilities, due to a recovery mechanism from customers. The Company’s equity investments are reviewed for impairment each reporting period. If the assessment indicates that the impairment is other than temporary, a loss is recognized resulting in the equity investment being written down to its estimated fair value. See Note 4.3.

Stock-Based Compensation

The Company received an allocation of costs from DTE Energy associated with stock-based compensation. Our allocation for ~~2009, 2008~~2012, 2011 and ~~2007~~2010 for stock-based compensation expense was approximately ~~$24~~$42 million ~~$15~~, $30 million and ~~$13~~$23 million, respectively.

~~Asset (gains) losses~~

Government Grants

Grants are recognized when there is reasonable assurance that the grant will be received and ~~reserves, net~~

~~In 2007, we recorded a $13 million reserve for a loan guaranty~~that any conditions associated with the grant will be met. When grants are received related to ~~Detroit Edison’s former ownership~~Property, Plant and Equipment, the Company reduces the basis of ~~a steam heating business now owned by Thermal Ventures II, LP (Thermal)~~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 ~~loss~~reduction of the associated expense in the period in which ~~was partially offset by approximately $5 million in gains on land and other sales.~~the expense is incurred.

~~Subsequent Events~~

~~The Company has evaluated subsequent events through February 23, 2010, the date that these financial statements were issued.~~

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Other Accounting Policies

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



Note		Title
3	~~New Accounting Pronouncements~~
4	Fair Value
54		Financial and Other Derivative Instruments
7		Asset Retirement Obligations
108		Regulatory Matters
119		Income Taxes
1715		Retirement Benefits and Trusteed Assets

NOTE 3 — ~~NEW ACCOUNTING PRONOUNCEMENTS~~

~~FASB Accounting Standards Codification~~™ ~~(Codification)~~

On July 1, 2009, the Codification became the single source of authoritative nongovernmental generally accepted accounting principles (GAAP) in the United States of America. The Codification is a reorganization of current GAAP into a topical format that eliminates the current GAAP hierarchy and establishes two levels of guidance — authoritative and non-authoritative. According to the FASB, all “non-grandfathered, non-SEC accounting literature” that is not included in the Codification would be considered non-authoritative. The FASB has indicated that the Codification does not change current GAAP. Instead, the proposed changes aim to (1) reduce the time and effort it takes for users to research accounting questions and (2) improve the usability of current accounting standards. The Codification is effective for interim and annual periods ending after September 15, 2009.

~~Fair Value Accounting~~

~~In September 2006, the FASB issued ASC 820 (SFAS No. 157,~~~~Fair Value Measurements)~~. The standard defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. It emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Fair value measurement should be determined based on the assumptions that market participants would use in pricing an asset or liability. Effective January 1, 2008, the Company adopted ASC 820 (SFAS No. 157). As permitted by ASC 820-10 (FSP No. 157-2), the Company elected to defer the effective date of the standard as it pertains to measurement and disclosures about the fair value of non-financial assets and liabilities made on a nonrecurring basis. The Company has adopted the recognition provisions for non-financial assets and liabilities as of January 1, 2009. See Note 4.

In April 2009, the FASB issued three FSPs intended to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities. The FSPs are effective for interim and annual periods ending after June 15, 2009.

•~~ASC 825-10 (FSP No. 107-1 and APB No. 28-1),~~~~Interim Disclosures about Fair Value of Financial Instruments,~~~~expands the fair value disclosures required for all financial instruments within the scope of ASC 825-10 to interim periods.~~

•~~ASC 820-10 (FSP No. 157-4),~~~~Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,~~ which applies to all assets and liabilities, i.e., financial and nonfinancial, reemphasizes that the objective of fair value remains unchanged (i.e., an exit price notion). The FSP provides application guidance on measuring fair value when the volume and level of activity has significantly decreased and identifying transactions that are not orderly. The FSP also emphasizes that an entity cannot presume that an observable transaction price is not orderly even when there has been a significant decline in the volume and level of activity.

•~~ASC 320-10 (FSP No. 115-2 and SFAS No. 124-2),~~~~Recognition and Presentation of Other-Than-Temporary Impairments,~~is intended to bring greater consistency to the timing of impairment recognition, and provide greater clarity to investors about the credit and noncredit components of impaired debt securities that are not expected to be sold.

~~The Company adopted these FSPs in the second quarter of 2009. The adoption of these FSPs did not have a significant impact on Detroit Edison’s consolidated financial statements.~~

~~Disclosures about Derivative Instruments and Guarantees~~

~~In March 2008, the FASB issued ASC 815-10 (SFAS No. 161,~~~~Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133)~~~~. This standard requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. Entities~~

are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under ASC 815 (SFAS No. 133) and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows.

The standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. Comparative disclosures for earlier periods at initial adoption are encouraged but not required. The Company adopted the standard effective January 1, 2009. See Note 5.

~~Subsequent Events~~

~~In May 2009, the FASB issued ASC 855 (SFAS No. 165,~~~~Subsequent Events)~~. This standard provides guidance on management’s assessment of subsequent events. The new standard clarifies that management must evaluate, as of each reporting period, events or transactions that occur after the balance sheet date “through the date that the financial statements are issued or are available to be issued.” Management must perform its assessment for both interim and annual financial reporting periods. The standard does not significantly change the Company’s practice for evaluating such events. ASC 855 (SFAS No. 165) is effective prospectively for interim and annual periods ending after June 15, 2009 and requires disclosure of the date subsequent events are evaluated through. The Company adopted the standard during the quarter ended June 30, 2009. See Note 2.

~~Transfers of Financial Assets~~

~~In June 2009, the FASB issued ASU 2009-16 (SFAS No. 166,~~~~Accounting for Transfers of Financial Assets — an amendment of FASB No. 140).~~This standard amends ASC 860, (SFAS No. 140), eliminates the concept of a “qualifying special-purpose entity” (QSPE) and associated guidance and creates more stringent conditions for reporting a transfer of a portion of a financial asset as a sale. ASU 2009-16 (SFAS No. 166) is intended to enhance reporting in the wake of the subprime mortgage crisis and the deterioration in the global credit markets. The standard is effective for financial asset transfers occurring after the beginning of an entity’s first fiscal year that begins after November 15, 2009. Early adoption is prohibited. ASU 2009-16 (SFAS No. 166) must be applied prospectively to transfers of financial assets occurring on or after its effective date. The adoption of ASU 2009-16 (SFAS No. 166) will not have a material impact on Detroit Edison’s consolidated financial statements.

~~Variable Interest Entities (VIE)~~

~~In June 2009, the FASB issued ASU 2009-17 (SFAS No. 167,~~~~Amendments to FASB Interpretation 46(R)).~~ This standard amends the consolidation guidance that applies to VIEs and affects the overall consolidation analysis under ASC 810 -10 (Interpretation 46(R)). The amendments to the consolidation guidance affect all entities and enterprises currently within the scope of ASC 810-10, as well as qualifying special purpose entities that are currently outside the scope of ASC 810-10. Accordingly, the Company will need to reconsider its previous ASC 810-10 conclusions, including (1) whether an entity is a VIE, (2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required. ASU 2009-17 (SFAS No. 167) is effective as of the beginning of the first fiscal year that begins after November 15, 2009. Early adoption is prohibited. The Company is currently assessing the impact of ASU 2009-17 (SFAS No. 167), however adoption of the standard is not expected to have a material impact to the consolidated financial statements.

~~Fair Value Measurements and Disclosures~~

~~In September and August 2009, respectively, the FASB issued ASU 2009-12,~~~~Fair Value Measurements and Disclosure,~~~~and ASU 2009-05,~~~~Measuring Liabilities at Fair Value.~~ASU 2009-12 provides guidance for the fair value measurement of investments in certain entities that calculate the net asset value per share (or its equivalent) determined as of the reporting entity’s measurement date. Certain attributes of the investment (such as restrictions on redemption) and transaction prices from principal-to-principal or brokered transactions will not be considered in measuring the fair value of the investment. The amendments in this standard are effective for interim and annual periods ending after December 15, 2009.

ASU 2009-05 provides guidance on measuring the fair value of liabilities under ASC 820. This standard clarifies that in the absence of a quoted price in an active market for an identical liability at the measurement date, companies may apply approaches that use the quoted price of an investment in the identical liability or similar liabilities traded as assets or other valuation techniques consistent with the fair-value measurement principles in ASC 820. The standard permits fair value measurements of liabilities that are based on the price that a company would pay to transfer the liability to a new obligor. It also permits a company to measure the fair value of liabilities using an estimate of the price it would receive to enter into the liability at that date. The new standard is effective for interim and annual periods beginning after August 27, 2009 and applies to all fair-value measurements of liabilities required by GAAP. The adoption of ASU 2009-12 and ASU 2009-05 did not have a material impact on Detroit Edison’s consolidated financial statements.

~~In January 2010, the FASB issued ASU 2010-06,~~~~Improving Disclosures about Fair Value Measurements~~. ASU 2010-06 requires the gross presentation of activity within the Level 3 fair value measurement roll forward and details of transfers in and out of Level 1 and 2 fair value measurements. The new disclosures are required of all entities that are required to provide disclosures about recurring and nonrecurring fair value measurements. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for the gross presentation of the Level 3 fair value measurement roll forward which is effective for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years.

~~Revenue Arrangements~~

~~In September 2009, the FASB ratified Issue No. 08-1,~~~~Revenue Arrangements with Multiple Deliverables (not yet codified).~~Issue 08-1 provides principles and application guidance on whether multiple deliverables exist, how the arrangement should be separated, and the consideration allocated. This standard shall be applied prospectively for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010, with earlier application permitted. Alternatively, an entity may elect to adopt this standard on a retrospective basis. The Company is currently assessing the impact of Issue No. 08-1 on Detroit Edison’s consolidated financial statements. Adoption of this standard is not expected to have a material impact to the consolidated financial statements.

~~NOTE 4 —~~ 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’~~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 iswas immaterial ~~for the years ended~~at December 31, ~~2009~~2012 and ~~2008.~~December 31, 2011. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

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

•

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

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

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

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The following table presents assets ~~and liabilities~~ measured and recorded at fair value on a recurring basis as of December 31, ~~2009:~~2012 and 2011:

Net Balance at
(in Millions) Level 1 Level 2 Level 3 December 31, 2009
Assets:

Cash equivalents $ 15 $ — $ — $ 15
Nuclear decommissioning trusts and other investments 589 325 — 914
Derivative assets — — 2 2

Total $ 604 $ 325 $ 2 $ 931

Liabilities:

Derivative liabilities — (8 ) — (8 )

Total $ — $ (8 ) $ — $ (8 )

Net Assets at December 31, 2009 $ 604 $ 317 $ 2 $ 923



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

Assets:
Current	$	—	$	116	$	1	$	117	$	—	$	129	$	1	$	130
Noncurrent	758		387		—		1,145		632		398		—		1,030
Total Assets	$	758	$	503	$	1	$	1,262	$	632	$	527	$	1	$	1,160

(a)

At December 31, 2012 available for sale securities of $116 million, included $102 million and $14 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively. At December 31, 2011 available for sale securities of $129 million, included $113 million and $16 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively.


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

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the years ended December 31, ~~2009~~2012 and ~~2008:~~2011:

Year Ended
December 31
(in Millions) 2009 2008
Asset balance as of beginning of period $ 4 4
Changes in fair value recorded in regulatory assets/liabilities — 2
Purchases, issuances and settlements — (2 )
Transfers in/out of Level 3 (2 ) —

Asset balance as of December 31 $ 2 $ 4

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, 2009 and 2008 $ 2 $ —

~~Transfers in/out of Level~~



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

No transfers between Levels 1, 2 or 3 represent existing assets or liabilities that were either previously categorized as a higher level and for which the inputs to the model become 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/out of Level 3 are reflected as if they had occurred ~~at the beginning of the period. Transfers out of Level 3 in 2009 reflect a change~~ in the ~~significance of unobservable inputs~~years ended December 31, 2012 and ~~an increased reliance on broker quotes for certain transactions.~~December 31, 2011.

Cash Equivalents

Cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value table are comprised of short-term investments inand money market funds. The fair values of the shares ofin these ~~funds~~investments are based onupon observable market prices for similar securities and, therefore, have been categorized as Level 12 in the fair value hierarchy.

Nuclear Decommissioning Trusts and Other Investments

~~The nuclear decommissioning trust fund investments have been established to satisfy Detroit Edison’s nuclear decommissioning obligations.~~

The nuclear decommissioning trusts and other ~~fund~~ 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 onin 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. ~~For non-exchange traded fixed income securities, the trustees receive prices from 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~~The Company has obtained an understanding of how these

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prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, ~~Detroit Edison~~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~~financial instruments included in the table below is determined by using quoted market prices when available. When quoted prices are not available, ~~and a discounted~~pricing services may be used to determine the fair value with reference to observable interest rate indexes. The Company has obtained an understanding of how the fair values are derived. The Company also selectively corroborates the fair value of its transactions by comparison of market-based price sources. Discounted cash flow ~~analysis~~analyses based upon estimated current borrowing rates are also used to determine fair value when quoted market prices are not available. The ~~table below shows~~fair values of notes receivable, excluding capital leases, are estimated using discounted cash flow techniques that incorporate market interest rates as well as assumptions about the ~~fair value relative~~remaining life of the loans and credit risk. Depending on the information available, other valuation techniques may be used that rely on internal assumptions and models. Valuation policies and procedures are determined by the Company's Treasury Department which reports to the ~~carrying value for long-term debt securities. Certain other financial instruments, such as notes payable, customer deposits~~Company's Vice President and ~~notes receivable are not shown as carrying value approximates fair value. See Note 5 for further fair value information for financial and derivative instruments.~~Treasurer.

~~December 31, 2009~~

~~December 31, 2008~~

~~Fair Value~~

~~Carrying Value~~

~~Fair Value~~

~~Carrying Value~~

~~Long-Term Debt~~

~~$5.2 billion~~

~~$5.0 billion~~

~~$5.2 billion~~

~~Investments in Debt and Equity Securities~~

The ~~Company generally classifies investments in debt~~following table presents the carrying amount 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~~financial instruments as adjustments to regulatory assets or liabilities, due to a recovery mechanism from customers. The Company’s investments are reviewed for impairment each reporting period. If the assessment indicates that the impairment is other than temporary, a loss is recognized resulting in the investment being written down to its estimated fair value.of December 31, 2012 and December 31, 2011:

December 31, 2012 December 31, 2011
Carrying Fair Value Carrying Fair
Amount Level 1 Level 2 Level 3 Amount Value
(In millions)
Notes receivable, excluding capital leases $ 5
$ —
$ —
$ 5
$ 6
$ 6
Notes receivable — affiliates —
—
—
—
26
26
Short-term borrowings — affiliates 80
—
—
80
64
64
Short-term borrowings — other 130
—
130
—
—
—
Long-term debt 4,963
—
5,021
620
5,051
5,740

Nuclear Decommissioning Trust Funds

~~Detroit Edison~~

DTE Electric has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. This obligation is reflected as an asset retirement obligation on the Consolidated Statements of Financial Position. ~~See Note 8 for additional information.~~

The NRC has jurisdiction over the decommissioning of nuclear power plants and requires decommissioning funding based upon a formula. The MPSC and FERC regulate the recovery of costs of decommissioning nuclear power plants and both require the use of external trust funds to finance the decommissioning of Fermi 2. Rates approved by the MPSC provide for the recovery of decommissioning costs of Fermi 2 and the disposal of low-level radioactive waste. ~~Detroit Edison~~DTE Electric is continuing to fund FERC jurisdictional amounts for decommissioning even though explicit provisions are not included in FERC rates. ~~The Company believes the MPSC and FERC collections will be adequate to fund the estimated cost~~See Note 7.

