In 1995, DTE Energy incorporated in the State of Michigan. Our utility operations consist primarily of DTE Electric and DTE Gas. We also have three other segments that are engaged in a variety of energy-related businesses.

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

DTE Gas is a Michigan corporation organized in 1898 and is a public utility subject to regulation by the ~~MPSC.~~MPSC and the FERC. DTE Gas is engaged in the purchase, storage, transportation, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan and the sale of storage and transportation capacity.

Our other businesses are involved in 1) natural gas pipelines, gathering and storage; 2) power and industrial ~~projects ;~~projects; and 3) energy marketing and trading operations.

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, and all amendments to such reports are available free of charge through the Investors - Reports and Filings page of our website: www.dteenergy.com, as soon as reasonably practicable after they are filed with or furnished to the Securities and Exchange Commission (SEC). Our previously filed reports and statements are also available at the SEC’s website: www.sec.gov.

The Company’s Code of Ethics and Standards of Behavior, Board of Directors’ Mission and Guidelines, Board Committee Charters, and Categorical Standards of Director Independence are also posted on its website. The information on the Company’s website is not part of this or any other report that the Company files with, or furnishes to, the SEC.

Additionally, the public may read and copy any materials the Company files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov.

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

Based on the following structure, we set strategic goals, allocate resources, and evaluate performance. See Note 2322 of the Notes to Consolidated Financial Statements in Item 8 of this Report for financial information by segment for the last three years.

Our Electric segment consists principally of DTE Electric, an electric utility engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan. ~~Our generating plants are~~DTE Electric is regulated by numerous federal and state governmental agencies, including, but not limited to, the MPSC, the FERC, the NRC, the EPA and the MDEQ. Electricity is generated from our fossil-fuel plants, a hydroelectric pumped storage plant, a nuclear plant and our wind and other renewable assets, and is purchased from electricity generators, suppliers and wholesalers. The electricity we produce and purchase is sold to three major classes of customers: residential, commercial and industrial, throughout southeastern Michigan.

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

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Fuel Supply and Purchased Power

Our power is generated from a variety of fuels and is supplemented with purchased power. We expect to have an adequate supply of fuel and purchased power to meet our obligation to serve customers. Our generating capability is heavily dependent upon the availability of coal. Coal is purchased from various sources in different geographic areas under agreements that vary in both pricing and terms. We expect to obtain the majority of our coal requirements through long-term contracts, with the balance to be obtained through short-term agreements and spot purchases. We have long-term and short-term contracts for the purchase of approximately ~~22.1~~29.4 million tons of low-sulfur western coal to be delivered from ~~2013~~2014 through ~~2015~~2016 and approximately ~~3.5~~1.6 million tons of Appalachian coal to be delivered ~~from 2013 through~~in 2014. All of these contracts have pricing schedules. We have approximately ~~81%~~92% of our ~~2013~~2014 expected coal requirements under contract. Given the geographic diversity of supply, we believe we can meet our expected generation requirements. We lease a fleet of rail cars and have our expected western coal rail requirements under contract through ~~2015.~~2018. All of our expected eastern coal rail requirements are under contract through ~~2013.~~2016. Our expected vessel transportation requirements for delivery of purchased coal to our generating facilities are under contract through 2014.

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

Properties

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

Generating plants owned and in service as of December 31, ~~2012~~2013 are ~~as follows:~~shown in the following table. The Company's renewable energy generation, principally wind turbines, is described below.


	Location by Michigan	Summer Net Rated Capability (a)			Location by Michigan	Summer Net Rated Capability (a)
Plant Name	County	(MW)	(%)	Year in Service	County	(MW)	(%)	Year in Service
Fossil-fueled Steam-Electric
Belle River (b)	St. Clair	1,036	9.8	1984 and 1985	St. Clair	1,036	9.9	1984 and 1985
Greenwood	St. Clair	793	7.5	1979	St. Clair	798	7.7	1979
Harbor Beach	Huron	95	0.9	1968
Monroe (c)	Monroe	3,047	28.9	1971, 1973 and 1974	Monroe	3,022	29.0	1971, 1973 and 1974
River Rouge	Wayne	524	5.0	1957 and 1958	Wayne	537	5.2	1957 and 1958
St. Clair	St. Clair	1,379	13.0	1953, 1954, 1959, 1961 and 1969	St. Clair	1,386	13.3	1953, 1954, 1959, 1961 and 1969
Trenton Channel	Wayne	675	6.4	1949 and 1968	Wayne	631	6.0	1949 and 1968
		7,549	71.5			7,410	71.1
Oil or Gas-fueled Peaking Units	Various	1,018	9.6	1966-1971, 1981 and 1999	Various	989	9.5	1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric Fermi 2 (d)	Monroe	1,086	10.3	1988	Monroe	1,102	10.6	1988
Hydroelectric Pumped Storage Ludington (e)	Mason	917	8.6	1973	Mason	917	8.8	1973
		10,570	100.0			10,418	100.0

In 2008, a renewable portfolio standard was established for Michigan electric providers targeting 10% of electricity sold to retail customers from renewable energy by 2015. DTE Electric ~~has~~had approximately ~~720~~900 MW of owned or contracted renewable energy generation, principally wind turbines located in Gratiot, Tuscola, Huron and Sanilac counties in Michigan, at December 31, ~~2012 representing~~2013, which is projected to represent approximately 8%9.6% of electricity that will be sold to retail ~~customers.~~customers in 2015. Approximately ~~510~~690 MW iswas in commercial operation at December 31, ~~2012~~2013. DTE Electric expects to meet the 10% renewable portfolio standard with the commercial operation of an additional 210 MW ~~expected~~ in ~~commercial operation~~2014 and 50 MW in ~~2013 or early 2014.~~2015.

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DTE Electric owns and operates ~~671~~669 distribution substations with a capacity of approximately ~~33,648,000~~33,418,000 kilovolt-amperes (kVA) and approximately ~~430,600~~428,600 line transformers with a capacity of approximately ~~22,306,000~~23,272,000 kVA.

Circuit miles of electric distribution lines owned and in service as of December 31, ~~2012:~~2013:


	Circuit Miles		Circuit Miles
Operating Voltage-Kilovolts (kV)	Overhead	Underground	Overhead	Underground
4.8 kV to 13.2 kV	27,856	14,585	27,739	14,578
24 kV	182	696	182	692
40 kV	2,278	383	2,289	383
120 kV	54	8	54	8
	30,370	15,672	30,264	15,661

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

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

See Notes 3, 10, 11 and 19 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

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

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

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

The electric Customer Choice program in Michigan allows our electric customers to purchase their electricity from alternative electric suppliers of generation services, subject to limits. Customers choosing to purchase power from alternative electric suppliers represented approximately 10% of retail sales in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011. Customers participating in the electric Customer Choice program consist primarily of industrial and commercial ~~customers whose MPSC-authorized full service rates exceed market costs.~~customers. MPSC rate orders and 2008 energy legislation enacted by the State of Michigan have placed a 10% cap on the total potential Customer Choice related migration, mitigating some of the unfavorable effects of electric Customer

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

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

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

Our gas sales, end user transportation and intermediate transportation volumes, revenues and net income are impacted by weather. Given the seasonal nature of our business, revenues and net income are concentrated in the first and fourth quarters of the calendar year. By the end of the first quarter, the heating season is largely over, and we typically realize substantially reduced revenues and earnings in the second quarter and losses in the third quarter. The impacts of changes in average customer usage are minimized by the RDM. Effective with the self implementation of rates on November 1, 2012, the RDM was terminated. The DTE Gas partial rate case settlement agreement approved by the MPSC in December 2012 ~~creates~~created a new RDM effective November 1, 2013 which decouples weather normalized distribution revenue inside caps. The caps are tied to expected customer conservation attributable to DTE ~~Gas'~~Gas's energy efficiency ~~program.~~program, or 1.125% in year one, increasing to 2.25% for the second and future periods.

Our operations are not dependent upon a limited number of customers, and the loss of any one or a few customers would not have a material adverse effect on our Gas segment.

Our gas distribution system has a planned maximum daily send-out capacity of ~~2.4~~2.5 Bcf, with approximately ~~64%~~67% of the volume coming from underground storage for ~~2012.~~2013. Peak-use requirements are met through utilization of our storage facilities, pipeline transportation capacity, and purchased gas supplies. Because of our geographic diversity of supply and our pipeline transportation and storage capacity, we are able to reliably meet our supply requirements. We believe natural gas supply and pipeline capacity will be sufficiently available to meet market demands in the foreseeable future.