Table of decommissioning using the NRC formula. 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.Contents

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

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

December 31 December 31
(in Millions) 2009 2008
Fermi 2 $ 790 $ 649
Fermi 1 3 3
Low level radioactive waste 24 33

Total $ 817 $ 685



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

At December 31, ~~2009,~~2012, investments in the nuclear decommissioning trust funds consisted of approximately ~~51%~~61% in publicly traded equity securities, ~~48%~~38% in fixed debt instruments and 1% in cash equivalents. At December 31, ~~2008,~~2011, investments in the nuclear decommissioning trust funds consisted of approximately ~~42%~~57% in publicly traded equity securities, ~~57%~~41% in fixed debt instruments and 1%2% in cash equivalents. The debt securities at both December 31, ~~2009~~2012 and December 31, ~~2008~~2011 had an average maturity of approximately ~~5 years.~~6 and 7 years, respectively.

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

Year Ended December 31
2009 2008 2007
(in Millions)
Realized gains $ 37 $ 34 $ 25
Realized losses $ (55 ) $ (49 ) $ (17 )
Proceeds from sales of securities $ 295 $ 232 $ 286



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

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

(in Millions)
As of December 31, 2009
Equity securities $ 420 $ 135
Debt securities 388 17
Cash and cash equivalents 9 —

$ 817 $ 152

As of December 31, 2008
Equity securities $ 288 $ 65
Debt securities 388 17
Cash and cash equivalents 9 —

$ 685 $ 82



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

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

~~Impairment charges for unrealized~~

Unrealized losses incurred by the Fermi 2 trust are recognized as a ~~regulatory~~Regulatory asset. ~~Detroit Edison~~DTE Electric recognized ~~$48~~$44 million and ~~$92~~$67 million of unrealized losses as ~~regulatory~~Regulatory assets at December 31, ~~2009~~2012 and ~~2008,~~2011, respectively. Since the decommissioning of Fermi 1 is funded by ~~Detroit Edison~~DTE Electric rather than through a regulatory recovery mechanism, there is no corresponding regulatory asset treatment. Therefore, ~~impairment charges for~~ unrealized losses incurred by the Fermi 1 trust are recognized in earnings immediately. There were no ~~impairment charges~~ unrealized losses recognized in ~~2009~~2012, 2011 and ~~2008~~2010 for Fermi 1. ~~Detroit Edison recognized impairment charges of $0.2 million for Fermi 1 for the year ended December 31, 2007.~~

~~Other Available-For-Sale~~

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, 2009 December 31, 2008
(in Millions) Fair Value Carrying value Fair Value Carrying Value
Cash equivalents $ 105 $ 105 $ 98 $ 98
Equity securities $ 4 $ 4 $ 20 $ 20

At December 31, ~~2009~~2012 and ~~2008,~~2011, these securities are comprised primarily of money-market and equity securities. During the year ended December 31, 2012 and December 31, 2011 no amounts of unrealized losses on available for sale securities were reclassified out of other comprehensive income into net income for the periods. Gains ~~(losses)~~ related to trading securities held at December 31, ~~2009, 2008,~~2012, 2011, and ~~2007~~2010 were $8$9 million ~~$(14)~~, $3 million and $3$7 million, respectively.

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NOTE 54 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

The Company recognizes all derivatives at their fair value on the Consolidated Statements of Financial Position ~~at their fair value~~ unless they qualify for certain scope exceptions, including the normal purchases and normal sales exception. Further, derivatives that qualify and are designated for hedge accounting are classified as either hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge), or as hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge). For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the value of the underlying exposure is deferred in Accumulated other comprehensive income and later reclassified into earnings when the underlying transaction occurs. For fair value hedges, changes in fair values for the derivative are recognized in earnings each period. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For derivatives that do not qualify or are not designated for hedge accounting, changes in ~~the~~ fair value are recognized in earnings each period.

The ~~Company’s~~Company's primary market risk exposure is associated with commodity prices, credit and interest rates. The Company has risk management policies to monitor and manage market risks. The Company uses derivative instruments to manage some of the exposure. ~~Contracts the Company typically classifies as derivative instruments include power, certain coal forwards, futures, options and swaps.~~

~~Detroit Edison~~DTE Electric generates, purchases, distributes and sells electricity. ~~Detroit Edison~~DTE Electric 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, ~~2009:~~2012 and 2011:

Balance Sheet Fair
Location Value
(in Millions)
FTRs Other current assets $ 2
Emissions Other current liabilities (5 )
Emissions Other non-current liabilities (3 )

Total derivatives not designated as hedging instrument
$ (6 )

Total derivatives:

Current $ (3 )
Noncurrent (3 )

Total derivatives as reported
$ (6 )



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

The effect of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position were $15 million in gains related to FTRs recognized in Regulatory liabilities for the year ended December 31, ~~2009 is as follows:~~2012, and $3 million in gains related to FTRs recognized in Regulatory liabilities for the year ended December 31, 2011.

Year Ended
Location of Gain Gain (Loss)
(Loss) Recognized Recognized in
in Regulatory Regulatory Assets
Assets / Liabilities / Liabilities on
On Derivative Derivative
(in Millions)
FTRs and Emissions Regulatory Asset $ (14 )
FTRs and Emissions Regulatory Liability (2 )

Total
$ (16 )

The following represents the cumulative gross volume of derivative contracts outstanding as of December 31, ~~2009:~~2012:



Commodity		Number of Units
~~Emissions (Tons)~~FTRs (MWh)	49,411		~~61,927~~
~~FTRs (MW)~~			~~4,486~~

NOTE 65 — PROPERTY, PLANT AND EQUIPMENT

Summary of property by classification as of December 31:

(in Millions) 2009 2008
Property, Plant and Equipment

Generation $ 8,833 $ 8,544
Distribution 6,618 6,433

Total 15,451 14,977

Less Accumulated Depreciation and Amortization

Generation (3,890 ) (3,690 )
Distribution (2,243 ) (2,138 )

Total (6,133 ) (5,828 )

Net Property, Plant and Equipment
$ 9,318 $ 9,149

~~AFUDC~~



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

The Allowance for Funds used During Construction (AFUDC) capitalized during ~~2009~~2012 and ~~2008~~2011 was approximately ~~$12~~$19 million and ~~$44~~$9 million, respectively.

The composite depreciation rate for ~~Detroit Edison~~DTE Electric was approximately 3.3% in ~~2009, 2008~~2012, 2011 and ~~2007.~~2010.

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The average estimated useful life for our generation and distribution property was 40 years and 3741 years, respectively, at December 31, ~~2009.~~2012.

Capitalized software costs are classified as Property, plant and equipment and the related amortization is included in Accumulated depreciation and amortization on the Consolidated Statements of Financial Position. The Company capitalizes the costs associated with computer software it develops or obtains for use in its business. The Company amortizes capitalized software costs on a straight-line basis over the expected period of benefit, ranging from 5 to 15 years.

Capitalized software costs amortization expense was ~~$55~~$62 million in ~~2009, $45~~2012, $58 million in ~~2008,~~2011 and ~~$31~~$55 million in ~~2007.~~2010. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, ~~2009~~2012 were ~~$488~~$479 million and ~~$161~~$245 million, respectively. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, ~~2008~~2011 were ~~$454~~$501 million and ~~$126~~$218 million, respectively. Amortization expense of capitalized software costs is estimated to be ~~$60~~approximately $40 million annually for ~~2010~~2013 through ~~2014.~~2017.

Gross property under capital leases was ~~$121~~$6 million and $26 million at December 31, ~~2009~~2012 and December 31, ~~2008.~~2011, respectively. Accumulated amortization of property under capital leases was ~~$88~~$3 million and ~~$80~~$14 million at December 31, ~~2009~~2012 and December 31, ~~2008,~~2011, respectively.

NOTE 76 — JOINTLY OWNED UTILITY PLANT

~~Detroit Edison~~

DTE Electric has joint ownership interest in two power plants, Belle River and Ludington Hydroelectric Pumped Storage. ~~Detroit Edison’s~~DTE Electric’s share of direct expenses of the jointly owned plants are included in Fuel and purchased power ~~and gas~~ and Operation and maintenance expenses in the Consolidated Statements of Operations. Ownership information of the two utility plants as of December 31, ~~2009~~2012 was as follows:

Ludington
Hydroelectric
Belle River Pumped Storage
In-service date 1984-1985 1973
Total plant capacity 1,260 MW 1,872 MW
Ownership interest * 49 %
Investment (in Millions) $ 1,626 $ 197
Accumulated depreciation (in Millions) $ 889 $ 128



				Ludington Hydroelectric
	Belle River			Pumped Storage
In-service date	1984-1985			1973
Total plant capacity	1,270		MW	1,872			MW
Ownership interest			(a)	49		%
Investment (in millions)	$	1,661		$	199
Accumulated depreciation (in millions)	$	953		$	164


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

Belle River

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

Ludington Hydroelectric Pumped Storage

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

NOTE 87 — ASSET RETIREMENT OBLIGATIONS

The Company has a legal retirement obligation for the decommissioning costs for its Fermi 1 and Fermi 2 nuclear ~~plants.~~plants, dismantlement of facilities located on leased property and various other operations. The Company has conditional retirement obligations for ~~disposal of~~ asbestos and PCB removal at certain of its power ~~plants. To a lesser extent, the Company has conditional retirement obligations at certain service centers~~plants and ~~disposal costs for PCB contained within transformers and circuit breakers.~~various distribution equipment. The Company recognizes such obligations as liabilities at fair market value when they are incurred, which generally is at the time the associated assets are placed in service. Fair value is measured using expected future cash outflows discounted at our credit-adjusted risk-free rate. In its regulated operations, the Company ~~defers~~recognizes regulatory assets or liabilities for timing differences ~~that arise~~ in ~~the~~ expense recognition offor legal asset retirement costs that are currently recovered in rates.

~~No liability has been recorded with respect to lead-based paint, as the quantities~~

Table of ~~lead-based paint~~Contents

If a reasonable estimate of fair value cannot be made in the ~~Company’s facilities are unknown. In addition, there~~period in which the retirement obligation is ~~no incremental cost to demolitions~~incurred, such as for assets with indeterminate lives, the liability is recognized when a reasonable estimate 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.~~fair value can be made. Substations, manholes and certain other distribution assets ~~within Detroit Edison~~ have an indeterminate life. Therefore, no liability has been recorded for these assets.

A reconciliation of the asset retirement obligations for ~~2009~~2012 follows:

(in Millions)
Asset retirement obligations at January 1, 2009 $ 1,226
Accretion 80
Liabilities settled (10 )
Revision in estimated cash flows 4

Asset retirement obligations at December 31, 2009 1,300
Less amount included in current liabilities (15 )

$ 1,285

~~Detroit Edison~~



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

In 2001, DTE Electric began the final decommissioning of Fermi 1, with the goal of removing the remaining radioactive material and terminating the Fermi 1 license. In 2011, based on management decisions revising the timing and estimate of cash flows, DTE Electric accrued an additional $19 million with respect to the decommissioning of Fermi 1. Management has ~~a legal obligation to decommission its nuclear power plants following~~suspended decommissioning activities and placed the ~~expiration of their operating licenses. This obligation is reflected as an asset retirement obligation~~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 ~~Financial Position. Based~~Operations. In addition, in 2011, based on updated studies revising the timing and estimate of cash flows, a reduction of approximately $20 million was made to the DTE Electric asset retirement obligation for asbestos removal with approximately $6 million of the decrease associated with Fermi 1 recorded in Asset (gains) and losses, reserves and impairments, net on the ~~actual or anticipated extended life~~Consolidated Statements of Operations.

In October 2011, the MPSC approved DTE Electric's request for a reduction to the nuclear decommissioning surcharge under the assumption that it would request an extension of the ~~nuclear plant, decommissioning expenditures for~~ Fermi 2 ~~are expected~~license for an additional 20 years beyond the term of the existing license which expires in 2025. DTE Electric expects to ~~be incurred primarily during~~request the ~~period~~license extension in 2014. This proposed extension of ~~2025 through 2050.~~the license, including the associated impact on spent nuclear fuel, resulted in a revision in estimated cash flows for the Fermi 2 asset retirement obligation of approximately $22 million in 2011. It is estimated that the cost of decommissioning Fermi 2 ~~when its license expires~~is $1.5 billion in ~~2025, will be $1.3 billion in 2009~~2012 dollars and ~~$3.4~~$10 billion in ~~2025~~2045 dollars, using a 6% inflation rate. In 2001, Detroit Edison began the decommissioning of Fermi 1, with the goal of removing the radioactive material and terminating the Fermi 1 license. The decommissioning of Fermi 1 is expected to be completed by 2012. Approximately ~~$1.2~~$1.5 billion of the asset retirement obligations represent nuclear decommissioning liabilities that are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear plant.

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

A portion of the funds recovered through the Fermi 2 decommissioning surcharge and deposited in external trust accounts is designated for the removal of non-radioactive assets and returning the ~~clean-up of the Fermi site.~~site to greenfield. This removal and

~~clean-up~~ greenfielding is not considered a legal liability. Therefore, it is not included in the asset retirement obligation, but is reflected as the nuclear decommissioning liability.

The decommissioning of Fermi 1 is funded by ~~Detroit Edison.~~DTE Electric. Contributions to the Fermi 1 trust are discretionary. See Note 43 for additional discussion of Nuclear Decommissioning Trust Fund Assets.

NOTE ~~9 — RESTRUCTURING~~

~~Performance Excellence Process~~

In 2005, the Company initiated a company-wide review of its operations called the Performance Excellence Process. Specifically, the Company began a series of focused improvement initiatives within Detroit Edison and associated corporate support functions. The Company incurred costs to achieve (CTA) restructuring expense for employee severance and other costs. Other costs include project management and consultant support. In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison, commencing in 2006, to defer the incremental CTA. Further, the order provides 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 deferred approximately $24 million and $54 million of CTA in 2008 and 2007 as a regulatory asset. The recovery of these costs was provided for by the MPSC in the order approving the settlement in the show cause proceeding and in the December 23, 2008 MPSC rate order. Amortization of prior year deferred CTA costs amounted to $18 million in 2009, $16 million in 2008 and $10 million in 2007.

Amounts expensed are recorded in the Operation and maintenance line on the Consolidated Statements of Operations. Deferred amounts are recorded in Regulatory assets on the Consolidated Statements of Financial Position. Costs incurred in 2008 and 2007 are as follows:

Employee Severance Costs(1) Other Costs Total Cost
(in Millions) 2008 2007 2008 2007 2008 2007
Costs incurred: $ — $ 15 $ 26 $ 50 $ 26 $ 65
Less amounts deferred or capitalized: — 15 26 50 26 65

Amount expensed $ — $ — $ — $ — $ — $ —


~~(1)~~		~~Includes corporate allocations~~

~~NOTE 10~~8 — REGULATORY MATTERS

~~Regulation~~

~~Detroit Edison~~Regulation

DTE Electric is subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to rates, recovery of certain costs, including the costs of generating facilities and regulatory assets, conditions of service, accounting and operating-related matters. ~~Detroit Edison~~DTE Electric is also regulated by the FERC with respect to financing authorization and wholesale electric activities. Regulation results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses.

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

Regulatory Assets and Liabilities

~~Detroit Edison~~

DTE Electric is required to record regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Continued applicability of regulatory accounting treatment requires that rates be designed to recover specific costs of providing regulated services and be charged to and collected from customers. Future regulatory changes or changes in the competitive environment could result in the discontinuance of this accounting treatment for regulatory assets and liabilities for some or all of our businesses and may require the write-off of the portion of any regulatory asset or liability that was no longer probable of recovery through regulated rates. Management believes that currently available facts support the continued use of regulatory assets and liabilities and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment.