We purchase natural gas supplies in the open market by contracting with producers and marketers, and we maintain a diversified portfolio of natural gas supply contracts. Supplier, producing region, quantity, and available transportation diversify our natural gas supply base. We obtain our natural gas supply from various sources in different geographic areas (Gulf Coast, Mid-Continent, Canada and Michigan) under agreements that vary in both pricing and terms. Gas supply pricing is generally tied to the New York Mercantile Exchange and published price indices to approximate current market prices combined with MPSC approved fixed price supplies with varying terms and volumes through ~~2015.~~2016.

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

We own distribution, storage and transportation properties that are located in the State of Michigan. Our distribution system includes approximately 19,000 miles of distribution mains, approximately ~~1,173,000~~1,162,000 service pipelines and approximately ~~1,309,000~~1,311,000 active meters. We own approximately 2,000 miles of transmission pipelines that deliver natural gas to the distribution districts and interconnect our storage fields with the sources of supply and the market areas.

We own storage properties relating to four underground natural gas storage fields with an aggregate working gas storage capacity of approximately 139 Bcf. These facilities are important in providing reliable and cost-effective service to our customers. In addition, we sell storage services to third parties.

Most of our distribution and transportation property is located on property owned by others and used by us through easements, permits or licenses. Substantially all of our property is subject to the lien of a mortgage.

We ~~own 68 miles of transportation and gathering (non-utility) pipelines in the northern lower peninsula of Michigan. We~~ lease a portion of our pipeline system to the Vector Pipeline Partnership (an affiliate) through a capital lease arrangement. See Note 18 of the Notes to Consolidated Financial Statements in Item 8 of the Report.

DTE ~~Gas'~~Gas's business is subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to rates, recovery of certain costs, including the costs of regulatory assets, conditions of service, accounting and operating-related matters. DTE ~~Gas'~~Gas's MPSC-approved rates charged to customers have historically been designed to allow for the recovery of costs, plus an authorized rate of return on our investments. DTE Gas operates natural gas storage and transportation facilities in Michigan as intrastate facilities regulated by the MPSC and provides intrastate storage and transportation services pursuant to an MPSC-approved tariff.

DTE Gas also provides interstate storage and transportation services in accordance with an Operating Statement on file with the FERC. The FERC's jurisdiction is limited and extends to the rates, non-discriminatory requirements, and the terms and conditions applicable to storage and transportation provided by DTE Gas in interstate markets. FERC granted DTE Gas

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

See ~~Note~~Notes 11 and 19 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.

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

Our strategy is to be the preferred provider of natural gas services in Michigan. We expect future sales volumes to decline due to reduced natural gas usage by customers due to more efficient furnaces and appliances, and an increased emphasis on conservation of energy usage. We continue to provide energy-related services that capitalize on our expertise, capabilities and efficient systems. We continue to focus on lowering our operating costs by improving operating efficiencies.

Competition in the gas business primarily involves other natural gas transportation providers, as well as providers of alternative fuels and energy sources. The primary focus of competition for end user transportation is cost and reliability. Some large commercial and industrial customers have the ability to switch to alternative fuel sources such as coal, electricity, oil and steam. If these customers were to choose an alternative fuel source, they would not have a need for our end-user transportation service. In addition, some of these customers could bypass our pipeline system and have their gas delivered directly from an interstate pipeline. We compete against alternative fuel sources by providing competitive pricing and reliable service, supported by our storage capacity.

Our extensive transportation pipeline system has enabled us to market 400 to 500 Bcf annually for intermediate storage and transportation services for Michigan gas producers, marketers, distribution companies and other pipeline companies. We operate in a central geographic location with connections to major Midwestern interstate pipelines that extend throughout the Midwest, eastern United States and eastern Canada.

DTE ~~Gas’~~Gas’s storage capacity is used to store natural gas for delivery to DTE ~~Gas'~~Gas's customers as well as sold to third parties, under a variety of arrangements for periods up to three years. Prices for storage arrangements for shorter periods are generally higher, but more volatile than for longer periods. Prices are influenced primarily by market conditions, weather and natural gas pricing.

The Gas Storage and Pipelines business holds the following property:

The assets of these businesses are well integrated with other DTE Energy operations. Pursuant to an operating agreement, DTE Gas provides physical operations, maintenance, and technical support for the Washington 10 and 28 storage facilities and for the ~~DTE Gas pipeline.~~Michigan gathering systems.

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

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

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

Power and Industrial Projects will continue leveraging its energy-related operating experience and project management capability to develop and grow our ~~steel;~~steel, renewable ~~power;~~power, on-site ~~energy;~~energy, landfill gas ~~recovery;~~recovery and REF businesses. We also will continue to pursue opportunities to provide asset management and operations services to third parties. There are limited competitors for our existing disparate businesses who provide similar products and services. Our operations are dependent upon a limited number of customers, and the loss of any one or a few customers could have a material adverse effect on the Power and Industrial Projects business.

We anticipate building around our core strengths in the markets where we operate. In determining the markets in which to compete, we examine closely the regulatory and competitive environment, new and pending legislation, the number of

We intend to focus on the following areas for growth:

Energy Trading focuses on physical and financial power, gas and coal marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, and optimization of contracted natural gas pipeline transportation and storage, and generating capacity positions. Energy Trading also provides natural gas, power and related services which may include the management of associated storage and transportation contracts on the customers’ behalf under FERC Asset Management Arrangements, and the supply or purchase of renewable energy credits to various customers. Our customer base is predominantly utilities, local distribution companies, pipelines, producers and generators, and other marketing and trading companies. We enter into derivative financial instruments as part of our marketing and hedging activities. These financial instruments are generally accounted for under the mark-to-market method, which results in the recognition in earnings of unrealized gains and losses from changes in the fair value of the derivatives. We utilize forwards, futures, swaps and option contracts to mitigate risk associated with our marketing and trading activity as well as for proprietary trading within defined risk guidelines. Energy Trading also provides commodity risk management services to the other businesses within DTE Energy.

Significant portions of the Energy Trading portfolio are economically hedged. Most financial instruments and physical power and gas contracts are deemed derivatives; whereas, natural gas inventory, contracts for pipeline transportation, renewable energy credits and certain storage assets are not derivatives. As a result, this segment may experience earnings volatility as derivatives are marked-to-market without revaluing the underlying non-derivative contracts and assets. The segment’s strategy is to economically manage the price risk of these underlying non-derivative contracts and assets with futures, forwards, swaps and options. This results in gains and losses that are recognized in different interim and annual accounting periods.

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

Our strategy for the Energy Trading business is to deliver value-added services to our customers. We seek to manage this business in a manner consistent with and complementary to the growth of our other business segments. We focus on physical marketing and the optimization of our portfolio of energy assets. We compete with electric, gas and coal marketers, financial institutions, traders, utilities and other energy providers. The Energy Trading business is dependent upon the availability of capital and an investment grade credit rating. The Company believes it has ample available capital capacity to support Energy Trading activities. We monitor our use of capital closely to ensure that our commitments do not exceed capacity. A material credit restriction would negatively impact our financial performance. Competitors with greater access to capital or at a lower cost may have a competitive advantage. We have risk management and credit processes to monitor and mitigate risk.

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

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

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

Water - In response to an EPA regulation, DTE Electric is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of completed studies and expected future studies, DTE Electric may be required to install technologies to reduce the impacts of the water intakes. However, the types of technologies are unknown at this time. The EPA is expected to finalize regulations on cooling water intake in early 2014. The EPA has also issued ~~an information collection request to begin a review of~~proposed steam electric effluent guidelines. When finalized, these guidelines are expected to require additional wastewater discharge controls.

Contaminated and Other Sites - Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. The facilities, which produced gas, have been designated as manufactured gas plant (MGP) sites. Gas segment owns, or previously owned, fifteen such former MGP sites. DTE Electric owns, or previously owned, three former MGP sites. The Company anticipates the cost amortization methodology approved by the MPSC for DTE Gas, which allows DTE Gas to amortize the MGP costs over a ten-year period beginning with the year subsequent to the year the MGP costs were incurred, and the cost deferral and rate recovery mechanism for Citizens ~~Fuel Gas~~ approved by the City of Adrian, will prevent MGP environmental costs from having a material adverse impact on the Company's results of operations.