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

(in Millions) 2009 2008

Assets

Recoverable pension and postretirement costs:
Pension $ 1,261 $ 1,133
Postretirement costs 515 609
Recoverable income taxes related to securitized regulatory assets 476 549
Asset retirement obligation 415 452
Deferred income taxes — Michigan Business Tax 343 336
Costs to achieve Performance Excellence Process 136 154
Other recoverable income taxes 89 89
Enterprise Business Systems costs 24 26
Recoverable costs under PA 141
Unamortized loss on reacquired debt 38 40
Electric Customer Choice implementation costs 18 37
Deferred Clean Air Act expenditures — 10
Accrued PSCR revenue — 20
Other 18 21

3,333 3,476
Less amount included in current assets — (20 )

$ 3,333 $ 3,456

Securitized regulatory assets $ 870 $ 1,001

Liabilities

Deferred income taxes — Michigan Business Tax $ 367 $ 335
Asset removal costs 157 182
Accrued pension 75 72
Renewable energy program 32 —
Refundable costs under PA 141 27 16
Refundable self implemented rates 27 —
Refundable restoration expense 15 —
Accrued PSCR refund 14 11
Fermi 2 refueling outage 13 25
Other 11 4

738 645
Less amount included in current liabilities (27 ) (52 )

$ 711 $ 593



	2012			2011
Assets	(In millions)
Recoverable pension and postretirement costs:
Pension	$	1,815		$	1,656
Postretirement costs	316			582
Asset retirement obligation	424			420
Recoverable Michigan income taxes	253			270
Recoverable income taxes related to securitized regulatory assets	226			316
Accrued PSCR revenue	87			147
Cost to achieve Performance Excellence Process	82			100
Other recoverable income taxes	76			81
Choice incentive mechanism	66			166
Recoverable restoration expense	49			58
Unamortized loss on reacquired debt	37			36
Enterprise Business Systems costs	16			18
Other	63			40
	3,510			3,890
Less amount included in current assets	(162		)	(272		)
	$	3,348		$	3,618
Securitized regulatory assets	$	413		$	577
Liabilities
Renewable energy	$	230		$	192
Refundable revenue decoupling / deferred gain	127			127
Asset removal costs	81			73
Over recovery of Securitization	54			53
Energy Optimization	26			24
Fermi 2 refueling outage	12			23
Refundable uncollectible expense	10			13
Low Income Energy Efficiency Fund	—			23
Other	9			6
	549			534
Less amount included in current liabilities	(66		)	(80		)
	$	483		$	454

As noted below, regulatory assets for which costs have been incurred have been included (or are expected to be included, for costs incurred subsequent to the most recently approved rate case) in ~~Detroit Edison’s~~DTE Electric's rate base, thereby providing a return on invested ~~costs.~~costs (except as noted). Certain other regulatory assets are not included in rate base but accrue recoverable carrying charges until surcharges to collect the assets are billed. Certain regulatory assets do not result from cash expenditures and therefore do not represent investments included in rate base or have offsetting liabilities that reduce rate base.

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ASSETS

•		~~Recoverable pension and postretirement costs~~— In 2007, the Company adopted ASC 715 (SFAS No. 158) which required, 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 charge related to the additional liability 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 recognized as benefit expenses in net income. (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.

•		~~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)

•		~~Deferred income taxes — Michigan Business Tax (MBT)~~— In July 2007, the MBT was enacted by the State of Michigan. State deferred tax liabilities were established for the Company’s utilities, and offsetting regulatory assets were recorded as the impacts of the deferred tax liabilities will be reflected in rates as the related taxable temporary differences reverse and flow through current income tax expense. (1)

•		~~Cost to achieve Performance Excellence Process (PEP)~~— The MPSC authorized the deferral of costs to implement the PEP. These costs consist of employee severance, project management and consultant support. These costs will be amortized over a ten-year period beginning with the year subsequent to the year the costs were deferred. (1)

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

•		~~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. (1)~~

•		~~Unamortized loss on reacquired debt~~~~— The unamortized discount, premium and expense related to debt redeemed with a refinancing are deferred, amortized and recovered over the life of the replacement issue. (1)~~

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

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

•		~~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.~~

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

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

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

Recoverable Michigan income taxes —In July 2007, the MBT was enacted by the State of Michigan. A State deferred tax liability was established, and an offsetting regulatory asset was recorded as the impact of the deferred tax liability will be reflected in rates as the related taxable temporary difference reverses and flows through current income tax expense. In May 2011, the MBT was repealed and the MCIT was enacted. The regulatory asset was remeasured to reflect the impact of the MCIT tax rate. (a)

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

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

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

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

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

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

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

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

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


~~(1)~~	(a)	Regulatory assets not earning a ~~return.~~return or accruing carrying charges.

LIABILITIES

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

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

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

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

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

•		~~Refundable costs under PA 141 —~~Detroit Edison’s 2007 Choice Incentive Mechanism (CIM) reconciliation and allocation resulted in the elimination of Regulatory Asset Recovery Surcharge (RARS) balances for commercial and industrial customers. RARS revenues received in 2008 that exceed the regulatory asset balances are required to be refunded to the affected classes.

•		~~Refundable self implemented rates —~~~~Amounts due customers for self implemented rates in excess of amounts provided for in January 2010 Detroit Edison MPSC order.~~

•		~~Refundable restoration expense —~~Amounts refundable for the MPSC approved restoration expenses tracking mechanism that tracks the difference between actual restoration expense and the amount provided for in base rates, recognized pursuant to the MPSC authorization.

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

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

Refundable revenue decoupling/deferred gain — At December 31, 2011, amounts were accrued as refundable to DTE Electric customers for the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established by the MPSC. In 2012, the revenue decoupling liability was reversed and a new regulatory liability representing DTE Electric's obligation to refund the resulting gain was accrued. See further discussion below.

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

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

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

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

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

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

2009 Electric Rate Case Filing- Court of Appeals Decision

On April 10, 2012, the Michigan Court of Appeals (COA) issued a decision relating to an appeal of the January ~~11,~~ 2010 MPSC order in DTE Electric's January 2009 rate case filing.

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

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

On August 1, 2012, DTE Electric filed an application for approval of accounting authority to defer for future amortization the gain resulting from the reversal of the Company's $127 million regulatory liability associated with the operation of the RDM. On August 14, 2012, the MPSC dismissed DTE Electric's initial pilot RDM reconciliation case. On September 25, 2012, the MPSC issued an order in Detroit Edison’s January 26, 2009 rate case filing. The MPSC approved an annual revenue increase of $217 million or a 4.8% increase in Detroit Edison’s annual revenue requirement for 2010. Includedapproving the Company's accounting application. As described in the ~~approved~~accounting application, DTE Electric will amortize the new regulatory liability to income, at a monthly rate of approximately $10.6 million, beginning January 2014. It is currently anticipated that with this accounting treatment, along with other cost saving measures, DTE Electric will not need to increase ~~in revenues was a return on equity of 11% on an expected 49% equity~~base rates until 2015. If DTE Electric's base rates are increased prior to January 1, 2015, the Company will cease amortization and ~~51% debt capital structure. Since~~refund to customers the final rate relief ordered was less than the Company’s self-implemented rate increase of $280 million effective on July 26, 2009, the MPSC ordered refunds for the period the self-implemented rates were in effect. Detroit Edison has recorded a refund liability of $27 million at December 31, 2009 representing the 2009 portionremaining unamortized balance of the ~~estimated refund due customers, including interest. The MPSC ordered Detroit Edison to file a refund plan by April 1, 2010.~~new regulatory liability.

~~Other key aspects of the MPSC order include the following:~~

	•		~~Continued progress toward correcting the existing rate structure to more accurately reflect the actual cost of providing service to business customers;~~

	•		~~Continued application of an adjustment mechanism for Electric Choice sales that reconciles actual customer choice sales with a base customer choice sales level of 1,586 GWh;~~

	•		Continued application of adjustment mechanisms to track expenses associated with restoration costs (storm and non-storm related expenses) and line clearance expenses. Annual reconciliations will be required using a base expense level of $117 million and $47 million, respectively. The change in base expense level was applied effective as of the July 26, 2009 self-implementation date;

	•		Implementation of a pilot Revenue Decoupling Mechanism, that will compare actual non-weather normalized sales per customer with the base sales per customer level established in this case for the period February 1, 2010 to January 31, 2011; and

	•		Implementation of an Uncollectible Expense Tracking Mechanism, based on a $66 million expense level, with an 80/20 percent sharing of the expenses above or below the base amount. The Uncollectible Expenses Tracking Mechanism was applied effective as of the July 26, 2009 self-implementation date.

~~Renewable Energy Plan~~

In March 2009, Detroit Edison filed its Renewable Energy Plan with the MPSC as required under 2008 PA 295. The Renewable Energy Plan application requests authority to recover approximately $35 million of additional revenue in 2009. The proposed revenue increase is necessary in order to properly implement Detroit Edison’s 20-year renewable energy plan to address the provisions of 2008 PA 295, 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. An MPSC order was issued June 2, 2009 approving the renewable energy plan and customer surcharges. The Renewable Energy Plan surcharges became effective in September 2009.

Energy Optimization (EO) Plans

~~In March 2009, Detroit Edison filed an Energy Optimization Plan with the MPSC as required under 2008 PA 295.~~

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

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

In August 2012, DTE Electric filed an amended EO plan with the MPSC. The plan application proposed ~~energy optimization~~the recovery of EO expenditures for the period ~~2009-2011~~2013-2015 of ~~$134~~$224 million and further ~~requests~~requested approval of ~~surcharges that are designed~~a surcharge to recover these costs. On December 20, 2012, the MPSC approved DTE Electric's EO plan.

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

In January 2012, DTE Electric filed an application with the MPSC for approval of the reconciliation of its 2011 RETM and LCT. The Company's 2011 restoration expenses were higher than the amount provided in rates. Accordingly, DTE Electric requested net recovery of approximately $44 million. An MPSC order ~~was issued June 2, 2009 approving~~is expected in the ~~Energy Optimization Plans~~first quarter of ~~$117~~2013.

DTE Electric Uncollectible Expense True-Up Mechanism (UETM)

In February 2012, DTE Electric filed an application with the MPSC for approval of its UETM for 2011 requesting authority to refund approximately $9 million ~~for Detroit Edison. The surcharges~~ consisting of costs related to ~~recover these costs were implemented effective June 3, 2009.~~2011 uncollectible expense. An MPSC order ~~was issued September 29, 2009 approving incentive mechanisms for~~is expected in the ~~utility. The mechanism allows a maximum payout~~first quarter of ~~15%~~2013.

Table of ~~program expenditures when the utility meets or exceeds the savings target by 15%.~~Contents

DTE Electric Choice Incentive Mechanism (CIM)

~~2009 Detroit Edison Depreciation Filing~~

In ~~2007, the MPSC ordered Michigan utilities to file depreciation studies using the current method,~~January 2012, DTE Electric filed an ~~approach that considers the time value of money and an inflation adjusted method proposed by the Company that removes excess escalation. In compliance~~application with the MPSC ~~order, Detroit Edison filed~~for approval of its ~~ordered depreciation studies in November 2009. The various required depreciation studies indicate composite depreciation rates~~CIM reconciliation for the period from ~~3.05%~~January 1, 2011 through October 28, 2011, the termination date of the CIM pursuant to ~~3.54%. The~~the October 20, 2011 MPSC rate order. On January 17, 2013, the MPSC approved a settlement agreement authorizing the Company ~~has proposed no change~~ to recover $63 million, plus interest, from its ~~current composite depreciation rate of 3.33%. The Company expects an order in this proceeding in the fourth quarter of 2010.~~customers through a surcharge to be implemented over a ten-month period beginning March 2013 through December 2013.

Power Supply Cost Recovery Proceedings

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

~~2007 Plan~~

2011 PSCR Year— ~~An MPSC order was issued on January 25,~~In March 2012, DTE Electric filed the 2011 PSCR reconciliation calculating a net under-recovery of $148 million that includes an under-recovery of $52.6 million for the 2010 ~~approving a 2007~~ PSCR ~~under collection amount of $38 million inclusive of a $2.7 million outage disallowance and the recovery of this amount as part of the 2008 PSCR reconciliation.~~year. In addition, the ~~order approved Detroit Edison’s Pension Equalization Mechanism reconciliation and authorized the Company to refund the $21 million over recovery, including interest, to customers in February 2010.~~

~~The following table summarizes Detroit Edison’s~~2011 PSCR reconciliation includes an over-refund of $3.8 million for the 2011 refund of the self-implementation rate increase related to the 2009 electric rate case filing ~~currently pending with~~and a credit of $10.5 million related to the ~~MPSC:~~expiration of a wholesale power sales contract.


		~~Net Over~~	~~PSCR Cost of Power~~	~~Description of Net~~
~~PSCR Year~~	~~Date Filed~~	~~(Under)-recovery~~	~~Sold~~	~~Under-recovery~~

~~2008~~	~~March 2009~~	~~($15.6) million~~	~~$1.3 billion~~	~~The total amount reflects an under-recovery of $14.8 million, plus $0.8 million in accrued interest due from customers~~

~~2009~~2013 Plan Year— In September ~~2008, Detroit Edison submitted~~2012, DTE Electric filed its 2009 PSCR plan filing to the MPSC. The plan includes the recovery of its 2008 PSCR under-collection from all customers and the refund of its 2005 PSCR reconciliation surcharge over-collection to commercial and industrial customers only. On June 29, 2009, the parties to this proceeding submitted a Settlement Agreement in this matter agreeing to maximum PSCR factors of 1.67 mills/kWh for residential customers and 1.35 mills/kWh for commercial and industrial customers and otherwise resolving this 2009 PSCR Plan case. An MPSC order was issued on January 25, 2010 approving the settlement.

~~2010 Plan Year~~~~— In September 2009, Detroit Edison submitted its 2010~~2013 PSCR plan case seeking approval of a levelized PSCR factor of ~~5.64~~ 4.74mills/kWh ~~below~~above the amount included in base rates for all PSCR customers. The filing supports a ~~2010~~total power supply expense forecast of ~~$1.2 billion. Also included in the filing is a request~~$1.5 billion. The plan also includes approximately $81 million for approval of the Company’s expense associated with the use of urea in the selective catalytic reduction units at Monroe power plant as well as a request for approval of a contract for capacity and energy associated with a wind energy project. The Company has also requested authority to recover transfer prices for renewable energy, coke oven gas expense and other potential expenses.

~~Merger Control Premium Costs~~

In July 2007, the State of Michigan Court of Appeals published its decision with respect to an appeal by Detroit Edison and others of certain provisions of a November 2004 MPSC order, including reversing the MPSC’s denial of recovery of merger control premium costs. In its published decision, the Court of Appeals held that Detroit Edison is entitled to recover its allocated share of the merger control premium and remanded this matter to the MPSC for further proceedings to establish the precise amount and timing of this recovery. Other parties filed requests for leave to appeal to the Michigan Supreme Court from the Court of Appeals decision and in September 2008, the Michigan Supreme Court granted the requests to address the merger control premium as well as the recovery of transmission costs through the PSCR. On May 1, 2009, the Michigan Supreme Court issued an order reversing the Court of Appeals decision with respect to recovery of the merger control premium, and reinstated the MPSC’s decision excluding the control premium costs from Detroit Edison’s general rates. The Court affirmed the lower court’s decision upholding the right of Detroit Edison to recover electric transmission costs through the Company’sits projected 2012 PSCR clause. The Company requested rehearing of the Supreme Court order on the merger premium and the Michigan Attorney General requested rehearing of the transmission portion of the order. On June 26, 2009, the Michigan Supreme Court denied request for a rehearing. The above actions did not have an impact on the Company’s consolidated financial statements.under-recovery.

~~Other~~

NOTE 119 — 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~~DTE Electric is determined on an individual company basis with no allocation of tax ~~benefits~~expenses or ~~expenses~~benefits from other affiliates of DTE Energy. We had an income tax payable to DTE Energy of ~~$75~~$13 million at December 31, ~~2009~~2012 and we had an income tax ~~payable~~receivable from DTE Energy of ~~$33~~$48 million at December 31, ~~2008 due to DTE Energy.~~2011.