We are also in the process of cleaning up other sites where contamination is present as a result of historical and ongoing utility operations. These other sites include an engineered ash storage facility, electrical distribution substations, gas pipelines, electric generating power plants, and underground and aboveground storage tank locations. Cleanup activities associated with these sites will be conducted over the next several years. Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for these sites and affect the Company's financial position and cash flows and the rates we charge our customers.

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

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

None.

In July 2009, DTE Energy received a Notice of ~~Violation (NOV)/~~Violation/Finding of Violation ~~(FOV)~~(NOV/FOV) from the EPA alleging, among other things, that five of DTE ~~Electric's~~Electric power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and operating permit requirements under the Clean Air Act. In June 2010, the EPA issued a NOV/FOV making similar allegations related to a ~~recent~~ project and outage at Unit 2 of the Monroe Power Plant. In March 2013, DTE Energy received a supplemental NOV from the EPA relating to the July 2009 NOV/FOV. The supplemental NOV alleged additional violations relating to the New Source Review provisions under the Clean Air Act, among other things.

In August 2010, the ~~United States~~U.S. Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and DTE Electric, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require DTE Electric to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require DTE Electric to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from DTE Electric's fleet of coal-fired power plants until the new control equipment is operating. On August 23, 2011, the U.S. District 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~~On March 28, 2013, the Court of Appeals ~~were held on November 27, 2012~~remanded the case to the U.S. District Court for review of the procedural component of the New Source Review notification requirements. On September 3, 2013, the EPA caused to be filed a motion seeking leave to amend their complaint regarding the June 2010 NOV/FOV adding additional claims related to outage work performed at the Trenton Channel and Belle River power plants as well as additional claims related to work performed at the Monroe Power Plant. In addition, the Sierra Club caused to be filed a ~~decision is expected in early 2013.~~motion to add a claim regarding the River Rouge Power Plant. The EPA and Sierra Club motions are currently pending with the U.S. District Court Judge.

Our common stock is listed on the New York Stock Exchange, which is the principal market for such stock. The following table indicates the reported high and low sales prices of our common stock on the Composite Tape of the New York Stock Exchange and dividends paid per share for each quarterly period during the past two years:

At December 31, ~~2012~~2013, there were ~~172,351,680~~177,087,230 shares of our common stock outstanding. These shares were held by a total of ~~67,753~~64,638 shareholders of record.

Our Bylaws nullify Chapter 7B of the Michigan Business Corporation Act (Act). This Act regulates shareholder rights when an individual’s stock ownership reaches 20% of a Michigan corporation’s outstanding shares. A shareholder seeking control of the Company cannot require our Board of Directors to call a meeting to vote on issues related to corporate control within 10 days, as stipulated by the Act.

We paid cash dividends on our common stock of $445 million in 2013, $407 million in 2012, and $389 million in 2011~~, and $360 million in~~ ~~2010~~. The amount of future dividends will depend on our earnings, cash flows, financial condition and other factors that are periodically reviewed by our Board of Directors. Although there can be no assurances, we anticipate paying dividends for the foreseeable future.

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

All of our equity compensation plans that provide for the annual awarding of stock-based compensation have been approved by shareholders. See Note 21 of the Notes to Consolidated Financial Statements in Item 8 of this Report for additional detail.

See the following table for information as of December 31, ~~2012~~2013.

The following table provides information about our purchases of equity securities that are registered by the Company pursuant to Section 12 of the Exchange Act of 1934 for the ~~year~~quarter ended December 31, ~~2012~~2013:

DTE Energy is a diversified energy company with ~~2012~~2013 operating revenues of approximately ~~$8.8~~$9.7 billion and approximately $26 billion in assets. We are the parent company of DTE Electric and DTE Gas, regulated electric and natural gas utilities engaged primarily in the business of providing electricity and natural gas sales, distribution and storage services throughout ~~southeastern~~ Michigan. We operate three energy-related non-utility segments with operations throughout the United States.

The following table summarizes our financial results:

Gross margin decreased $109 million in 2013 and decreased $66 million in ~~2012 and increased $75 million in 2011.~~2012. The overall decrease in gross margin in ~~2012~~2013 was ~~the result of decreased economic performance~~primarily due to timing from mark-to-market adjustments on certain transactions in our ~~power~~gas structured strategy.

Natural gas structured transactions typically involve a physical purchase or sale of natural gas in the future and/or natural gas basis financial instruments which are derivatives and a related non-derivative pipeline transportation contract. These gas ~~trading and power full requirements services strategies~~structured transactions can result in significant earnings volatility as the derivative components are marked-to-market without revaluing the related non-derivative contracts. During the fourth quarter of 2013, we saw significant increases in gas prices which led to the volatility in the accounting earnings due to ~~fewer market opportunities.~~the physical component being marked-to-market without an offsetting mark on the transportation component. Unrealized losses from gas structured transactions were $89 million in 2013. We anticipate that approximately 65% of the financial impact of this timing difference will reverse during the first quarter of 2014 as the underlying contracts are settled.

The decrease in gross margin in 2013 represents a $1 million decrease in realized margins and a $108 million decrease in unrealized margins. The $1 million decrease in realized margins is due to $40 million of unfavorable results, primarily in our power trading, power full requirements, and gas transportation strategies, offset by $39 million of favorable results, primarily in our gas and coal trading, and gas structured strategies. The $108 million decrease in unrealized margins is due to $123 million of unfavorable results, primarily in our gas structured, gas trading and gas transportation strategies, offset by $15 million of favorable results, primarily in our power full requirements strategy.

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

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

See also the “Fair Value” section that follows.

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

The 2013 net loss of $44 million represented an improvement of $3 million from the 2012 net loss of $47 million due primarily to lower impairments of investments.

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

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

We use cash to maintain and expand our electric and natural gas utilities and to grow our non-utility businesses, retire and pay interest on long-term debt and pay dividends. We believe that we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements. In ~~2013,~~2014, we expect that cash from operations will be ~~$1.8~~$1.6 billion due to lower surcharge collections and higher ~~working capital requirements.~~cash contributions to employee benefit plans. We anticipate base level utility capital investments, environmental, renewable and energy optimization expenditures and expenditures for non-utility businesses in ~~2013~~2014 of approximately ~~$2.2~~$2.3 billion. We plan to seek regulatory approval to include utility capital expenditures in our regulatory rate base consistent with prior treatment. Capital spending for growth of existing or new non-utility businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria.

A majority of our operating cash flow is provided by our electric and natural gas utilities, which are significantly influenced by factors such as weather, electric Customer Choice, regulatory deferrals, regulatory outcomes, economic conditions and operating costs.

Cash from operations was lower by $55 million in 2013. The reduction in operating cash flow reflects lower cash generated from working capital items, partially offset by higher net income after adjusting for non-cash and non-operating items (primarily depreciation, depletion and amortization and deferred income taxes).

Cash from operations ~~totaling $2.2 billion in 2012~~ was $201 million higher ~~than the comparable 2011 period.~~in 2012. The improvement in operating cash flow ~~comparison primarily~~ reflects higher cash generated from working capital items, partially offset by lower net income after adjusting for non-cash and non-operating items ~~(depreciation,~~(primarily depreciation, depletion and amortization, deferred income taxes, loss on sale of non-utility business and asset (gains) and losses, reserves and impairments, net).

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

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

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

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~~Table of Contents~~

Capital spending within our non-utility businesses is primarily for ongoing maintenance, expansion and ~~expansion. The balance of non-utility spending is for growth, which we manage very carefully.~~growth. We look to make growth investments that meet strict criteria in terms of strategy, management skills, risks and returns. All new investments are analyzed for their rates of return and cash payback on a risk adjusted basis. We have been disciplined in how we deploy capital and will not make investments unless they meet our criteria. For new business lines, we initially invest based on research and analysis. We start with a limited investment, we evaluate results and either expand or exit the business based on those results. In any given year, the amount of growth capital will be determined by the underlying cash flows of the Company with a clear understanding of any potential impact on our credit ratings.

Net cash used for investing activities was higher by $137 million in ~~both~~2013 due primarily to increased capital expenditures by our utility businesses.

Net cash used for investing activities was higher by $209 million in 2012 ~~and 2011~~ due primarily to increased capital expenditures by our utility and non-utility businesses. The 2012 increase includes higher capital expenditures for the Bluestone Pipeline project and the Power and Industrial Projects acquisition of fourteen on-site energy projects, partially offset by the proceeds from the sale of the Unconventional Gas Production business.

Cash ~~from~~used for Financing Activities

We rely on both short-term borrowing and long-term financing as a source of funding for our capital requirements not satisfied by our operations.

Our strategy is to have a targeted debt portfolio blend of fixed and variable interest rates and maturity. We continually evaluate our leverage target, which is currently ~~50 percent~~50% to ~~52 percent,~~52%, to ensure it is consistent with our objective to have a strong investment grade debt rating.

Net cash used for financing activities was ~~$443~~$182 million lower in ~~2012, compared~~2013. The decrease was primarily attributable to ~~net~~higher issuances of long-term debt, partially offset by higher redemptions of long-term debt.

Net cash used for financing activities ~~of approximately $445~~was $2 million ~~for the same period~~lower in ~~2011.~~2012. The ~~change~~decrease was primarily attributable to lower redemptions of long-term debt, offset by a reduction in short-term borrowings.

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

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Outlook

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

We may be impacted by the ~~delayed~~timing of collection ~~of underrecoveries~~or refund of our various recovery and tracking mechanisms as a result of timing of MPSC orders. Energy prices are likely to be a source of volatility with regard to working capital requirements for the foreseeable future. We are continuing our efforts to identify opportunities to improve cash flow through working capital initiatives and maintaining flexibility in the timing and extent of our long-term capital projects.

We have approximately ~~$800~~$900 million in long-term debt maturing in the next twelve months. The repayment of the principal amount of the Securitization debt is funded through a surcharge payable by DTE Electric’s customers. The repayment of the other debt is expected to be paid through internally generated funds or the issuance of long-term debt.

DTE Energy has approximately $1.6 billion of available liquidity at December 31, ~~2012,~~2013, consisting of cash and amounts available under unsecured revolving credit agreements.

~~We expect to issue equity of approximately $300 million in 2013 through our dividend reinvestment plan and pension and other employee benefit plans.~~

At the discretion of management, and depending upon financial market conditions, we anticipate making ~~up to a $315 million contribution~~2014 contributions to the pension plans ~~in 2013. In January 2013, the Company contributed~~of up to $345 million and up to $145 million to ~~its~~the other postretirement benefit plans. ~~At the discretion of management, the Company may make up to an additional $120 million contribution to its postretirement benefit plans in 2013.~~

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~~Table of Contents~~

Various ~~non-utility~~ subsidiaries of the Company have entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade. As of December 31, ~~2012~~2013, the value of the transactions for which the Company would have been exposed to collateral requests had DTE Energy’s credit rating been below investment grade on such date was approximately $~~326~~406 million. In circumstances where an entity is downgraded below investment grade and collateral requests are made as a result, the requesting parties often agree to accept less than the full amount of their exposure to the downgraded entity. In addition, the Company maintains adequate credit facilities to meet this obligation should such an occurrence arise.

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

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

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Contractual Obligations

The following table details our contractual obligations for debt redemptions, leases, purchase obligations and other long-term obligations as of December 31, ~~2012:~~2013:


	Total		2013		2014-2015		2016-2017		2018 and Beyond		Total		2014		2015-2016		2017-2018		2019 and Beyond
	(In millions)										(In millions)
Long-term debt:
Mortgage bonds, notes and other(a)	$	6,865	$	634	$	1,066	$	474	$	4,691	$	7,326	$	695	$	836	$	416	$	5,379
Securitization bonds	479		177		302		—		—		302		197		105		—		—
Junior subordinated debentures	480		—		—		—		480		480		—		—		—		480
Capital lease obligations	20		7		10		3		—		19		8		11		—		—
Interest	5,890		415		688		577		4,210		6,091		429		670		631		4,361
Operating leases	233		38		56		41		98		230		35		58		45		92
Electric, gas, fuel, transportation and storage purchase obligations ~~(a)~~(b)	4,229		1,856		1,584		222		567		8,499		2,577		1,802		645		3,475
Other long-term obligations ~~(d)~~(e)	148		80		39		13		16		99		40		36		11		12
Total obligations	$	18,344	$	3,207	$	3,745	$	1,330	$	10,062	$	23,046	$	3,981	$	3,518	$	1,748	$	13,799


(a)	Excludes $14 million of unamortized discount on debt.


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


~~(b)~~(c)	Includes liabilities for unrecognized tax benefits of ~~$11~~$10 million.


~~(c)~~(d)	Excludes other long-term liabilities of ~~$179~~$193 million not directly derived from contracts or other agreements.

~~(d)~~(e)

At December 31, ~~2012,~~2013, we met the minimum pension funding levels required under the Employee Retirement Income Security Act of 1974 (ERISA) and the Pension Protection Act of 2006 for our defined benefit pension plans. We may contribute more than the minimum funding requirements for our pension plans and may also make contributions to our ~~benefit plans and our~~other postretirement benefit plans; however, these amounts are not included in the table above as such amounts are discretionary. Planned funding levels are disclosed in the Capital Resources and Liquidity and Critical Accounting Estimates sections herein and in Note 20 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Credit Ratings

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. The Company’s credit ratings affect our cost of capital and other terms of financing as well as our ability to access the credit and commercial paper markets. Management believes that our current credit ratings provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to us may affect our ability to access these funding sources or cause an increase in the return required by investors.

As part of the normal course of business, DTE Electric, DTE Gas and various non-utility subsidiaries of the Company routinely enter into physical or financially settled contracts for the purchase and sale of electricity, natural gas, coal, capacity, storage and other energy-related products and services. Certain of these contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit in the event that the senior unsecured debt rating of DTE Energy is downgraded below investment grade. Certain of these contracts for DTE Electric and DTE Gas contain similar provisions in the event that the senior unsecured debt rating of the particular utility is downgraded below investment grade.

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The amount of such collateral which could be requested fluctuates based upon commodity prices and the provisions and maturities of the underlying transactions and could be substantial. Also, upon a downgrade below investment grade, we could have restricted access to the commercial paper market and if DTE Energy is downgraded below investment grade our non-utility businesses, especially the Energy Trading and Power and Industrial Projects segments, could be required to restrict operations due to a lack of available liquidity. A downgrade below investment grade could potentially increase the borrowing costs of DTE Energy and its subsidiaries and may limit access to the capital markets. The impact of a downgrade will not affect our ability to comply with our existing debt covenants. While we currently do not anticipate such a downgrade, we cannot predict the outcome of current or future credit rating agency reviews.

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In January ~~2012,~~2013, Fitch ~~Ratings~~ raised ~~DTE Electric's~~the senior secured debt rating for DTE Gas from 'A-' to 'A' and ~~raised~~affirmed the senior unsecured debt rating for DTE ~~Gas'~~Energy at 'BBB' and senior secured debt rating for DTE Electric at 'A'. The upgrade reflects improved earnings and cash flows following recent rate case orders, a constructive regulatory environment, and strong credit metrics. In February 2013, based on steady improvement in the financial profiles due in large part to a constructive legislative and regulatory environment, Moody's upgraded DTE Energy's unsecured debt rating from ~~'BBB+'~~'Baa2' to ~~'A-'. At~~'Baa1' and upgraded the ~~same time, Fitch Ratings revised the outlook for~~secured debt rating of DTE Electric and DTE Gas from ~~stable~~'A2' to ~~positive.~~'A1'. In ~~January~~August 2013, ~~Fitch~~S&P raised ~~DTE Gas' senior secured debt rating from 'A-' to 'A' and revised~~ the credit outlook from ~~positive~~'stable' to ~~stable. In February 2012, Moody's revised the outlook of~~'positive' for DTE Energy, DTE Electric, and DTE Gas ~~from stable~~pointing to ~~positive.~~the Company's improving business risk profile. S&P also revised its business risk profile to 'excellent'. In ~~February 2013,~~January 2014, based on a favorable view of the U.S. regulatory environment, Moody's ~~raised~~upgraded DTE Energy's ~~senior~~ unsecured debt rating from ~~'Baa2'~~'Baa1' to ~~'Baa1', DTE Electric's senior~~'A3' and upgraded the secured debt rating ~~from 'A2' to 'A1', and DTE Gas' senior secured debt rating from 'A2 to A1'. At the same time, Moody's revised the outlook~~ of ~~DTE Energy,~~ DTE Electric and DTE Gas from ~~positive~~'A1' to ~~stable.~~'Aa3'.

CRITICAL ACCOUNTING ESTIMATES

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

Regulation

A significant portion of our business is subject to regulation. This results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses. DTE Electric and DTE Gas are required to record regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Future regulatory changes or changes in the competitive environment could result in the discontinuance of this accounting treatment for regulatory assets and liabilities for some or all of our businesses. Management believes that currently available facts support the continued use of regulatory assets and liabilities and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment.