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

(Dollars in Millions) 2009 2008 2007
Income tax expense at 35% statutory rate $ 211 $ 181 $ 163

Investment tax credits (6 ) (6 ) (7 )
Depreciation 3 3 3
Employee Stock Ownership Plan dividends (4 ) (2 ) (4 )
Medicare Part D subsidy (5 ) (4 ) (4 )
Domestic production activities deduction (5 ) (2 ) (2 )
State and other income taxes, net of federal benefit 36 19 1
Other, net (2 ) (3 ) (1 )

Total $ 228 $ 186 $ 149

Effective income tax rate 37.7 % 36.0 % 32.0 %



	2012			2011			2010
	(In millions)
Income before income taxes	$	768		$	704		$	711
Income tax expense at 35% statutory rate	$	269		$	246		$	249
Investment tax credits	(6		)	(6		)	(6		)
Depreciation	3			3			3
Employee Stock Ownership Plan dividends	(3		)	(3		)	(3		)
Domestic production activities deduction	(16		)	(6		)	(6		)
State and other income taxes, net of federal benefit	40			39			40
Other, net	(5		)	(6		)	(7		)
Income Tax Expense	$	282		$	267		$	270
Effective income tax rate	36.7		%	38.0		%	38.0		%

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

(in Millions) 2009 2008 2007
Current income taxes Federal $ 168 $ 66 $ 257
State and other income tax expense 45 30 3

Total current income taxes 213 96 260

Deferred income taxes Federal 4 91 (109 )
State and other income tax expense 11 (1 ) (2 )

Total deferred income taxes 15 90 (111 )

Total $ 228 $ 186 $ 149

~~Investment tax credits are deferred and amortized to income over the average life of the related property.~~



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

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

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

(in Millions) 2009 2008
Property, plant and equipment $ (1,409 ) $ (1,297 )
Securitized regulatory assets (474 ) (545 )
Pension and benefits 103 110
Other comprehensive income 9 (1 )
Other, net (76 ) (142 )

$ (1,847 ) $ (1,875 )



	2012			2011
	(In millions)
Property, plant and equipment	$	(2,578	)	$	(2,285	)
Securitized regulatory assets	(261		)	(384		)
Pension and benefits	73			67
Other comprehensive income	15			15
Other, net	(24		)	(182		)
	$	(2,775	)	$	(2,769	)

Current deferred income tax liability (included in Current Liabilities — Other)	$	(14	)	$	(68	)
Long-term deferred income tax liabilities	$	(2,761	)	$	(2,701	)
	$	(2,775	)	$	(2,769	)

Deferred income tax assets	$	557		$	608
Deferred income tax liabilities	(3,332		)	(3,377		)
	$	(2,775	)	$	(2,769	)

(in Millions) 2009 2008
Deferred income tax liabilities $ (2,832 ) $ (2,777 )
Deferred income tax assets 985 902

$ (1,847 ) $ (1,875 )

Current deferred income tax asset (included in Current Assets — Other) $ 24 $ 19
Long term deferred income tax liabilities (1,871 ) (1,894 )

$ (1,847 ) $ (1,875 )

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) 2009 2008 2007
Balance at January 1 $ 70 $ 7 $ 12
Additions for tax positions of current years 10 72 2
Additions for tax positions of prior years 24 (9 ) —
Reductions for tax positions of prior years (8 ) — (7 )

Balance at December 31 $ 96 $ 70 $ 7

~~Unrecognized~~



	2012			2011			2010
	(In millions)
Balance at January 1	$	59		$	18		$	96
Additions for tax positions of prior years	—			45			1
Reductions for tax positions of prior years	(3		)	(5		)	—
Additions for tax positions of current year	—			1			6
Settlements	(52		)	—			(85		)
Balance at December 31	$	4		$	59		$	18

The Company had $3 million and $4 million of unrecognized tax benefits at December 31, ~~2009,~~2012 and at December 31, 2011, respectively, that, if recognized, would favorably impact our effective tax ~~rate by $2 million.~~rate. The Company does not anticipate any material decrease in unrecognized tax benefits in the next 12 months.

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The Company recognizes interest and penalties pertaining to income taxes in Interest expense and Other expenses, respectively, on its Consolidated Statements of Operations. Accrued interest pertaining to income taxes totaled $6$1 million and $1$2 million at December 31, ~~2009~~2012 and December 31, ~~2008,~~2011, respectively. The Company had no accrued penalties pertaining to income taxes. The Company recognized ~~$5 million for~~ interest expense (income) related to income taxes ~~during 2009~~of $(3) million, $1 million and ~~an immaterial amount during 2008.~~$1 million in 2012, 2011 and 2010, respectively.

In ~~2009,~~2012, DTE Energy and its subsidiaries settled a federal tax audit for the ~~2004 through 2006~~2009 and 2010 tax ~~years. The resulting change to~~years, which resulted in the recognition of $52 million of unrecognized tax benefits ~~was not significant.~~by Detroit Edison. The ~~Company’s U.S.~~Company's federal income tax returns for years ~~2007~~2011 and subsequent years remain subject to examination by the IRS. The ~~Company’s~~Company's Michigan Business Tax returns for the year 2008 and subsequent years is subject to examination by the State of Michigan. The Company also files tax returns in numerous state and local jurisdictions with varying statutes of limitation.

Michigan ~~Business~~Corporate Income Tax (MCIT)

~~In July 2007,~~

On May 25, 2011, the Michigan Business Tax (MBT) was ~~enacted by the State of Michigan to replace~~repealed and the Michigan ~~Single Business~~Corporate Income Tax ~~(MSBT)~~was enacted effective January 1, ~~2008.~~2012. The ~~MBT is comprised of~~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 ~~0.8 percent and an apportioned business income~~the MBT to offset deferred tax liabilities that resulted from enactment of ~~4.95 percent. The MBT provides credits for Michigan business investment, compensation, and research and development. Legislation was also enacted, in 2007, by~~ the ~~State~~MBT.

As a result of ~~Michigan creating a deduction for businesses that realize an increase in their~~the enactment of the MCIT, the net state deferred tax liability ~~due~~was remeasured to reflect the impact of the new MCIT tax rate on cumulative temporary differences expected to reverse after the effective date. The net impact of this remeasurement was a decrease in deferred income tax liabilities of $30 million that was offset against the regulatory asset established upon the enactment of the MBT. ~~The MBT is accounted for as an income tax.~~

~~The MBT consolidated deferred tax liability balance is $354 million as of December 31, 2009 and is reported net~~Due to the elimination of the ~~related federal~~future tax ~~benefit. The~~deductions allowed under the MBT, the one-time MBT deferred tax asset ~~balance is $367 million as of December 31, 2009 and is reported net~~that was established upon the enactment of the ~~related federal~~MBT has been remeasured to zero. The net impact of this remeasurement is a reduction of net deferred tax ~~liability.~~assets of $342 million. The ~~regulated asset balance is $343~~$342 million ~~and~~ decrease in deferred tax assets was offset against the ~~regulated liability balance is $367 million as~~regulatory liabilities established upon enactment of ~~December 31, 2009 and is further discussed~~the MBT.

Consistent with the original establishment of these deferred tax assets (liabilities), no recognition of these non-cash transactions have been reflected in ~~Note 10.~~the Consolidated Statements of Cash Flows.

NOTE 1210 — LONG-TERM DEBT

~~Our~~

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

(in Millions) 2009 2008
Detroit Edison Taxable Debt, Principally Secured

5.9% due 2010 to 2038 $ 2,829 $ 2,841
Detroit Edison Tax- Exempt Revenue Bonds (2)

5.5% due 2011 to 2038 1,263 1,263

4,092 4,104
Less amount due within one year (513 ) (13 )

$ 3,579 $ 4,091

Securitization Bonds

6.5% due 2010 to 2015 $ 933 $ 1,064
Less amount due within one year (140 ) (132 )

$ 793 $ 932



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

Securitization Bonds
6.6% due 2013 to 2015	$	479		$	643
Less amount due within one year	(177		)	(164		)
	$	302		$	479


~~(1)~~	(a)	Weighted average interest rates as of December 31, ~~2009~~2012 are shown below the description of each category of debt.


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

40
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Debt Issuances

In ~~2009, we~~2012, the Company issued the following long-term debt:

(in Millions)
Month Issued Type Interest Rate Maturity Amount

April Tax-Exempt Revenue Bonds (1) 6.00 % 2036 69
June Tax-Exempt Revenue Bonds (2) 5.625 % 2020 32
June Tax-Exempt Revenue Bonds (3) 5.25 % 2029 60
June Tax-Exempt Revenue Bonds (4) 5.50 % 2029 59
November Tax-Exempt Revenue Bonds (5) 3.05 % 2024 65

$ 285



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

_____________________________


~~(1)~~	(a)	Proceeds were used ~~to refund existing Tax-Exempt Revenue Bonds.~~

~~(2)~~		~~These Tax-Exempt Revenue Bonds were converted from a variable rate mode~~for the early redemption of DTE Electric long-term debt; for the repayment of short-term borrowings; and ~~remarketed in a fixed rate mode to maturity.~~

~~(3)~~		~~These Tax-Exempt Revenue Bonds were converted from a variable rate mode and remarketed in a fixed rate mode with a five-year mandatory put.~~

~~(4)~~		~~These Tax-Exempt Revenue Bonds were converted from a variable rate mode and remarketed in a fixed rate mode with a seven-year mandatory put.~~

~~(5)~~		~~These Tax-Exempt Revenue Bonds were issued in a fixed rate mode with a three-year mandatory put. Proceeds were used to refund existing Tax-Exempt Revenue Bonds.~~for general corporate purposes.

Debt ~~Retirements and~~ Redemptions

~~The~~

In 2012, the following debt was ~~retired, through optional redemption or payment at maturity, during 2009.~~

(in Millions)
Month Retired Type Interest Rate Maturity Amount

April Tax-Exempt Revenue Bonds (1) Variable 2036 $ 69
December Tax-Exempt Revenue Bonds (1) 6.40 % 2024 65

$ 134

redeemed:


~~(1)~~		~~These Tax-Exempt Revenue Bonds were redeemed with the proceeds from the issuance of new Detroit Edison Tax-Exempt Revenue Bonds.~~



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

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

2015 &
(in Millions) 2010 2011 2012 2013 2014 thereafter Total
Amount to mature $ 513 $ 152 $ 303 $ 313 $ 341 $ 2,475 $ 4,097

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

Cross Default Provisions

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

NOTE 1311 — PREFERRED AND PREFERENCE SECURITIES

At December 31, ~~2009, Detroit Edison~~2012, DTE Electric had approximately 6.75 million shares of preferred stock with a par value of ~~$100~~$100 per share and 30 million shares of preference stock with a par value of $1$1 per share authorized, with no shares issued.

NOTE 1412 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

~~Detroit Edison~~

DTE Electric has a ~~$69~~$300 million ~~five-year~~ unsecured revolving credit agreement ~~expiring in October 2010 and a $212 million, two-year unsecured revolving credit agreement expiring in April 2011. The five-year and two-year credit facilities are~~ with a syndicate of 2220 banks ~~and~~that may be used for general corporate borrowings, but ~~are~~is intended to provide liquidity support for ~~our~~the Company's commercial paper program. No one bank provides more than 8.5% of the commitment in ~~any~~the facility. Borrowings under the ~~facilities~~facility are available at prevailing short-term interest rates. The ~~above agreements require~~facility will expire in October 2016. At December 31, 2012, there was $130 million outstanding against this facility, while there were no amounts outstanding against this facility at December 31, 2011.

The agreement requires the Company to maintain a total funded debt to capitalization ratio ~~as defined in the agreements,~~ of no more than 0.65 to 1.1. In the agreements, “total funded debt” means all indebtedness of the Company and its consolidatedsubsidiaries, including capital lease obligations, hedge agreements and guarantees of third parties' debt, but excluding contingent obligations and nonrecourse and junior subordinated debt. “Capitalization” means the sum of (a) total funded debt plus (b) “consolidated net worth,” which is equal to consolidated total stockholders' equity of the Company and its consolidated subsidiaries (excluding pension effects under certain FASB statements), as determined in accordance with accounting principles generally accepted in the United States of America. At December 31, ~~2009,~~2012, the total funded debt to total capitalization ratio for ~~Detroit Edison is~~ DTE Electric was 0.52 to ~~1. Should we have delinquent obligations~~1.

Table of ~~at least $50 million to any creditor; such delinquency will be considered a default under our credit agreements.~~Contents

~~We had no outstanding commercial paper of as of December 31, 2009 and December 31, 2008.~~

~~Detroit Edison had no short-term borrowings at December 31, 2009 and $75 million outstanding at December 31, 2008.~~ The weighted average interest rate for short-term borrowings was ~~1.3%~~0.4% at December 31, ~~2008.~~2012.

NOTE 1513 — CAPITAL AND OPERATING LEASES

~~Lessee~~—

The Company leases various assets under capital and operating leases, including coal ~~cars,~~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, ~~2009~~2012 were:

Capital Operating
(in Millions) Leases Leases
2010 $ 9 $ 23
2011 7 22
2012 5 22
2013 5 19
2014 4 14
Thereafter 7 77

Total minimum lease payments 37 $ 177

Less imputed interest 5

Present value of net minimum lease payments 32
Less current portion 7

Non-current portion $ 25



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

Rental expense for operating leases was ~~$48~~$29 million in ~~2009, $39~~2012, $27 million in ~~2008,~~2011, and ~~$48~~$22 million in ~~2007.~~2010. Contingent rental payments of $27 million were incurred in 2012 related to power purchase agreements. The contingent payments are based upon delivery of energy and renewable energy credits, which are dependent upon future production.

NOTE 1614 — COMMITMENTS AND CONTINGENCIES

~~Environmental~~

Environmental

Air— ~~Detroit Edison~~ DTE Electric is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze, mercury, and ~~mercury~~other air pollution. ~~The new~~These rules ~~will lead~~have led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, mercury and ~~mercury~~other emissions. To comply with these requirements, ~~Detroit Edison~~DTE Electric has spent approximately ~~$1.5~~$1.9 billion through ~~2009.~~2012. The Company estimates ~~Detroit Edison~~DTE Electric will make ~~future undiscounted~~ capital expenditures of ~~up to $73~~approximately $335 million in ~~2010~~2013 and up to ~~$2.2~~approximately $1.6 billion of additional capital expenditures through ~~2019~~2020 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants. The Cross State Air Pollution Rule (CSAPR), finalized in July 2011, requires further reductions of sulfur dioxide and nitrogen oxides emissions beginning in 2012. On December 30, 2011, the U. S. Court of Appeals for the District of Columbia Circuit granted the motions to stay the rule, leaving DTE Electric temporarily subject to the previously existing Clean Air Interstate Rule (CAIR). On August 21, 2012, the Court issued its decision, vacating CSAPR and leaving CAIR in place. The EPA's petition seeking a rehearing of the U.S. Court of Appeals decision regarding the CSAPR was denied on January 24, 2013. The Electric Generating Unit Maximum Achievable Control Technology (EGU MACT) Rule was finalized on December 16, 2011. The EGU MACT requires reductions of mercury and other hazardous air pollutants ~~(HAPs). It~~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 ~~those expected rulemakings at this time.~~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~~ DTE Electric power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and ~~Title V~~ operating permit requirements under the Clean Air Act. WeAn additional NOV/FOV was received in June 2010 related to a recent project and outage at Unit 2 of the Monroe Power Plant.

On August 5, 2010, the U. S. Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and DTE Electric, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require DTE Electric to install and operate the best available control technology at Unit 2 of the

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Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require DTE Electric to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from DTE Electric's fleet of coal-fired power plants until the new control equipment is operating.

On August 23, 2011, the U.S. District judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy.On October 20, 2011, the EPA caused to be filed a Notice of Appeal. Oral arguments took place on November 27, 2012 in the appeal of the August 2011 summary judgment before a three-judge panel of the Sixth Circuit Court of Appeals in Cincinnati, Ohio. A decision in this appeal is expected in early 2013. DTE Energy and DTE Electric believe that the plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of ~~our~~ discussions with the EPA regarding the NOV/FOV and the ~~EPA could bring legal action against Detroit Edison. We~~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,~~supplemental environmental programs, and/or pay fines. WeThe Company cannot predict the financial impact or outcome of this matter, or the timing of its resolution.

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

Water— In response to an EPA regulation, ~~Detroit Edison is~~DTE Electric would be required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of completed studies and expected future studies, ~~Detroit Edison~~DTE Electric may be required to install ~~additional control~~ technologies to reduce the impacts of the water ~~intakes. Initially, it~~intake structures. The initial rule published in 2004 was ~~estimated that Detroit Edison could incur up to approximately $55 million over the four to six years subsequent to 2008~~subsequently remanded and a proposed rule published in ~~additional capital expenditures to comply with these requirements. However, a January 2007 circuit court decision remanded back to~~2011. The proposed rule specified an eight year compliance timeline. In July 2012, the EPA ~~several provisions~~announced that a notice of the federal regulation that may result in a delay in compliance dates. The decision also raised the possibility that Detroit Edison may have to install cooling towers at some facilities at a cost substantially greater than was initially estimated for other mitigative technologies. In 2008, the Supreme Court agreed to review the remanded cost-benefit analysis provision ofits final action on the rule ~~and in April 2009 upheld EPA’s use of this provision in determining best technology available for reducing environmental impacts. Concurrently, the EPA continues to~~

~~develop a revised rule, a draft of which is expected to~~will be ~~published by summer 2010.~~issued June 2013. The EPA has also ~~proposed~~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— ~~Detroit Edison~~Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. The facilities, which produced gas, have been designated as manufactured gas plant (MGP) sites. DTE Electric conducted remedial investigations at contaminated sites, including three former ~~manufactured gas plant (MGP)~~MGP sites. The investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites, including the area surrounding an ash landfill, electrical distribution substations, electric generating power plants, and underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is expected to be incurred over the next several years. At December 31, ~~2009~~2012 and ~~2008,~~2011, the Company had $9$9 million and ~~$12~~$8 million, respectively, accrued for remediation. Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows.

~~Landfill~~~~— Detroit Edison~~

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

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Other

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

In 2010, the EPA finalized a new sulfur dioxide ambient air quality standard that requires states to submit plans for non-attainment areas to be in compliance by 2017. Michigan's proposed non-attainment area includes DTE Electric facilities in southwest Detroit ~~Edison performed an engineering analysis~~and areas of Wayne County. Preliminary modeling runs by the MDEQ suggest that emission reductions may be required by significant sources of sulfur dioxide emissions in ~~2009~~these areas, including DTE Electric power plants. The state implementation plan process is in the preliminary stage and ~~identified~~any required emission reductions for DTE Electric sources to meet the ~~need for embankment side slope repairs and reconstruction.~~standard cannot be estimated currently.

Nuclear Operations

Property Insurance

~~Detroit Edison~~

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

~~Detroit Edison~~

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

~~Detroit Edison~~

DTE Electric has ~~$500~~$500 million in primary coverage and ~~$2.25~~$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.~~$2.75 billion, subject to a $1 million deductible.

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

Under the NEIL policies, ~~Detroit Edison~~DTE Electric could be liable for maximum assessments of up to approximately ~~$28~~$31 million per event if the loss associated with any one event at any nuclear plant in the United States should exceed the accumulated funds available to NEIL.

Public Liability Insurance

As of January 1, ~~2010,~~2013, as required by federal law, ~~Detroit Edison~~DTE Electric maintains ~~$375~~$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.~~$300 million. Further, under the Price-Anderson Amendments Act of 2005, deferred premium charges up to ~~$117.5~~$117.5 million could be levied against each licensed nuclear facility, but not more than ~~$17.5~~$17.5 million per year per facility. Thus, deferred premium charges could be levied against all owners of licensed nuclear facilities in the event of a nuclear incident at any of these facilities.

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Nuclear Fuel Disposal Costs

In accordance with the Federal Nuclear Waste Policy Act of 1982, ~~Detroit Edison~~DTE Electric has a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. ~~Detroit~~

~~Edison~~DTE Electric is obligated to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold. The fee is a component of nuclear fuel expense. ~~Delays have occurred in the DOE’s~~The DOE's Yucca Mountain Nuclear Waste Repository program for the acceptance and disposal of spent nuclear fuel atwas terminated in 2011. DTE Electric currently employs a ~~permanent repository~~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 ~~proposed fiscal year 2011 federal budget recommends termination of funding~~initial offload from the spent fuel pool until 2014. The dry cask storage facility is expected to provide sufficient spent fuel storage capability for ~~completion~~the life of the ~~government’s long-term storage facility. Detroit Edison~~plant as defined by the original operating license.

DTE Electric is a party in the litigation against the DOE for both past and future costs associated with the ~~DOE’s~~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~~In July 2012, DTE Electric executed a settlement agreement with the federal government for costs associated with the DOE's delay in acceptance of spent nuclear fuel ~~storage strategy utilizing~~from Fermi 2 for permanent storage. The settlement provided for a ~~fuel pool. We have begun work on an on-site~~payment of approximately $48 million, received in August 2012, for delay-related costs experienced by DTE Electric through 2010, and a claims process for submittal of delay-related costs from 2011 through 2013. The settlement proceeds reduced the cost of the dry cask storage facility ~~which is expected~~assets. The federal government continues to ~~provide sufficient storage capability~~maintain its legal obligation to accept spent nuclear fuel from Fermi 2 for ~~the life of the plant as defined by the original operating license.~~permanent storage. Issues relating to long-term waste disposal policy and to the disposition of funds contributed by ~~Detroit Edison~~DTE Electric ratepayers to the federal waste fund await future governmental action.

Guarantees

In certain limited circumstances, the Company enters into contractual guarantees. The Company may guarantee another entity’s obligation in the event it fails to perform. The Company may provide guarantees in certain indemnification agreements. Finally, the Company may provide indirect guarantees for the indebtedness of others.

~~Detroit Edison has guaranteed a bank term loan~~

Labor Contracts

We had approximately 4,800 employees as of $11 million related to the sale of its steam heating business to Thermal Ventures II, L.P. In conjunction with a refinancing of the steam heating business in 2009, the Company performed a reconsideration analysis and determined the steam heating business entity to be a variable interest entity as a result of insufficient equity at risk. It was determined that the Company is not the primary beneficiary and historical accounting remains unchanged. At December 31, ~~2009, the Company has reserves for the entire amount~~2012, of ~~the bank loan guarantee.~~

~~Labor Contracts~~

~~There are several bargaining units for the Company’s union employees.~~which approximately 2,700 were represented by unions. The majority of our union employees are under ~~contracts~~a contract that ~~expire~~expires in June ~~2010 and August 2012.~~2013.

Purchase Commitments

As of December 31, ~~2009,~~2012, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply ~~commitments and energy trading contracts.~~commitments. The Company estimates that these commitments will be approximately ~~$1.5~~$0.8 billion from ~~2010~~2013 through ~~2025.~~ 2028 as detailed in the following table:



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

The Company also estimates that ~~2010~~2013 capital expenditures will be approximately ~~$940 million.~~$1.6 billion. The Company has made certain commitments in connection with expected capital expenditures. ~~Certain of these commitments are with variable interest entities where the Company determined it was not the primary beneficiary as it does not have significant exposure to losses.~~

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.

~~The Company provides services to the domestic automotive industry, including GM, Ford Motor Company (Ford) and Chrysler and many~~

Table of their vendors and suppliers. Chrysler filed for bankruptcy protection on April 30, 2009. We have reserved approximately $7 million of pre-petition accounts receivable related to Chrysler as of December 31, 2009. GM filed for bankruptcy protection on June 1, 2009. We have not reserved or written off any pre-petition accounts receivable related to GM as of December 31, 2009. Closing of GM or Chrysler plants or other facilities that operate within Detroit Edison’s service territory will also negatively impact the Company’s operating revenues in future periods. In 2009, GM and Chrysler each represented two percent of its annual electric sales volumes, respectively.Contents

Other Contingencies

~~Other~~

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 108 for a discussion of contingencies related to Regulatory Matters.

NOTE 1715 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

~~Measurement Date~~

In 2008, the Company changed the measurement date of its pension and postretirement benefit plans from November 30 to December 31. As a result, the Company recognized an adjustment of $15 million ($9 million after-tax) to retained earnings, which represents approximately one month of pension and other postretirement benefit costs for the period from December 1, 2007 to December 31, 2008. All amounts and balances reported in the following tables as of December 31, 2009 and December 31, 2008 are based on measurement dates of December 31, 2009 and December 31, 2008, respectively.

Pension Plan Benefits

~~Detroit Edison~~

DTE Electric participates in various plans that provide pension and other postretirement benefits for DTE Energy and its affiliates. ~~Detroit Edison~~The plans are sponsored by DTE Energy Corporate Services, LLC (LLC), a subsidiary of DTE Energy. DTE Electric is allocated net periodic benefit costs for its share of the amounts of the combined plans.

Effective January 1, 2012, the Company discontinued offering future non-represented employees a cash balance retirement plan benefit. In ~~prior years, Detroit Edison served as~~its place, the ~~plan sponsor for a pension plan that changed in 2008~~Company will annually contribute an amount equivalent to ~~be sponsored by DTE Energy Corporate Services, LLC, (LLC) a subsidiary~~four percent of ~~DTE Energy. The change in plan sponsorship did not change~~an employee's eligible pay to the ~~pension cost or contributions allocated to Detroit Edison, or the benefits of plan participants.~~employee's defined contribution retirement savings plan.

The Company’s policy is to fund pension costs by contributing amounts consistent with the Pension Protection Act of 2006 provisions and additional amounts when it deems appropriate. At the discretion of management, and depending upon financial market conditions, we ~~deem appropriate. The Company anticipates~~anticipate making up to a ~~$200~~$275 million contribution to the pension plans in ~~2010.~~2013.

Net pension cost includes the following components:

Pension Plans
(in Millions) 2009 2008 2007
Service cost $ 43 $ 45 $ 51
Interest cost 158 148 138
Expected return on plan assets (165 ) (163 ) (148 )
Amortization of:
Net actuarial loss 38 27 46
Prior service cost 7 5 6
Special termination benefits — — 8

Net pension cost $ 81 $ 62 $ 101

~~Special termination benefits in the above tables represent costs associated with our Performance Excellence Process.~~



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

Pension Plans
(in Millions) 2009 2008
Other changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets

Net actuarial loss $ 177 $ 665
Amortization of net actuarial loss (38 ) (27 )
Prior service cost — 12
Amortization of prior service cost (7 ) (6 )

Total recognized in other comprehensive income and regulatory assets $ 132 $ 644

Pension Plans
(in Millions) 2009 2008

Total recognized in net periodic pension cost and other comprehensive income and regulatory assets $ 213 $ 707
Estimated amounts to be amortized from accumulated other comprehensive income and regulatory assets into net periodic benefit cost during next fiscal year
Net actuarial loss $ 70 $ 37
Prior service cost 5 7



	2012			2011
	(In millions)
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income
Net actuarial loss	$	289		$	437
Amortization of net actuarial loss	(125		)	(99		)
Amortization of prior service cost	(1		)	(4		)
Total recognized in Regulatory assets and Other comprehensive income	$	163		$	334
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	343		$	480
Estimated amounts to be amortized from Regulatory assets and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year
Net actuarial loss	$	143		$	120
Prior service cost	$	1		$	1

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The following table reconciles the obligations, assets and funded status of the plan as well as the amount recognized as prepaid pension cost or pension liability in the Consolidated Statements of Financial Position at December 31. During 2008, the sponsor of a pension plan changed from Detroit Edison to the LLC. As a result, as of December 31, 2009 and 2008, the tables below include assets and obligations for Detroit Edison only. At the beginning of 2008, as Detroit Edison was the pension plan sponsor, the tables below included assets and obligations for Detroit Edison and all affiliates participating in the combined plan.31:

Pension Plans
(in Millions) 2009 2008
Accumulated benefit obligation, end of year
$ 2,490 $ 2,206

Change in projected benefit obligation Projected benefit obligation, beginning of year $ 2,368 $ 2,754
Adjustment due to plan sponsorship change — (385 )
December 2007 benefit payments — (15 )
Service cost 43 45
Interest cost 158 149
Actuarial (gain) loss 264 (53 )
Benefits paid (156 ) (156 )
Measurement date change — 16
Plan amendments — 13

Projected benefit obligation, end of year
$ 2,677 $ 2,368

Change in plan assets

Plan assets at fair value, beginning of year $ 1,387 $ 2,599
Adjustment due to plan sponsorship change — (752 )
December 2007 contributions — 150
December 2007 payments — (15 )
Actual return on plan assets 252 (557 )
Company contributions 204 104
Measurement date change — 14
Benefits paid (156 ) (156 )

Plan assets at fair value, end of year $ 1,687 $ 1,387

Funded status, end of year $ (990 ) $ (981 )

Amount recorded as:
Current liabilities $ (3 ) $ (3 )
Noncurrent liabilities (987 ) (978 )

$ (990 ) $ (981 )

Amounts recognized in regulatory assets (see Note 10)

Net actuarial loss $ 1,241 $ 1,106
Prior service cost 20 27

Regulatory assets $ 1,261 $ 1,133

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

2009 2008 2007
Projected benefit obligation

Discount rate 5.90 % 6.90 % 6.50 %
Rate of compensation increase 4.00 % 4.00 % 4.00 %

Net pension costs

Discount rate 6.90 % 6.50 % 5.70 %
Rate of compensation increase 4.00 % 4.00 % 4.00 %
Expected long-term rate of return on plan assets 8.75 % 8.75 % 8.75 %



	2012			2011
	(In millions)
Accumulated benefit obligation, end of year	$	3,307		$	2,963
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	3,196		$	2,899
Service cost	64			55
Interest cost	155			154
Actuarial loss	342			251
Settlements	2			2
Benefits paid	(174		)	(165		)
Projected benefit obligation, end of year	$	3,585		$	3,196
Change in plan assets
Plan assets at fair value, beginning of year	$	1,957		$	1,936
Actual return on plan assets	220			(18		)
Company contributions	208			204
Benefits paid	(174		)	(165		)
Plan assets at fair value, end of year	$	2,211		$	1,957
Funded status of the plan	$	(1,374	)	$	(1,239	)
Amount recorded as:
Current liabilities	$	(6	)	$	(8	)
Noncurrent liabilities	(1,368		)	(1,231		)
	$	(1,374	)	$	(1,239	)
Amounts recognized in Regulatory assets (see Note 8)
Net actuarial loss	$	1,805		$	1,645
Prior service cost	10			11
	$	1,815		$	1,656

At December 31, ~~2009,~~2012, the benefits related to the Company’s qualified and nonqualified pension plans expected to be paid in each of the next five years and in the aggregate for the five fiscal years thereafter are as follows:

(in Millions)
2010 $ 161
2011 165
2012 169
2013 175
2014 180
2015 - 2019 993

Total $ 1,843



	(In millions)
2013	$	182
2014	187
2015	193
2016	200
2017	208
2018 - 2022	1,145
Total	$	2,115

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



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

The Company employs a formal process in determining the long-term rate of return for various asset classes. Management reviews historic financial market risks and returns and long-term historic relationships between the asset classes of equities, fixed income and other assets, consistent with the widely accepted capital market principle that asset classes with higher volatility generate a greater return over the long-term. Current market factors such as inflation, interest rates, asset class risks and asset class returns are evaluated and considered before long-term capital market assumptions are determined. The

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long-term portfolio return is also established employing a consistent formal process, with due consideration of diversification, active investment management and rebalancing. Peer data is reviewed to check for reasonableness.