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

Derivatives and Hedging Activities

Derivatives are generally recorded at fair value and shown as Derivative Assets or Liabilities. Changes in the fair value of the derivative instruments are recognized in earnings in the period of change, unless the derivative meets certain defined conditions and qualifies as an effective hedge. The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchases and normal sales are not recorded at fair value. Substantially all of the commodity contracts entered into by DTE Electric and DTE Gas meet the criteria specified for this exception.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets and liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. Management makes certain assumptions it believes that market participants would use in pricing assets and liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and our counterparties is incorporated in the valuation of the assets and liabilities through the use of credit reserves, the impact of which was immaterial at December 31, ~~2012~~2013 and ~~2011~~2012. Management believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

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

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Allowance for Doubtful Accounts

We establish an allowance for doubtful accounts based on historical losses and management's assessment of existing economic conditions, customer trends, and other factors. The allowance for doubtful accounts for our two utilities is calculated using the aging approach that utilizes rates developed in reserve studies and applies these factors to past due receivable balances. We believe the allowance for doubtful accounts is based on reasonable estimates.

Asset Impairments

Goodwill

Certain of our reporting units have goodwill or allocated goodwill resulting from purchase business combinations. We perform an impairment test for each of our reporting units with goodwill annually or whenever events or circumstances indicate that the value of goodwill may be impaired.

~~In September 2011, the FASB issued ASU No. 2011-08,~~ ~~Intangibles-Goodwill and Other (Topic 350)-Testing Goodwill for Impairment~~, which is intended to simplify how entities test for goodwill impairment by permitting an entity the option of performing a qualitative assessment to determine whether further impairment testing is necessary (“step zero”). The standard is effective for annual and interim goodwill impairments tests for fiscal years beginning after December 15, 2011. We did not apply step zero for the 2012 goodwill impairment test and proceeded directly to step one of the test.

In performing Step 1 of the impairment test, we compare the fair value of the reporting unit to its carrying value including goodwill. If the carrying value including goodwill were to exceed the fair value of a reporting unit, Step 2 of the test would be performed. Step 2 of the impairment test requires the carrying value of goodwill to be reduced to its fair value, if lower, as of the test date.

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

We performed our annual impairment test as of October 1, ~~2012~~2013 and determined that ~~except for the Unconventional Gas Production reporting unit,~~ the estimated fair value of each reporting unit exceeded its carrying value, and no impairment existed. ~~The $2 million of goodwill attributable to the Unconventional Gas Production reporting unit was written off in the fourth quarter of 2012 in connection with its sale.~~ As part of the annual impairment test, we also compared the aggregate fair value of our reporting units to our overall market capitalization. The implied premium of the aggregate fair value over market capitalization is likely attributable to an acquisition control premium (the price in excess of a stock's market price that investors typically pay to gain control of an entity). The results of the test and key estimates that were incorporated are as follows.

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~~Table of Contents~~

As of October 1, ~~2012~~2013 Valuation Date:


Reporting Unit	Goodwill		Fair Value Reduction % (a)		Discount Rate		Terminal Multiple (b)	Valuation Methodology (c)	Goodwill		Fair Value Reduction % (a)		Discount Rate		Terminal Multiple (b)	Valuation Methodology (c)
	(In millions)								(In millions)
Electric	$	1,208	31	%	7	%	9.0x	DCF, assuming stock sale	$	1,208	37	%	7	%	9.0x	DCF, assuming stock sale
Gas	745		21	%	7	%	10.5x	DCF, assuming stock sale	743		29	%	6	%	10.5x	DCF, assuming stock sale
Power and Industrial Projects (d)	26		70	%	9	%	10.0x	DCF, assuming asset sale (e)	26		65	%	9	%	10.0x	DCF, assuming asset sale (e)
Gas Storage and Pipelines	22		82	%	8	%	11.0x	DCF, assuming asset sale	24		84	%	8	%	11.0x	DCF, assuming asset sale
Energy Trading	17		33	%	15	%	n/a	DCF, assuming asset sale	17		15	%	11	%	n/a	DCF, assuming asset sale
Unconventional Gas Production (f)	2		n/a		n/a		n/a	Sales Price
	$	2,020							$	2,018

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

We had pension costs of $228 million in 2013, $220 million in 2012, and $172 million in ~~2011, and $112~~2011. Other postretirement benefits costs (credit) were $(42) million in ~~2010. Postretirement benefits costs were~~2013, $151 million in 2012 and $122 million in ~~2011~~2011. Pension and ~~$164 million in 2010. Pension and~~other postretirement benefits costs for ~~2012~~2013 are calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on our plan assets of 8.25%. In developing our expected long-term rate of return assumptions, we evaluated asset class risk and return expectations, as well as inflation assumptions. Projected returns are based on broad equity, bond and other markets. Our ~~2013~~2014 expected long-term rate of return on pension plan assets is based on an asset allocation assumption utilizing active investment

We calculate the expected return on pension and other postretirement benefit plan assets by multiplying the expected return on plan assets by the market-related value (MRV) of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments that are to be made during the year. Current accounting rules provide that the MRV of plan assets can be either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For our pension plans, we use a calculated value when determining the MRV of the pension plan assets and recognize changes in fair value over a three-year period. Accordingly, the future value of assets will be impacted as previously deferred gains or losses are recognized. Financial markets in ~~2012~~2013 contributed to our investment performance resulting in unrecognized net gains. As of December 31, ~~2012,~~2013, we had ~~$81~~$150 million of cumulative ~~losses~~gains that remain to be recognized in the calculation of the MRV of pension assets related to investment performance in 2013, 2012 ~~2011~~ and ~~2010.~~2011. For our other postretirement benefit plans, we use fair value when determining the MRV of other postretirement benefit plan assets, therefore all investment ~~losses~~gains and ~~gains~~losses have been recognized in the calculation of MRV for these plans.

The discount rate that we utilize for determining future pension and other postretirement benefit obligations is based on a yield curve approach and a review of bonds that receive one of the two highest ratings given by a recognized rating agency. The yield curve approach matches projected pension plan and other postretirement benefit payment streams with bond portfolios reflecting actual liability duration unique to our plans. The discount rate determined on this basis ~~decreased~~increased to 4.95% at December 31, 2013 from 4.15% at December 31, ~~2012 from 5.0% at December 31, 2011.~~2012. We estimate that our ~~2013~~2014 total pension costs will approximate ~~$226~~$175 million compared to ~~$220~~$228 million in ~~2012~~2013 primarily due to greater than expected 2013 returns, a ~~lower~~higher discount rate, and higher amortization of net actuarial losses, partially offset by 2013 contributions. Our 2013 postretirement benefit costs will approximate $30 million compared to $151 million in 2012 primarily due to plan design changes and favorable retiree medical utilization, partially offset by a lower ~~discount rate, higher~~ amortization of net actuarial losses and ~~updated~~2014 contributions. Our 2014 other postretirement benefit credit will approximate $(120) million compared to $(42) million in 2013 due to the continued impact of plan design changes, favorable retiree medical utilization trends, greater than expected returns, a higher discount rate, lower amortization of net actuarial losses and modestly lower assumed long-term retiree medical inflation. Our health care trend rate for pre-65 participants assumes ~~7.00%~~7.5% for ~~2013 through~~2014 and 2015, 7% for 2016 and 2017, ~~6.50%~~6.5% in 2018, ~~6.00%~~6% in 2019, ~~5.50%~~5.75% in 2020, ~~and 5.00%~~5.5% in 2021, 5.25% in 2022, 5% in 2023, 4.75% in 2024 and 4.5% in 2025 and beyond. Our health care trend rate for post-65 participants assumes 6.5% for 2014 and 2015, 6.25% for 2016 and 2017, 6% in 2018, 5.75% in 2019, 5.5% in 2020, 5.25% in 2021, 5% in 2022, 4.75% in 2023, 4.5% in 2024 and beyond. Future actual pension and other postretirement benefit costs will depend on future investment performance, changes in future discount rates and various other factors related to plan design. The MPSC approved the deferral of the non-capitalized portion of DTE Gas' negative pension expense. DTE Gas records a regulatory liability for any negative pension costs, as determined under generally accepted accounting principles.