The Company employs a total return investment approach whereby a mix of equities, fixed income and other investments are used to maximize the long-term return on plan assets consistent with prudent levels of risk, with consideration given to the liquidity needs of the plan. ~~The intent of this strategy is to minimize plan expenses over the long-term.~~ Risk tolerance is established through consideration of future plan cash flows, plan funded status, and corporate financial considerations. The investment portfolio contains a diversified blend of equity, fixed income and other investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, growth and value investment styles, and large and small market capitalizations. 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, ~~2009~~2012 are listed below:



U.S. Large Cap Equity Securities		2522	%
U.S. Small Cap and Mid Cap Equity Securities	5	6
Non U.S. Equity Securities	20	14
Fixed Income Securities	25	26
Hedge Funds and Similar Investments		20
Private Equity and Other	8	6
~~Short-Term Investments~~		3

		100100	%

~~The fair values of the Company’s plans assets~~

Fair Value Measurements at December 31, ~~2009, by asset category are as follows:~~

~~Fair Value Measurements at~~

2012 and December 31, ~~2009~~

Balance at
(in Millions)(a) Level 1 Level 2 Level 3 December 31, 2009
Asset Category:

Short-term investments (b) $ — $ 42 $ — $ 42
Equity securities
U.S. Large Cap(c) 436 20 — 456
U.S. Small/Mid Cap(d) 101 2 — 103
Non U.S(e) 153 79 — 232
Fixed income securities(f) 31 397 — 428
Other types of investments
Hedge Funds and Similar Investments(g) — — 320 320
Private Equity and Other(h) — — 106 106

Total $ 721 $ 540 $ 426 $ 1,687

2011 (a):



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


(a)		See Note 43 — 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 ~~mid~~ 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~~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 ~~includes~~utilizes a diversified group of ~~funds and~~ strategies that attempt to capture financial market ~~inefficiencies.~~inefficiencies and includes publicly traded debt and equity, publicly traded mutual funds, commingled and limited partnership funds and non-exchange traded securities. Pricing for ~~investments~~Level 1 and Level 2 assets in this category is ~~based on limited observable inputs~~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 ~~there is little, if any, publicly available pricing.~~Level 2 assets. Valuations for some Level 3 assets in this category may be based on ~~relative publicly-traded securities, derivatives, and privately-traded securities.~~limited observable inputs as there may be little, if any, publicly available pricing.

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(h)		This category includes a diversified group of funds and strategies that primarily invests in private equity partnerships. This category also includes investments in timber and private mezzanine debt. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available


		pricing. Valuations for assets in this category may be based on discounted cash flow analyses, ~~relative~~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~~DTE Electric has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, ~~Detroit Edison~~DTE Electric selectively corroborates the fair values of securities by comparison of market-based price sources.

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

Hedge Funds
and Similar Private Equity
(in Millions) Investments and Other Total
Beginning Balance at January 1, 2009 $ 310 $ 105 $ 415
Total realized/unrealized gains (losses) 20 (7 ) 13
Purchases, sales and settlements (10 ) 8 (2 )

Ending Balance at December 31, 2009 $ 320 $ 106 $ 426

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 $ 23 $ (7 ) $ 16



	Year Ended December 31, 2012									Year Ended December 31, 2011
	Hedge Funds and Similar			Private Equity						Hedge Funds and Similar			Private Equity
	Investments			and Other			Total			Investments			and Other			Total
	(In millions)
Beginning Balance	$	205		$	116		$	321		$	206		$	118		324
Total realized/unrealized gains (losses):
Realized gains (losses)	13			(4		)	9			(3		)	4			1
Unrealized gains (losses)	(3		)	8			5			1			(21		)	(20		)
Purchases, sales and settlements:
Purchases	176			23			199			44			16			60
Sales	(153		)	(18		)	(171		)	(43		)	(1		)	(44		)
Ending Balance	$	238		$	125		$	363		$	205		$	116		$	321
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	11		$	4		$	15		$	3		$	(20	)	$	(17	)

There were no transfers between Level 3 and Level 2 and there were no significant transfers between Level 2 and Level 1 in the years ended December 31, 2012 and 2011.

The Company also sponsors defined contribution retirement savings plans. Participation in one of these plans is available to substantially all represented and non-represented employees. The Company matches employee contributions up to certain predefined limits based upon eligible compensation, ~~and~~ the employee’s contribution ~~rate.~~rate and, in some cases, years of credit service. The cost of these plans was ~~$16~~$19 million, $18 million, and $17 million in ~~2009, $16 million in 2008,~~each of the years ended 2012, 2011, and ~~$17 million in 2007.~~2010, respectively.

Other Postretirement Benefits

The Company participates in plans sponsored by LLC that provide certain postretirement health care and life insurance benefits for employees who are eligible for these benefits. The Company’s policy is to fund certain trusts to meet our postretirement benefit obligations. Separate qualified Voluntary Employees Beneficiary Association (VEBA) trusts exist for represented and non-represented employees.

Effective January 1, 2012, in lieu of offering future non-represented employees post-employment health care and life insurance benefits, the Company will allocate $4,000 per year to an account in a tax-exempt trust for each employee. The accumulated balance and earnings in an employee's account will vest when the employee has ten years of service, regardless of age. These funds will be available to the employee to use for health care expenses after the employee leaves the Company.

Effective January 1, 2013, the Company replaced sponsored retiree medical, prescription drug and dental coverage for current and future Medicare eligible non-represented retirees, spouses, surviving spouses, or same sex domestic partners with a Retiree Health Care Allowance (RHCA) account of $3,500 or $3,250 per year depending on their date of hire. Local 17

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employees hired after September 24, 2012 will receive a $4,000per year allocation to an account in a tax-exempt trust for each employee, in lieu of offering post-employment health care and life insurance benefits. Current Local 17 employees, spouses, surviving spouse, or same sex domestic partners, who retired after November 6, 2012 will receive a RHCA of $3,250 per year upon becoming eligible for Medicare.

In January 2013, the Company contributed $120 million to its other postretirement benefit plans. At the discretion of management, ~~subject to MPSC requirements,~~ the Company may make up to ~~a $90~~an additional $120 million contribution to ~~the~~its VEBA trusts in ~~2010.~~2013.

Net postretirement cost includes the following components:

(in Millions) 2009 2008 2007
Service cost $ 45 $ 48 $ 48
Interest cost 102 94 90
Expected return on plan assets (42 ) (58 ) (54 )
Amortization of:
Net loss 53 27 51
Prior service costs 2 2 4
Net transition obligation 2 2 7
Special termination benefits — — 2

Net postretirement cost $ 162 $ 115 $ 148

~~Special termination benefits in the above tables represent costs associated with our Performance Excellence Process.~~

(in Millions) 2009 2008
Other changes in plan assets and APBO recognized in regulatory assets

Net actuarial (gain) loss $ (38 ) $ 237
Amortization of net actuarial loss (52 ) (28 )
Prior service (credit) — (1 )
Amortization of prior service cost (2 ) (2 )
Amortization of transition (asset) (2 ) (2 )

Total recognized in regulatory assets $ (94 ) $ 204

Total recognized in net periodic pension cost and regulatory assets $ 68 $ 319



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

(in Millions)
Estimated amounts to be amortized from regulatory assets into net periodic benefit cost during next fiscal year

Net actuarial loss $ 38 $ 49
Prior service cost 2 2
Net transition obligation 2 2



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

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

(in Millions) 2009 2008
Change in accumulated post retirement benefit obligation during the year

Accumulated postretirement benefit obligation, beginning of year $ 1,553 $ 1,479
December 2007 cash flow — (4 )
Service cost 45 48
Interest cost 102 94
Plan amendments — (1 )
Actuarial (gain)/loss 21 (7 )
Measurement date change — 11
Benefits paid (75 ) (72 )
Medicare Part D 4 5

Accumulated postretirement benefit obligation , end of year $ 1,650 $ 1,553

Change in plan assets during the year

Plan assets at fair value, beginning of year $ 478 $ 658
December 2007 cash flow — 1
Actual return on plan assets 99 (189 )
Measurement date change — 5
Company contributions 90 76
Benefits paid (75 ) (73 )

Plan assets at fair value, end of year $ 592 $ 478

Funded status, as of December 31 $ (1,058 ) $ (1,075 )

Non-current liabilities $ (1,058 ) $ (1,075 )

Amounts recognized in regulatory assets (see Note 10)

Net actuarial loss $ 510 $ 600
Prior service cost (2 ) —
Net transition obligation 7 9

$ 515 $ 609



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

At December 31, 2012, the benefits expected to be paid, including prescription drug benefits, in each of the next five years and in the aggregate for the five fiscal years thereafter are as follows:



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

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

2009 2008 2007
Projected Benefit Obligation

Discount rate 5.90 % 6.90 % 6.50 %

Net Benefit Costs

Discount rate 6.90 % 6.50 % 5.70 %
Expected long-term rate of return on Plan assets 8.75 % 8.75 % 8.75 %
Health care trend rate pre-65 7.00 % 7.00 % 8.00 %
Health care trend rate post-65 7.00 % 6.00 % 7.00 %
Ultimate health care trend rate 5.00 % 5.00 % 5.00 %
Year in which ultimate reached 2016 2011 2011



	2012		2011		2010
Projected benefit obligation
Discount rate	4.15	%	5.00	%	5.50	%
Health care trend rate pre- and post- 65	7.00	%	7.00	%	7.00	%
Ultimate health care trend rate	5.00	%	5.00	%	5.00	%
Year in which ultimate reached	2019		2016		2016
Net benefit costs
Discount rate	5.00	%	5.50	%	5.90	%
Expected long-term rate of return on plan assets	8.25	%	8.75	%	8.75	%
Health care trend rate pre- and post- 65	7.00	%	7.00	%	7.00	%
Ultimate health care trend rate	5.00	%	5.00	%	5.00	%
Year in which ultimate reached	2020		2019		2016

A ~~one-percentage-point~~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 ~~$24~~$21 million and increased the accumulated benefit obligation by ~~$217~~$218 million at December 31, ~~2009.~~2012. A ~~one-percentage-point~~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 ~~$20~~$13 million and would have decreased the accumulated benefit obligation by ~~$185~~$185 million at December 31, ~~2009.~~2012.

~~At December 31, 2009, the benefits expected to be paid, including prescription drug benefits, in each~~51

Table of ~~the next five years and in the aggregate for the five fiscal years thereafter are as follows:~~Contents

(in Millions)
2010 $ 92
2011 97
2012 100
2013 104
2014 108
2015 - 2019 611

Total $ 1,112

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 $17 million in 2009, $11 million in 2008 and $12 million in 2007.

~~At December 31, 2009, the gross amount of federal subsidies expected to be received in each of the next five years and in the aggregate for the five fiscal years thereafter was as follows:~~

(in Millions)
2010 $ 5
2011 6
2012 6
2013 6
2014 7
2015 - 2019 39

Total $ 69

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 ~~the~~its pension plans.

Target allocations for plan assets as of December 31, ~~2009~~2012 are listed below:



U.S. ~~Large Cap~~ Equity Securities		2021	%
~~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	14	10
~~Short-Term Investments~~		0

		100	%

~~The fair values of the Company’s plan assets~~

Fair Value Measurements at December 31, ~~2009, by asset category are as follows:~~

~~Fair Value Measurements at~~
2012 and December 31, ~~2009~~

Balance at
(in Millions)(a) Level 1 Level 2 Level 3 December 31, 2009
Asset Category:

Short-term investments(b) $ — $ 12 $ — $ 12
Equity securities
U.S. Large Cap(c) 102 55 — 157
U.S. Small/Mid Cap(d) 32 34 — 66
Non U.S(e) 50 47 — 97
Fixed income securities(f) 5 160 — 165
Other types of investments
Hedge Funds and Similar Investments(g) — — 63 63
Private Equity and Other(h) — — 32 32

Total $ 189 $ 308 $ 95 $ 592

2011(a):



	December 31, 2012								December 31, 2011
	Level 1		Level 2		Level 3		Net Balance		Level 1		Level 2		Level 3		Net Balance
Asset Category:	(In millions)
Short-term investments (b)	$	1	$	1	$	—	$	2	$	1	$	8	$	—	$	9
Equity securities
U.S. Large Cap (c)	122		2		—		124		116		10		—		126
U.S. Small/Mid Cap (d)	70		—		—		70		46		4		—		50
Non U.S. (e)	151		4		—		155		116		10		—		126
Fixed income securities (f)	25		162		—		187		15		156		—		171
Hedge Funds and Similar Investments (g)	68		15		78		161		53		14		63		130
Private Equity and Other (h)	—		—		57		57		—		—		39		39
Total	$	437	$	184	$	135	$	756	$	347	$	202	$	102	$	651


(a)		See Note 43 — 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 ~~mid~~ 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 ~~includes~~utilizes a diversified group of ~~funds and~~ strategies that attempt to capture financial market ~~inefficiencies.~~inefficiencies and includes publicly traded debt and equity, publicly traded mutual funds, commingled and limited partnership funds and non-exchange traded securities. Pricing for ~~investments~~Level 1 and Level 2 assets in this category is ~~based on limited observable inputs~~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 ~~there is little, if any, publicly available pricing.~~Level 2 assets. Valuations for some Level 3 assets in this category may be based on ~~relative publicly-traded securities, derivatives, and privately-traded securities.~~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, ~~relative~~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~~DTE Electric has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, ~~Detroit Edison~~DTE Electric selectively corroborates the fair values of securities by comparison of market-based price sources.

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

HedgeFunds Similar Private Equityand
(in Millions) Investments Other Total
Beginning Balance at January 1, 2009 $ 52 $ 26 $ 78
Total realized/unrealized gains (losses) 4 3 7
Purchases, sales and settlements 7 3 10

Ending Balance at December 31, 2009 $ 63 $ 32 $ 95

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 $ 2 $ 6



	Year Ended December 31, 2012									Year Ended December 31, 2011
	Hedge Funds and Similar Investments			Private Equity and Other			Total			Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance	$	63		$	39		$	102		$	52		$	36		$	88
Total realized/unrealized gains (losses):
Realized gains (losses)	4			(7		)	(3		)	(1		)	1			—
Unrealized gains (losses)	—			9			9			2			(14		)	(12		)
Purchases, sales and settlements:
Purchases	56			25			81			45			31			76
Sales	(45		)	(9		)	(54		)	(35		)	(15		)	(50		)
Ending Balance	$	78		$	57		$	135		$	63		$	39		$	102
The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	4		$	1		$	5		$	3		$	(11	)	$	(8	)

There were no transfers between Level 3 and Level 2 and there were no significant transfers between Level 2 and Level 1 in the years ended December 31, 2012 and 2011.

Healthcare Legislation

In December 2003, the Medicare Act was signed into law which provides for a non-taxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least “actuarially equivalent” to the benefit established by law. The effects of the subsidy reduced net periodic postretirement benefit costs by $4 million in 2012, $5 million in 2011 and $5 million in 2010.

NOTE 1816 — 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) 2009 2008 2007
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately

Accounts receivable, net $ 16 $ 72 $ (163 )
Inventories 30 (24 ) (47 )
Recoverable pension and postretirement costs (13 ) (852 ) 594
Accrued pension liability — affiliates 9 598 (330 )
Accounts payable (56 ) (82 ) 73
Accrued power supply cost recovery revenue 7 82 41
Accrued payroll 2 3 (50 )
Income taxes payable (109 ) (29 ) 10
General taxes — (12 ) 4
Risk management and trading activities 8 1 (4 )
Accrued postretirement liability — affiliates (17 ) 259 (239 )
Other assets (26 ) 3 (387 )
Other liabilities 110 99 285

$ (39 ) $ 118 $ (213 )



	2012			2011			2010
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately	(In millions)
Accounts receivable, net	$	24		$	(62	)	$	—
Inventories	7			(53		)	(71		)
Recoverable pension and postretirement costs	106			(436		)	(26		)
Accrued pension liability — affiliates	137			271			(27		)
Accounts payable	(64		)	41			47
Income taxes payable/receivable	114			54			(77		)
Accrued postretirement liability — affiliates	(221		)	157			3
Regulatory assets	125			(18		)	(77		)
Other assets	108			(80		)	(54		)
Other liabilities	(78		)	(15		)	29
	$	258		$	(141	)	$	(253	)

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



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

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

(in Millions) 2009 2008 2007
Cash Paid For
Interest (excluding interest capitalized) $ 328 $ 290 $ 295
Income taxes 319 24 280



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

NOTE 1917 — 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. ~~Prior to March 31, 2007, under a service agreement with DTE Energy,~~A shared services company accumulates various ~~DTE Energy affiliates, including Detroit Edison, provided~~ corporate support services ~~inclusive of various financial, auditing, tax, legal, treasury~~expenses and cash management, human resources, information technology, and regulatory services, which were billed to DTE Energy corporate. Subsequent to March 31, 2007, a newly formed shared service company began to accumulate the aforementioned corporate support services type expenses, which previously had been recorded on the various operating units of DTE Energy Company, including Detroit Edison. These administrative and general expenses incurred by the shared services company were then charged tocharges various subsidiaries of DTE Energy, including ~~Detroit Edison.~~DTE Electric. DTE Electric records federal, state and local income taxes payable to or receivable from DTE Energy based on its federal, state and local tax provisions.

The following is a summary of transactions with affiliated companies:

(in Millions) 2009 2008 2007
Revenues

Energy sales $ 1 $ — $ —
Other services 4 6 5
Shared capital assets 28 23 21
Costs

Fuel and power purchases 3 5 3
Other services and interest 3 7 6
Corporate expenses (net) 313 388 331
Other

Dividends declared 305 228 305
Dividends paid 305 305 305
Capital contribution 250 175 175

December 31,
(in Millions) 2009 2008
Assets

Accounts receivable $ 3 $ 5
Notes receivable 82 41
Liabilities & Equity

Accounts payable 74 103
Other liabilities
Accrued pension liability 987 978
Accrued postretirement liability 1,058 1,075



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



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

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

Charitable contributions to the DTE Energy Foundation were approximately $21 million and $13 million for the years ended December 31, 2011 and 2010, respectively. The DTE Energy Foundation is a non-consolidated not-for-profit private foundation, the purpose of which is to contribute and assist charitable organizations and does not serve a direct business or political purpose of DTE Electric.

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NOTE 2018 — SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

First Second Third Fourth
(in Millions) Quarter Quarter Quarter(1) Quarter Year
2009

Operating Revenues $ 1,118 $ 1,108 $ 1,289 $ 1,199 $ 4,714
Operating Income 214 189 318 178 899
Net Income 78 79 149 70 376

2008
Operating Revenues 1,153 1,173 1,440 1,108 4,874
Operating Income 139 151 316 194 800
Net Income 41 51 159 80 331



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


~~(1)~~(a)		~~The 2009 Third Quarter~~ In the fourth quarter of 2012, the Company recorded an adjustment that decreased operating income by $9 million ($5 million after tax) to correct other postretirement benefit expenses reported in prior periods. This adjustment is not considered material to the operating results ~~were adjusted for the effect~~of any of the January 2010 Detroit Edison MPSC rate order that required the refund of a portion of the self implemented rate increase effective on July 26, 2009. The adjustments resulted in a reduction of Operating Revenues of $11 million, Operating Income of $11 million and Net Income of $7 million.relevant periods.

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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


~~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 ~~year~~years ended December 31, ~~2009~~2012 and December 31, 2011 professional services were performed by PricewaterhouseCoopers LLP (PwC). For the year ended December 31, 2008, professional services were performed by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, “Deloitte”). The following table presents fees for professional services rendered by PwC ~~and Deloitte~~ for the audit of ~~Detroit Edison’s~~DTE Electric’s annual financial statements for the years ended December 31, ~~2009~~2012 and December 31, ~~2008,~~2011, respectively, and fees billed for other services rendered by PwC ~~and Deloitte~~ during those periods.

2009 2008
Audit fees (1) $ 1,231,865 $ 1,466,413
Audit-related fees (2) 37,400 45,500

Total $ 1,269,265 $ 1,511,913



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


~~(1)~~	(a)	Represents the aggregate fees for the audits of ~~Detroit Edison’s~~DTE Electric’s annual financial statements included in the Annual Reports on Form 10-K and for the reviews of the financial statements included in ~~Detroit Edison’s~~the Quarterly Reports on Form 10-Q.


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


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

The above listed fees were pre-approved by the DTE Energy ~~audit committee.~~Audit Committee. Prior to engagement, the DTE Energy ~~audit committee~~Audit Committee pre-approves these services by category of service. The DTE Energy ~~audit committee~~Audit Committee may delegate to the chair of the ~~audit committee,~~Audit Committee, or to one or more other designated members of the ~~audit committee,~~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~~Audit Committee at the next scheduled meeting.

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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.~~

(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.

~~(i)~~

~~Exhibits filed herewith.~~


~~4-267~~		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 (2009 Series CT).

~~4-268~~		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 (2009 Series CT Variable Rate Senior Notes due 2024).

~~12-36~~12-45		Computation of Ratio of Earnings to Fixed Charges.

~~23-22~~23-27		Consent of PricewaterhouseCoopers LLP.

~~23-23~~		~~Consent of Deloitte & Touche LLP.~~

~~31-53~~31-79		Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report.

~~31-54~~31-80		Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report.

(ii)Exhibits incorporated herein by reference.


	~~(ii)~~		~~Exhibits incorporated herein by reference.~~

		Certain exhibits listed below refer to "The Detroit Edison Company" and were effective prior to the change to DTE Electric Company effective January 1, 2013.
3(a)		~~Restated~~ Articles of Incorporation of ~~The Detroit Edison~~DTE Electric Company, as ~~filed December 10, 1991.~~amended effective January 1, 2013. (Exhibit ~~3-13~~3-1 to Form ~~10-Q for the quarter ended June 30, 1999)~~8-K filed January 2, 2013).

3(b)		Bylaws of The Detroit Edison Company, as amended through September 22, 1999. (Exhibit 3-14 to Form 10-Q for the quarter ended September 30, 1999).

4(a)		Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-1 to Registration Statement on Form A-2 (File No. 2-1630)) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below:

		Supplemental Indenture, dated as of December 1, 1940, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-14 to Registration Statement on Form A-2 (File No. 2-4609)). (amendment)

		Supplemental Indenture, dated as of September 1, 1947, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-20 to Registration Statement on Form S-1 (File No. 2-7136)). (amendment)

		Supplemental Indenture, dated as of March 1, 1950, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust


		Company, N.A., as successor trustee (Exhibit B-22 to Registration Statement on Form S-1 (File No. 2-8290)). (amendment)

		Supplemental Indenture, dated as of November 15, 1951, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-23 to Registration Statement on Form S-1 (File No. 2-9226)). (amendment)

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		Supplemental Indenture, dated as of August 15, 1957, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 3-B-30 to Form 8-K dated September 11, 1957). (amendment)

		Supplemental Indenture, dated as of December 1, 1966, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 2-B-32 to Registration Statement on Form S-9 (File No. 2-25664)). (amendment)

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

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

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

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

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

		Supplemental Indenture, dated as of August 1, 1999, 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 4-204 to Form 10-Q for the quarter ended September 30, 1999). (1999 Series AP, BP and CP)

		~~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 March 15, 2001, 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 4-222 to Form 10-Q for the quarter ended March 31, 2001). (2001 Series AP)


		Supplemental Indenture, dated as of May 1, 2001, 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 4-226 to Form 10-Q for the quarter ended June 30, 2001). (2001 Series BP)

		Supplemental Indenture, dated as of August 15, 2001, 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 4-227 to Form 10-Q for the quarter ended September 30, 2001). (2001 Series CP)

		Supplemental Indenture, dated as of September 15, 2001, 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 4-228 to Form 10-Q for the quarter ended September 30, 2001). (2001 Series D and E)

		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)

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		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.~~trustee. (Exhibit 4-261 to Form 10-K for the year ended December 31, 2008). (2008 Series LT)

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

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

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

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

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

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

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

		Supplemental Indenture, dated as of August 15, 2011, to Mortgage and Deed of Trust, dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-277 to Form 10-Q for the quarter ended September 30, 2011). (2011 Series D, 2011 Series E, 2011 Series F)

		Supplemental Indenture, dated as of September 1, 2011, to Mortgage and Deed to Trust, dated as of October 1, 1924 between The Detroit Edison Company and the Bank of New York Mellon Trust Company N.A. as successor trustee (Exhibit 4-278 to Detroit Edison Form 10-Q for the quarter ended September 30, 2011. (2011 Series H)

		Supplemental Indenture, dated as of June 20, 2012, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-279 to Form 10-Q for the quarter ended June 30, 2012). (2012 Series A and B)

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		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)).

		~~Ninth Supplemental Indenture,~~ and indentures supplemental thereto, dated as of ~~October 10, 2001,~~the dates indicated below and filed as exhibits 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 4-229 to Form 10-Q for the quarter ended September 30, 2001). (6.125% Senior Notes due 2010)filings set forth below:

		Tenth Supplemental Indenture, dated as of October 23, 2002, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-231 to Form 10-Q for the quarter ended September 30, 2002). ~~(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%(6.35% Senior Notes due 2032)

		Twelfth Supplemental Indenture, dated as of August 1, 2003, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-236 to Form 10-Q for the quarter ended September 30, 2003). (5 1/2% Senior Notes due 2030)


		Thirteenth Supplemental Indenture, dated as of April 1, 2004, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-237 to Form 10-Q for the quarter ended March 31, 2004). (4.875% Senior Notes Due 2029 and 4.65% Senior Notes due 2028)

		Fourteenth Supplemental Indenture, dated as of July 15, 2004, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-239 to Form 10-Q for the quarter ended June 30, 2004). (2004 Series D 5.40% Senior Notes due 2014)

		Sixteenth Supplemental Indenture, dated as of April 1, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Registration Statement on Form S-4 (File No. 333-123926)). (2005 Series AR 4.80% Senior Notes due 2015 and 2005 Series BR 5.45% Senior Notes due 2035)

		Eighteenth Supplemental Indenture, dated as of September 15, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Form 8-K dated September 29, 2005). (2005 Series C 5.19% Senior Notes due October 1, 2023)

		Nineteenth Supplemental Indenture, dated as of September 30, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-247 to Form 10-Q for the quarter ended September 30, 2005). (2005 Series E 5.70% Senior Notes due 2037)

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		Twentieth Supplemental Indenture, dated as of May 15, 2006, to the Collateral Trust Indenture dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-249 to Form 10-Q for the quarter ended June 30, 2006). (2006 Series A Senior Notes due 2036)

		Twenty-Second Supplemental Indenture, dated as of December 1, 2007, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Form 8-K dated December 18, 2007). (2007 Series A Senior Notes due 2038)

		Twenty-Fourth Supplemental Indenture, dated as of May 1, 2008, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-254 to Form 10-Q for the quarter ended June 30, 2008). (2008 Series ET Variable Rate Senior Notes due 2029)

		Amendment dated June 1, 2009 to the Twenty-fourth Supplemental Indenture, dated as of May 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (2008 Series ET Variable Rate Senior Notes due 2029) (Exhibit 4-265 to Form 10-Q for the quarter ended June 30, 2009)

		Twenty-Fifth Supplemental Indenture, dated as of June 1, 2008, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-256 to Form 10-Q for the quarter ended June 30, 2008). (2008 Series G 5.60% Senior Notes due 2018)

		Twenty-Sixth Supplemental Indenture, dated as of July 1, 2008, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-258 to Form 10-Q for the quarter ended June 30, 2008). (2008 Series KT Variable Rate Senior Notes due 2020)

		Amendment dated June 1, 2009 to the ~~Twenty-sixth~~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 ~~(2008 Series KT Variable Rate Senior Notes due 2020) (Exhibit~~Exhibit 4-266 to Form 10-Q for the quarter ended June 30, 2009)

Table of Contents



		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 ~~Trust~~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~~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~~Edison's Form 10-Q for the quarter ended March 31, 2009). (2009 Series BT 6.00% Senior Notes due 2036)

~~4(c)~~		Thirty-First Supplemental Indenture, dated as of August 1, 2010 to the Collateral Trust ~~Agreement~~Indenture, dated as of June 1, 1993 by and between The Detroit Edison Company and The Bank of New York Mellon Trust I.Company, N.A., as successor trustee. (Exhibit ~~4.9~~4-270 to ~~Registration Statement on~~ Form ~~S-3 (File No. 333-100000))~~10-Q for the quarter ended September 30, 2010). (2010 Series B 3.45% Senior Notes due 2020)

~~4(d)~~		Thirty-Second Supplemental Indenture, dated as of September 1, 2010, to the Collateral Trust ~~Agreement~~Indenture, dated as of June 1, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust ~~II.~~Company, N.A., as successor trustee. (Exhibit ~~4.10~~4-272 to ~~Registration Statement on~~ Form ~~S-3 (File No. 333-100000)~~10-Q for the quarter ended September 30, 2010.). (2010 Series A 4.89% Senior Notes due 2020)

10(a)		Securitization Property Sales Agreement dated as of March 9, 2001, between The Detroit Edison Securitization Funding LLC and The Detroit Edison Company. (Exhibit 10-42 to Form 10-Q for the quarter ended March 31, 2001).

10(b)		Certain arrangements pertaining to the employment of ~~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)~~10(c)		Certain arrangements pertaining to the employment of David E. Meador with The Detroit Edison Company, dated January 14, 1997. (Exhibit 10-5 to Form 10-K for the year ended December 31, 1996).

~~10(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)~~10(d)		The Detroit Edison Company Supplemental Long-Term Disability Plan, dated January 27, 1997. (Exhibit 10-4 to Form 10-K for the year ended December 31, 1996).

~~10(g)~~10(e)		Form of ~~The Detroit Edison Company’s~~Amended and Restated Five-Year Credit Agreement, dated as of August 20, 2010 and amended and restated as of October ~~17, 2005,~~21, 2011, by and among The Detroit Edison Company, the lenders party thereto, Barclays Bank PLC, as Administrative Agent, and Citibank, N.A. ~~and~~, 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 ~~17, 2005)~~21, 2011).

~~10(h)~~		Form of Detroit Edison Two-Year Credit Agreement, dated as of April 29, 2009, by and among Detroit Edison, the lenders party thereto, Barclays, as Administrative Agent, and Citibank, JPMorgan and RBS, as Co-Syndication Agents. (Exhibit 10.1 to Form 8-K filed May 5, 2009).

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).

~~(iii) Exhibits furnished herewith.~~

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iii.Exhibits furnished herewith.


~~32-53~~
32-79		Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report.

~~32-54~~32-80		Chief Financial Officer Section 906 Form 10-K Certification of Periodic Report.

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema

101.CAL		XBRL Taxonomy Extension Calculation Linkbase

101.DEF		XBRL Taxonomy Extension Definition Database

101.LAB		XBRL Taxonomy Extension Label Linkbase

101.PRE		XBRL Taxonomy Extension Presentation Linkbase

~~The Detroit Edison~~63

Table of Contents

DTE Electric Company

Schedule II — Valuation and Qualifying Accounts

Year Ended December 31
(in Millions) 2009 2008 2007
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statements of Financial Position)

Balance at Beginning of Period $ 121 $ 93 $ 72
Additions:
Charged to costs and expenses 62 81 63
Charged to other accounts (1) 7 5 4
Deductions (2) (72 ) (58 ) (46 )

Balance At End of Period $ 118 $ 121 $ 93



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


~~(1)~~	(a)	Collection of accounts previously written off.


~~(2)~~(b)		~~Non-collectible~~Uncollectible accounts written off.