Lowering the expected long-term rate of return on our plan assets by one percentage point would have increased our ~~2012~~2013 pension costs by approximately $32 million. Lowering the discount rate and the salary increase assumptions by one percentage point would have increased our ~~2012~~2013 pension costs by approximately ~~$14~~$16 million. Lowering the expected long-term rate of return on our plan assets by one percentage point would have increased our ~~2012~~2013 other postretirement costs by approximately ~~$10~~$13 million. Lowering the discount rate assumption by one percentage point would have ~~increased~~decreased our ~~2012~~2013 other postretirement ~~costs~~credit by approximately ~~$46~~$27 million. Lowering the health care cost trend assumptions by one percentage point would have ~~decreased~~increased our other postretirement ~~benefit service and interest costs~~credit for ~~2012~~2013 by approximately ~~$26~~$8 million.

The value of our qualified pension and other postretirement benefit plan assets was $5.2 billion at December 31, 2013 and $4.4 billion at December 31, ~~2012 and $3.9 billion at December 31, 2011.~~2012. At December 31, ~~2012,~~2013, our qualified pension plans were underfunded by ~~$1.4 billion~~$565 million and our other postretirement benefit plans were underfunded by ~~$1.2 billion.~~$351 million. The ~~2012 and 2011~~2013 funding levels ~~were~~ generally ~~similar~~improved due to increased discount rates, investment returns in excess of expected returns, plan sponsor contributions and plan design changes for our other postretirement benefits plans in ~~2012~~2013 and ~~2011, largely offset by the impact of decreased discount rates.~~2012.

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

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Legal Reserves

We are involved in various legal proceedings, claims and litigation arising in the ordinary course of business. We regularly assess our liabilities and contingencies in connection with asserted or potential matters, and establish reserves when appropriate. Legal reserves are based upon management’s assessment of pending and threatened legal proceedings and claims against us.

Insured and Uninsured Risks

Our comprehensive insurance program provides coverage for various types of risks. Our insurance policies cover risk of loss including property damage, general liability, workers’ compensation, auto liability, and directors’ and officers’ liability. Under our risk management policy, we self-insure portions of certain risks up to specified limits, depending on the type of exposure. The maximum self-insured retention for various risks is as follows: property ~~damage-~~damage - $10 million, general ~~liability-~~liability - $7 million, workers’ ~~compensation-~~compensation - $9 million, and auto ~~liability-$7~~liability - $7 million. We have an actuarially determined estimate of our incurred but not reported (IBNR) liability prepared annually and we adjust our reserves for self-insured risks as appropriate. As of December 31, ~~2012,~~2013, this IBNR liability was approximately ~~$37~~$36 million.

41

Accounting for Tax Obligations

We are required to make judgments regarding the potential tax effects of various financial transactions and results of operations in order to estimate our obligations to taxing authorities. We account for uncertain income tax positions using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If the benefit does not meet the more likely than not criteria for being sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We also have non-income tax obligations related to property, sales and use and employment-related taxes and ongoing appeals related to these tax matters.

Accounting for tax obligations requires judgments, including assessing whether tax benefits are more likely than not to be sustained, and estimating reserves for potential adverse outcomes regarding tax positions that have been taken. We also assess our ability to utilize tax attributes, including those in the form of carry-forwards, for which the benefits have already been reflected in the financial statements. We believe the resulting tax reserve balances as of December 31, 2013 and 2012 ~~and December 31, 2011~~ are ~~appropriately accounted.~~appropriate. The ultimate outcome of such matters could result in favorable or unfavorable adjustments to our consolidated financial statements and such adjustments could be material.

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

FAIR VALUE

Derivatives are generally recorded at fair value and shown as Derivative Assets or Liabilities. Contracts we typically classify as derivative instruments include power, natural gas, oil and certain coal forwards, futures, options and swaps, and foreign currency exchange contracts. Items we do not generally account for as derivatives include natural gas inventory, pipeline transportation, renewable energy credits and storage assets. See Notes 3 and 4 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

The tables below do not include the expected earnings impact of non-derivative natural gas storage, transportation, certain power contracts and renewable energy credits which are subject to accrual accounting. Consequently, gains and losses from these positions may not match with the related physical and financial hedging instruments in some reporting periods, resulting in volatility in DTE Energy’s reported period-by-period earnings; however, the financial impact of the timing differences will reverse at the time of physical delivery and/or settlement.

The Company manages its mark-to-market (MTM) risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, itthe Company records and manages the energy purchase and sale obligations under its contracts in separate components based on the commodity (e.g. electricity or natural gas), the product (e.g. electricity for delivery during peak or off-peak hours), the delivery location (e.g. by region), the risk profile (e.g. forward or option), and the delivery period (e.g. by month and year).

The Company has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active

43

~~Table of Contents~~

markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). For further discussion of the fair value ~~hierarchy. See~~hierarchy, see Note 3 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

The following tables provide details on changes in our MTM net asset (or liability) position during ~~2012:~~2013:


	Total			Total
	(In millions)			(In millions)
MTM at December 31, 2011	$	49
MTM at December 31, 2012				$	(4	)
Reclassify to realized upon settlement	(80		)	(89		)
Changes in fair value recorded to income	65			(11		)
Amounts recorded to unrealized income	(15		)	(100		)
Changes in fair value recorded in regulatory liabilities	15			5
Change in collateral held by (for) others	(56		)	(9		)
Option premiums paid and other	3
MTM at December 31, 2012	$	(4	)
Option premiums received and other				(5		)
Amounts recorded in other comprehensive income				1
MTM at December 31, 2013				$	(112	)

The table below shows the maturity of our MTM positions:

DTE Energy has commodity price risk in both utility and non-utility businesses arising from market price fluctuations.

The Electric and Gas businesses have risks in conjunction with the anticipated purchases of coal, natural gas, uranium, electricity, and base metals to meet their service obligations. However, the Company does not bear significant exposure to earnings risk as such changes are included in the PSCR and GCR regulatory rate-recovery mechanisms. In addition, changes in the price of natural gas can impact the valuation of lost and stolen gas and storage sales revenue ~~and uncollectible expenses~~ at the Gas segment. Gas segment manages its market price risk related to storage sales revenue primarily through the sale of long-term storage contracts. The Company is exposed to short-term cash flow or liquidity risk as a result of the time differential between actual cash settlements and regulatory rate recovery.

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

Our Power and Industrial Projects business segment is subject to electricity and natural gas product price risk. ~~To the extent that~~The Company manages its exposures to commodity price risk ~~has not been mitigated~~ through the use of long-term ~~contracts, we manage this exposure using forward energy, capacity and futures~~ contracts.

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

The Company purchases and sells electricity, natural gas, coal, coke and other energy products from and to governmental entities and numerous companies operating in the steel, automotive, energy, retail, financial and other industries. Certain of its customers have filed for bankruptcy protection under ~~Chapter 11 of~~ the U.S. Bankruptcy Code. The Company regularly reviews contingent matters relating to these customers and its purchase and sale contracts and records provisions for amounts considered at risk of probable loss. The Company believes its accrued amounts are adequate for probable loss.

The ~~final resolution~~Company's utilities provide services to the city of ~~these matters may~~Detroit, Michigan (Detroit). Detroit filed for Chapter 9 bankruptcy protection on July 18, 2013. The Company had pre-petition accounts receivable of approximately $20 million outstanding as of the bankruptcy filing date. Detroit has been paying amounts owed in a timely manner and its account is substantially current. The Company does not expect Detroit's bankruptcy filing to have a material ~~effect~~impact on ~~the consolidated~~its financial ~~statements.~~results.

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

We are exposed to credit risk through trading activities. Credit risk is the potential loss that may result if our trading counterparties fail to meet their contractual obligations. We utilize both external and internal credit assessments when determining the credit quality of our trading counterparties.

The following table displays the credit quality of our trading counterparties as of December 31, ~~2012:~~2013:

We are subject to interest rate risk in connection with the issuance of ~~debt and preferred securities.~~debt. In order to manage interest costs, we may use treasury locks and interest rate swap agreements. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). As of December 31, ~~2012,~~2013, we had a floating rate debt-to-total debt ratio of approximately ~~7 percent~~2% (excluding securitized debt).

We have foreign currency exchange risk arising from market price fluctuations associated with fixed priced contracts. These contracts are denominated in Canadian dollars and are primarily for the purchase and sale of natural gas and power as well as for long-term transportation capacity. To limit our exposure to foreign currency exchange fluctuations, we have entered into a series of foreign currency exchange forward contracts through July 2016.

We performed a sensitivity analysis on the fair values of our commodity contracts, long-term debt obligations and foreign currency exchange forward contracts. The commodity contracts and foreign currency exchange risk listed below principally relate to our energy marketing and trading activities. The sensitivity analysis involved increasing and decreasing forward rates at December 31, ~~2012~~2013 and ~~2011~~2012 by a hypothetical 10% and calculating the resulting change in the fair values.

The results of the sensitivity analysis calculations as of December 31, ~~2012~~2013 and ~~2011:~~2012:

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

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

The effectiveness of the Company’s internal control over financial reporting as of December 31, ~~2012~~2013 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm who also audited the Company’s financial statements, as stated in their report which appears herein.

There have been no changes in the Company’s internal control over financial reporting during the quarter ended December 31, ~~2012~~2013 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

DTE Energy owns the following businesses:

DTE Electric and DTE Gas are regulated by the MPSC. Certain activities of DTE Electric and DTE Gas, as well as various other aspects of businesses under DTE Energy are regulated by the FERC. In addition, the Company is regulated by other federal and state regulatory agencies including the NRC, the EPA, the MDEQ and ~~the MDEQ.~~CFTC.

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

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

Certain prior year balances were reclassified to match the current year’s financial statement presentation. Such revisions included an increase in the Consolidated Statements of Cash Flows line items for (i) Proceeds from sale of nuclear decommissioning trust funds, and (ii) Investment in nuclear decommissioning trust funds by $662 million and $753 million for the years ended December 31, 2012 and 2011, respectively. These revisions were needed to properly state the gross purchases and sales activity in the nuclear decommissioning trust fund for the respective years. The totals of Net cash used in investing activities for both 2012 and 2011 were unchanged by these revisions. The revisions noted above are not deemed material, individually or in the aggregate, to the prior period consolidated financial statements.

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

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

Legal entities within the Company's Power and Industrial Projects segment enter into long-term contractual arrangements with customers to supply energy-related products or ~~services, which includes arrangements related to entities acquired in 2012. See Note 6.~~services. The entities are generally designed to pass-through the commodity risk associated with these contracts to the customers, with the Company retaining operational and customer default risk. These entities generally are ~~VIEs.~~VIEs and are consolidated when the Company is the primary beneficiary. In addition, ~~the Company has~~we have interests in certain VIEs that we share control of all significant activities for those entities with our partners, and therefore are accounted for under the equity method.

The Company has variable interests in VIEs through certain of its long-term purchase contracts. As of December 31, ~~2012,~~2013, the carrying amount of assets and liabilities in the Consolidated Statements of Financial Position that relate to its variable interests under long-term purchase contracts are predominately related to working capital accounts and generally represent the amounts owed by the Company for the deliveries associated with the current billing cycle under the contracts. The Company has not provided any form of financial support associated with these long-term contracts. There is no significant potential exposure to loss as a result of its variable interests through these long-term purchase contracts.

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

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

The following table summarizes the major balance sheet items for consolidated VIEs as of December 31, ~~2012~~2013 and ~~December 31, 2011. Amounts at December 31, 2012~~2012. All assets and ~~December 31, 2011 for~~liabilities of a consolidated ~~VIEs~~VIE are presented where it has been determined that ~~are~~a consolidated VIE has either (1) assets that can be used only to settle obligations of the VIE or (2) liabilities for which creditors do not have recourse to the general credit of the primary ~~beneficiary are segregated in the restricted amounts column.~~beneficiary. VIEs, in which the Company holds a majority voting interest and is the primary beneficiary, that meet the definition of a business and whose assets can be used for purposes other than the settlement of the VIE's obligations have been excluded from the table below.

Amounts for non-consolidated VIEs as of December 31, ~~2012~~2013 and ~~December 31, 2011~~2012 are as follows:

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

Non-utility businesses recognize revenues as services are provided and products are delivered. See Note 4 for discussion of derivative contracts.

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

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

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

Comprehensive income (loss) is the change in common shareholders’ equity during a period from transactions and events from non-owner sources, including net income. As shown in the following ~~table,~~tables, amounts recorded to accumulated other comprehensive loss for the year ended December 31, ~~2012~~2013 include unrealized gains and losses from derivatives accounted for as cash flow hedges, unrealized gains and losses on ~~available for sale~~available-for-sale securities, the Company’s interest in other comprehensive income of equity investees, which comprise the net unrealized gains and losses on investments, changes in benefit obligations, consisting of deferred actuarial losses, prior service costs and transition amounts related to pension and other postretirement benefit plans, and foreign currency translation adjustments.

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.

The costs related to the issuance of long-term debt are deferred and amortized over the life of each debt issue. In accordance with MPSC regulations applicable to the Company’s electric and gas utilities, the unamortized discount, premium and expense related to utility debt redeemed with a refinancing are amortized over the life of the replacement issue. Discount, premium and expense on early redemptions of debt associated with non-utility operations are charged to earnings.

The Company generally classifies investments in debt and equity securities as either trading or available-for-sale and has recorded such investments at market value with unrealized gains or losses included in earnings or in other comprehensive income or loss, respectively. Changes in the fair value of Fermi 2 nuclear decommissioning investments are recorded as adjustments to regulatory assets or liabilities, due to a recovery mechanism from customers. The Company’s equity investments are reviewed for impairment each reporting period. If the assessment indicates that the impairment is other than temporary, a loss is recognized resulting in the equity investment being written down to its estimated fair value. See Note 3.

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

Charitable contributions to the DTE Energy Foundation were $2118 million, $21 million, and $1421 million for the years ended December 31, 2013, 2012 ~~2011~~ and ~~2010,~~2011, respectively. The DTE Energy Foundation is a non-consolidated not-for-profit private foundation, the purpose of which is to contribute to and assist charitable organizations and does not serve a direct business or political purpose of DTE.

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

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The Company makes certain assumptions it believes that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and its counterparties is incorporated in the valuation of assets and liabilities through the use of credit reserves, the impact of which was immaterial at December 31, ~~2012~~2013 and ~~December 31, 2011~~.2012. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

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

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, ~~2012~~2013 and ~~2011:~~2012:

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

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

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the years ended December 31, ~~2012~~2013 and ~~2011~~2012:

DTE Electric has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. This obligation is reflected as an asset retirement obligation on the Consolidated Statements of Financial Position. Rates approved by the MPSC provide for the recovery of decommissioning costs of Fermi 2 and the disposal of low-level radioactive waste. DTE Electric is continuing to fund FERC jurisdictional amounts for decommissioning even though explicit provisions are not included in FERC rates. See Note 10.

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

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:

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

At December 31, 2013, investments in the nuclear decommissioning trust funds consisted of approximately 61% in publicly traded equity securities, 37% in fixed debt instruments and 2% in cash equivalents. At December 31, 2012, investments in the nuclear decommissioning trust funds consisted of approximately 61% in publicly traded equity securities, 38% in fixed debt instruments and 1% in cash equivalents.

The debt securities at December 31, 2013 and 2012 had an average maturity of approximately 7 and 6 years, respectively. Securities held in the nuclear decommissioning trust funds are classified as available-for-sale. As DTE Electric does not have the ability to hold impaired investments for a period of time sufficient to allow for the anticipated recovery of market value, all unrealized losses are considered to be other than temporary impairments.

Certain of the Company's derivative positions are subject to netting arrangements which provide for offsetting of asset and liability positions as well as related cash collateral. Such netting arrangements generally do not have restrictions. Under such netting arrangements, the Company offsets the fair value of derivative instruments with cash collateral received or paid for those contracts executed with the same counterparty, which reduces the Company's total assets and liabilities. Cash collateral is allocated between the fair value of derivative instruments and customer accounts receivable and payable with the same counterparty on a pro rata basis to the extent there is exposure. Any cash collateral remaining, after the exposure is netted to zero, is reflected in accounts receivable and accounts payable as collateral paid or received, respectively.

The Company also provides and receives collateral in the form of letters of credit which can be offset against net derivative assets and liabilities as well as accounts receivable and payable. The Company had issued letters of credit of approximately $19 million and $63 million at December 31, 2013 and 2012, respectively, which could be used to offset our net derivative liabilities. Letters of credit received from third parties which could be used to offset our net derivative assets were not material for the periods presented. Such balances of letters of credit are excluded from the tables below and are not netted with the recognized assets and liabilities in the Consolidated Statements of Financial Position.