Table of Contents

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~~ DTE ELECTRIC COMPANY (Registrant)
Date:	February ~~23, 2010~~20, 2013	By		/s/ ~~ANTHONY F. EARLEY, JR.~~GERARD M. ANDERSON
			~~Anthony F. Earley, Jr.~~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/ ~~ANTHONY F. EARLEY, JR.~~GERARD M. ANDERSON	By	/s/ ~~PETER B. OLEKSIAK~~DAVID E. MEADOR
	Gerard M. Anderson			David E. Meador
	~~Anthony F. Earley, Jr.~~ Chairman of the Board and		Director, Executive Vice President and Chief
	Chief Executive Officer		~~Peter B. Oleksiak~~ ~~Vice President, Controller and Investor Relations, and~~ ~~Chief Accounting~~Financial Officer
	(Principal Executive Officer)		(Principal Financial Officer)

By	/s/ ~~SANDRA KAY ENNIS~~DONNA M. ENGLAND	By	/s/ ~~DAVID E. MEADOR~~LISA A. MUSCHONG
	Donna M. England		Lisa A. Muschong
	Chief Accounting Officer		Director
	(Principal Accounting Officer)

	~~Sandra Kay Ennis~~ ~~Director and Corporate Secretary~~		~~David E. Meador~~ ~~Director, Executive Vice President and Chief Financial Officer~~

By	/s/ BRUCE D. PETERSON
	Bruce D. Peterson
	~~Bruce D. Peterson~~ Director

Date: February ~~23, 2010~~20, 2013

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

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



Michigan		38-0478650
~~Michigan~~ (State or other jurisdiction of incorporation or organization)		~~38-0478650~~ (I.R.S. Employer Identification No.)


One Energy Plaza, Detroit, Michigan		48226-1279
(Address of principal executive offices)		~~48226-1279~~ (Zip Code)



ASC		Accounting Standards Codification

ASU		Accounting Standards Update

~~CTA~~CIM		~~Costs~~A Choice Incentive Mechanism authorized by the MPSC that allows DTE Electric to ~~achieve, consisting~~recover or refund non-fuel revenues lost or gained as a result of ~~project management, consultant support and employee severance, related to the Performance Excellence Process~~fluctuations in electric Customer Choice sales.

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

~~Detroit Edison~~DTE Electric		~~The Detroit Edison~~DTE Electric Company (a direct wholly owned subsidiary of DTE ~~Energy Company)~~Energy) and subsidiary ~~companies~~companies. Formerly known as The Detroit Edison Company.

DTE Energy		DTE Energy Company, ~~the parent of Detroit Edison and~~ directly or indirectly the parent ~~company~~ of DTE Electric, DTE Gas Company and numerous ~~utility and~~ non-utility subsidiaries

EPA		United States Environmental Protection Agency

FASB		Financial Accounting Standards Board

FERC		Federal Energy Regulatory Commission

~~FSP~~FTRs		~~FASB Staff Position~~Financial transmission rights are financial instruments that entitle the holder to receive payments related to costs incurred for congestion on the transmission grid.

~~FTRs~~MCIT		~~Financial transmission rights~~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~~Power Supply Cost Recovery mechanism authorized by the MPSC that allows ~~Detroit Edison~~DTE Electric to recover through rates its fuel, fuel-related and purchased power costs.

RDM		A Revenue Decoupling Mechanism authorized by the MPSC that is designed to minimize the impact on revenues of changes in average customer usage of electricity

Securitization		~~Detroit Edison~~DTE Electric financed specific stranded costs at lower interest rates through the sale of rate reduction bonds by a wholly-owned special purpose entity, The Detroit Edison Securitization Funding LLC.

~~SFAS~~VIE		~~Statement of Financial Accounting Standards~~Variable Interest Entity



Units of Measurement
~~Units of Measurement~~

~~GWh~~		~~Gigawatthour of electricity~~

kWh		Kilowatthour of electricity

MW		Megawatt of electricity

MWh		Megawatthour of electricity



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

				FOR THE FISCAL YEAR ENDED DECEMBER 31, 2012
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



		Page
Definitions		1

Forward-Looking Statements		2
		3
Part I
Items 1. ~~1A., 1B. &2.~~& 2. Business ~~Risk Factors, Unresolved Staff Comments~~ and Properties		4
Item 1A. Risk Factors	7
Item 1B. Unresolved Staff Comments	10
Item 3. Legal Proceedings		12
		11
Item 4. ~~Submission of Matters to a Vote of Security Holders~~Mine Safety Disclosures		13
		11
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		13
		11
Item 6. Selected Financial Data		13
		11
Item 7. Management’s Narrative Analysis of Results of Operations		14
		12
Item 7A. Quantitative and Qualitative Disclosures About Market Risk		16
		14
Item 8. Financial Statements and Supplementary Data		17
		15
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		65
		56
Item 9A. Controls and Procedures		65
		56
Item 9B. Other Information		65
		56
Part III
Item 10. Directors, Executive Officers and Corporate Governance		65
		56
Item 11. Executive Compensation		65
		56
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		65
		56
Item 13. Certain Relationships and Related Transactions, and Director Independence		65
		56
Item 14. Principal Accountant Fees and Services		65
		56
Part IV
Item 15. Exhibits and Financial Statement Schedules	57
Signatures	66 65
EX-12.45
EX-23.27
EX-31.79
EX-31.80
EX-32.79
EX-32.80
101.INS XBRL Instance Document
~~Signatures~~ 101.SCH XBRL Taxonomy Extension Schema
74101.CAL XBRL Taxonomy Extension Calculation Linkbase
~~EX-4.267~~101.DEF XBRL Taxonomy Extension Definition Database
~~EX-4.268~~101.LAB XBRL Taxonomy Extension Label Linkbase
~~EX-12.36~~101.PRE XBRL Taxonomy Extension Presentation Linkbase
~~EX-23.22~~
~~EX-23.23~~
~~EX-31.53~~
~~EX-31.54~~
~~EX-32.53~~
~~EX-32.54~~

•		~~the length and severity of ongoing economic decline resulting in lower demand, customer conservation and increased thefts of electricity;~~

•		~~changes in the economic and financial viability of our customers, suppliers, and trading counterparties, and the continued ability of such parties to perform their obligations to the Company;~~

•		~~economic climate and population growth or decline in the geographic areas where we do business;~~

•		~~high levels of uncollectible accounts receivable;~~

•		~~access to capital markets and capital market conditions 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;~~

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

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

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

•		environmental issues, laws, regulations, and the increasing costs of remediation and compliance, including actual and potential new federal and state requirements that include or could include carbon and more stringent mercury emission controls, a renewable portfolio standard, energy efficiency mandates, carbon tax or cap and trade structure and ash landfill regulations;

•		~~nuclear regulations and operations associated with nuclear facilities;~~

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

•		~~employee relations and the impact of collective bargaining agreements;~~

•		~~unplanned outages;~~

•		~~changes in the cost and availability of coal and other raw materials and purchased power;~~

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

•		~~the effects of competition;~~

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

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

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

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

•		~~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; and~~

•		~~binding arbitration, litigation and related appeals.~~

	��
Revenue by Service
(in Millions)		2009		2008		2007
Residential		$	1,820	$	1,726	$	1,739
Commercial			1,702		1,753		1,723
Industrial			730		894		854
Other			299		289		384

Subtotal			4,551		4,662		4,700
Interconnection sales (1)			163		212		200

Total Revenue		$	4,714	$	4,874	$	4,900


~~(1)~~	(a)	Represents power that is not distributed by ~~Detroit Edison.~~DTE Electric.


	Location by	Summer Net
	Michigan	Rated Capability (1)
Plant Name	County	(MW)		(%)		Year in Service
Fossil-fueled Steam-Electric
Belle River (2)	St. Clair		1,034		9.3	1984 and 1985
Conners Creek	Wayne		230		2.1	1951
Greenwood	St. Clair		785		7.1	1979
Harbor Beach	Huron		103		0.9	1968
Marysville	St. Clair		84		0.8	1943 and 1947
Monroe (3)	Monroe		3,090		27.9	1971, 1973 and 1974
River Rouge	Wayne		523		4.7	1957 and 1958
St. Clair (4)	St. Clair		1,365		12.3	1953, 1954, 1959, 1961 and 1969
Trenton Channel	Wayne		730		6.6	1949 and 1968

			7,944		71.7
Oil or Gas-fueled Peaking Units	Various		1,101		10.0	1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric Fermi 2 (5)	Monroe		1,102		10.0	1988
Hydroelectric Pumped Storage Ludington(6)	Mason		917		8.3	1973

			11,064		100.0



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


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


~~(4)~~		~~Excludes one oil-fueled unit (250 MW) in cold standby status.~~

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


	Circuit Miles
Operating Voltage-Kilovolts (kV)	Overhead		Underground
4.8 kV to 13.2 kV		28,243		13,884
24 kV		177		681
40 kV		2,317		363
120 kV		54		13

		30,791		14,941



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


(in Thousands of MWh)	2009		2008		2007

Electric Sales
Residential		14,625		15,492		16,147
Commercial		18,200		18,920		19,332
Industrial		9,922		13,086		13,338
Other		3,229		3,218		3,300

		45,976		50,716		52,117
Interconnection sales (1)		5,156		3,583		3,587

Total Electric Sales		51,132		54,299		55,704


Electric Deliveries
Retail and Wholesale		45,976		50,716		52,117
Electric Customer Choice, including self generators (2)		1,477		1,457		2,239

Total Electric Sales and Deliveries		47,453		52,173		54,356


~~(2)~~	(b)	The Belle River capability represents ~~Detroit Edison’s~~DTE Electric's entitlement to ~~81.39%~~81% of the capacity and energy of the plant. See Note 76 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.


~~(3)~~	(c)	The Monroe ~~power~~generating plant provided ~~38%~~37% of ~~Detroit Edison’s~~DTE Electric's total ~~2009~~2012 power generation.


~~(6)~~	(e)	Represents ~~Detroit Edison’s~~DTE Electric's 49% interest in Ludington with a total capability of 1,872 MW. See Note 76 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.


(in Millions)
Air	$	2,200
Water		55
MGP sites		5
Other sites		21

Estimated total future expenditures through 2019	$	2,281

Estimated 2010 expenditures	$	82

Estimated 2011 expenditures	$	253



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


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


Increase (Decrease) in Income Statement Components Compared to Prior Year (in Millions)	2009			2008

Operating revenues	$	(160	)	$	(26	)
Fuel and purchased power		(287	)		92

Gross margin		127			(118	)
Operation and maintenance		(45	)		(100	)
Depreciation and amortization		101			(21	)
Taxes other than income		(27	)		(45	)
Asset (gains) losses and reserves, net		(1	)		(9	)

Operating income		99			57
Other (income) and deductions		12			6
Income tax provision		42			37

Net Income	$	45		$	14


Increase (Decrease) in Gross Margin Components Compared to Prior Year (in Millions)	2009			2008
December 2008 rate order	$	80		$	—
Securitization bond and tax surcharge rate increase		62			—
July 2009 rate self-implementation		93			—
Energy Optimization and Renewable Energy surcharge		54			—
April 2008 expiration of show cause rate decrease		25			46
Weather		(66	)		(37	)
Reduction in customer demand and other		(121	)		(127	)

Increase (decrease) in gross margin	$	127		$	(118	)


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

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

Power Generated and Purchased
(in Thousands of MWh)	2009					2008					2007
Power Plant Generation
Fossil		40,595		74	%		41,254		71	%		42,359		72	%
Nuclear		7,406		14			9,613		17			8,314		14

		48,001		88			50,867		88			50,673		86
Purchased Power		6,495		12			6,877		12			8,422		14

System Output		54,496		100	%		57,744		100	%		59,095		100	%
Less Line Loss and Internal Use		(3,364	)				(3,445	)				(3,391	)

Net System Output		51,132					54,299					55,704

Average Unit Cost ($/MWh)
Generation (1)	$	18.20				$	17.93				$	15.83

Purchased Power	$	37.74				$	69.50				$	62.40

Overall Average Unit Cost	$	20.53				$	24.07				$	22.47


~~(1)~~		~~Represents fuel costs associated with power plants.~~


~~Item 7A.~~		~~Quantitative and Qualitative Disclosures about~~Item 7A. Quantitative and Qualitative Disclosures About Market Risk


		Page
Controls and Procedures		18 16

Consolidated Financial Statements

~~Reports~~Report of Independent Registered Public Accounting ~~Firms~~Firm		19 17

Consolidated Statements of Operations		21 18

Consolidated Statements of Comprehensive Income	19

Consolidated Statements of Financial Position		22 20

Consolidated Statements of Cash Flows		24 22

Consolidated Statements of Changes in Shareholder’s Equity ~~and Comprehensive Income~~		25 23

Notes to Consolidated Financial Statements		26 24

Financial Statement Schedule

Schedule II — Valuation and Qualifying Accounts		73 64


	December 31
(in Millions, Except Shares)	2009			2008
Liabilities and Shareholder’s Equity
Current Liabilities
Accounts payable
Affiliates	$	74		$	103
Other		251			346
Accrued interest		83			80
Accrued vacations		48			58
Short-term borrowings		—			75
Current portion long-term debt, including capital leases		660			153
Other		213			263

		1,329			1,078


Long-Term Debt (net of current portion)
Mortgage bonds, notes and other		3,579			4,091
Securitization bonds		793			932
Capital lease obligations		25			33

		4,397			5,056


Other Liabilities
Deferred income taxes		1,871			1,894
Regulatory liabilities		711			593
Asset retirement obligations		1,285			1,205
Unamortized investment tax credit		75			85
Nuclear decommissioning		136			114
Accrued pension liability—affiliates		987			978
Accrued postretirement liability—affiliates		1,058			1,075
Other		239			208

		6,362			6,152


Commitments and Contingencies (Notes 10 and 16)

Shareholder’s Equity
Common stock, $10 par value, 400,000,000 shares authorized, and 138,632,324 shares issued and outstanding		3,196			2,946
Retained earnings		693			622
Accumulated other comprehensive income (loss)		(16	)		(12	)

		3,873			3,556


Total Liabilities and Shareholder’s Equity	$	15,961		$	15,842


										Accumulated
					Additional					Other
	Common Stock				Paid in		Retained			Comprehensive
(Dollars in Millions, Shares in Thousands)	Shares		Amount		Capital		Earnings			Income (Loss)			Total
Balance, December 31, 2006		138,632	$	1,386	$	1,210	$	516		$	3		$	3,115

Net income		—		—		—		317			—			317
Dividends declared on common stock		—		—		—		(305	)		—			(305	)
Net change in unrealized gains on investments, net of tax		—		—		—		—			1			1
Capital contribution by parent company		—		—		175		—			—			175

Balance, December 31, 2007		138,632		1,386		1,385		528			4			3,303

Net income		—		—		—		331			—			331
Implementation of ASC 715 (SFAS No. 158) measurement date provision, net of tax		—		—		—		(9	)		—			(9	)
Dividends declared on common stock		—		—		—		(228	)		—			(228	)
Net change in unrealized gains on investments, net of tax		—		—		—		—			(2	)		(2	)
Benefit obligations, net of tax		—		—		—		—			(14	)		(14	)
Capital contribution by parent company		—		—		175		—			—			175

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 losses 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



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



	December 31,		December 31,
	2012		2011
	(In millions)
ASSETS
Restricted cash	$	102	$	107
Accounts receivable	34		34
Securitized regulatory assets	413		577
Other assets	7		10
	$	556	$	728

LIABILITIES
Accounts payable and accrued current liabilities	$	11	$	14
Other current liabilities	50		55
Current portion long-term debt, including capital leases	177		164
Securitization bonds	302		479
Other long term liabilities	7		7
	$	547	$	719


							Accumulated
							Other
	Benefit						Comprehensive
(in Millions)	Obligations			Other			Loss
Beginning balances	$	(14	)	$	2		$	(12	)
Current period change		(2	)		(2	)		(4	)

Ending balance	$	(16	)	$	—		$	(16	)



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


								Net Balance at
(in Millions)	Level 1		Level 2			Level 3		December 31, 2009
Assets:
Cash equivalents	$	15	$	—		$	—	$	15
Nuclear decommissioning trusts and other investments		589		325			—		914
Derivative assets		—		—			2		2

Total	$	604	$	325		$	2	$	931

Liabilities:
Derivative liabilities		—		(8	)		—		(8	)

Total	$	—	$	(8	)	$	—	$	(8	)


Net Assets at December 31, 2009	$	604	$	317		$	2	$	923

Large accelerated filer o

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