As of December 31, 2013, the total cash collateral posted, net of cash collateral received, was $12 million. As of December 31, 2012, the total cash collateral received, net of cash collateral posted, was $20 million. As of December 31, 2013, derivative assets and derivative liabilities are shown net of cash collateral of $26 million and $17 million, respectively. There was no cash collateral related to unrealized positions to net against derivative assets and liabilities as of December 31, 2012. The Company recorded cash collateral paid of $34 million and cash collateral received of $13 million not related to unrealized derivative positions as of December 31, 2013. The Company recorded cash collateral paid of $4 million and cash collateral received of $24 million not related to unrealized derivative positions as of December 31, 2012. These amounts are included in accounts receivable and accounts payable and are recorded net by counterparty.

The effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for years ended December 31, ~~2012~~2013 and ~~2011~~2012 is as follows:

Revenues and energy costs related to trading contracts are presented on a net basis in the Consolidated Statements of Operations. Commodity derivatives used for trading purposes, and financial non-trading commodity derivatives, are accounted for using the mark-to-market method with unrealized and realized gains and losses recorded in Operating revenues. Non-trading physical commodity sale and purchase derivative contracts are generally accounted for using the mark-to-market method with unrealized and realized gains and losses for sales recorded in Operating revenue and purchases recorded in Fuel, purchased power and gas.

The effects of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position were $5 million in unrealized gains related to FTRs recognized in Regulatory liabilities for the year ended December 31, 2013, and $15 million in unrealized gains related to FTRs recognized in Regulatory liabilities, for the year ended December 31, 2012~~, and $3 million~~ ~~in unrealized gains related to FTRs recognized in Regulatory liabilities, for the year ended~~ ~~December 31, 2011~~.

The following represents the cumulative gross volume of derivative contracts outstanding as of December 31, ~~2012~~2013:

Various ~~non-utility~~ subsidiaries of the Company have entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade. Certain of these provisions (known as “hard triggers”) state specific circumstances under which the Company can be asked to post collateral upon the occurrence of a credit downgrade, while other provisions (known as “soft triggers”) are not as specific. For contracts with soft triggers, it is difficult to estimate the amount of collateral which may be requested by counterparties and/or which the Company may ultimately be required to post. The amount of such collateral which could be requested fluctuates based on commodity prices (primarily natural gas, power and coal) and the provisions and maturities of the underlying transactions. As of December 31, ~~2012~~2013, DTE Energy's contractual obligation in the ~~value~~form of cash or letter of credit in the ~~transactions for which the Company would have been exposed~~event of a downgrade to ~~collateral requests had DTE Energy’s credit rating been~~ below investment grade, ~~on such date~~ under both hard trigger and soft trigger provisions, was approximately $~~326~~406 million.

The Company has goodwill resulting from purchase business combinations.

The change in the carrying amount of goodwill for the fiscal years ended December 31, ~~2012~~2013 and ~~2011~~2012 is as follows:

Summary of property by classification as of December 31:

The Allowance for Funds used During Construction (AFUDC) capitalized was approximately $2023 million and $1020 million during ~~2012~~2013 and ~~2011,~~2012, respectively.

The composite depreciation rate for DTE Electric was approximately ~~3.3%~~3.4% in 2013 and 3.3% in 2012 ~~2011~~ and ~~2010.~~2011. The composite depreciation rate for DTE Gas was 2.4% in 2013 and 2012, and 2.3% in 2011 ~~and~~ ~~2.5%~~ in ~~2010~~.

The average estimated useful life for each major class of utility property, plant and equipment as of December 31, ~~2012~~2013 follows:

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

Capitalized software costs are classified as Property, plant and equipment and the related amortization is included in Accumulated depreciation, depletion and amortization on the Consolidated Statements of Financial Position. The Company capitalizes the costs associated with computer software it develops or obtains for use in its business. The Company amortizes capitalized software costs on a straight-line basis over the expected period of benefit, ranging from 3 to 15 years.

Capitalized software costs amortization expense was $7571 million in 2013, $68 million in 2012 and $65 million in 2011. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2013 were $65668 million ~~in 2011~~ and $~~2010~~384 million., respectively. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2012 were $~~561~~608 million and $~~295~~313 million, respectively. ~~The gross carrying amount and accumulated amortization of capitalized software costs at~~ ~~December 31, 2011~~ ~~were $623 million~~ ~~and $300 million, respectively. Amortization expense of capitalized software costs is estimated to be approximately $46 million~~ ~~annually for 2013 through 2017.~~

Gross property under capital leases was $3235 million and $5732 million at December 31, ~~2012~~2013 and ~~December 31, 2011~~2012, respectively. Accumulated amortization of property under capital leases was $321 million and $3420 million at December 31, ~~2012~~2013 and ~~December 31, 2011~~2012, respectively.

DTE Electric has joint ownership interest in two power plants, Belle River and Ludington Hydroelectric Pumped Storage. DTE Electric’s share of direct expenses of the jointly owned plants are included in Fuel, purchased power and gas and Operation and maintenance expenses in the Consolidated Statements of Operations. Ownership information of the two utility plants as of December 31, ~~2012~~2013 was as follows:

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.

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.

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

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

A reconciliation of the asset retirement obligations for ~~2012~~2013 follows:

A portion of the funds recovered through the Fermi 2 decommissioning surcharge and deposited in external trust accounts is designated for the removal of non-radioactive assets and returning the site to greenfield. This removal and greenfielding is not considered a legal liability. Therefore, it is not included in the asset retirement obligation, but is reflected as the nuclear

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

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

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

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

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

In July 2013, the COA issued a decision relating to an appeal of the October 2011 MPSC order in DTE Electric's October 2010 rate case filing. The COA found that the record of evidence in the 2010 rate case order was insufficient to support the MPSC's authorization to recover costs for the ~~pilot advanced metering infrastructure (AMI)~~AMI program and remanded this matter to the MPSC. The MPSC had approved $37an approximately $11 million of rate ~~base~~increase related to the AMI program in the ~~January 2010~~October 2011 order. DTE Electric is currently operating its AMI program pursuant to the MPSC's approval set forth in ~~its~~the October ~~20,~~ 2011 ~~order, which was not reviewed by or subject to~~order. On August 29, 2013, the MPSC reopened the 2010 electric rate case for the limited purpose of addressing the COA's ~~April 10, 2012 decision. On November 28, 2012,~~ opinion on AMI. The Company is unable to predict the outcome of this matter or the timing of its resolution.

The approval excludes the request to defer the difference between DTE Electric's tariff rates and any transitional rates that might be approved by the MPSC ~~issued an order approving the Company's accounting application. As described~~ in the future. The MPSC will address proposed rates and recovery matters in a future contested proceeding. As the accounting order did not provide a regulatory recovery mechanism, a regulatory asset will not be recognized until a regulatory recovery mechanism is put into place and the recovery of the regulatory asset becomes probable.

On July 19, 2013, DTE Electric filed its TRM application proposing a transitional tariff option for certain former PLD customers and a modified line extension provision. The application also proposed a recovery mechanism for the deferred net incremental revenue requirement described above. The application further discussed that DTE Electric will ~~amortize the new regulatory liability to income, at a monthly rate~~be requesting recovery, in subsequent PSCR cases, of ~~approximately $10.6 million, beginning January 2014. It is currently anticipated that with this accounting treatment, along with other cost saving measures,~~PLD transmission delivery service costs incurred while DTE Electric ~~will~~is temporarily relying upon PLD to operate and maintain PLD's system during the system conversion period. If the MPSC determines that the transmission costs are not ~~need to increase base rates until 2015. If DTE Electric's base rates are increased prior to January 1, 2015,~~recoverable in the PSCR, the Company ~~will cease amortization and refund to customers the remaining unamortized balance~~requested recovery as part of the ~~new regulatory liability.~~TRM.

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

In May ~~2012,~~2013, DTE Electric and DTE Gas ~~both~~ filed separate applications for approval of their respective reconciliations

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. AnOn February 28, 2013, the MPSC ~~order is expected in~~approved a settlement agreement and authorized a $44 million net surcharge to recover the ~~first quarter of~~costs over a three-month period beginning April 1, 2013.

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

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

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

In March ~~2012,~~2013, DTE Gas filed an application with the MPSC for approval of its UETM reconciliation for ~~2011~~2012 requesting authority to refund approximately $~~7 million~~, ~~consisting of a $19 million~~ ~~over-recovery related to 2011 uncollectible expense, partially offset by $12 million~~ ~~related to the 2010 UETM under-recovery. In~~$20 million. On September ~~2012,~~10, 2013, the MPSC approved a settlement agreement approving the ~~net~~requested 2012 UETM refund ~~of $7 million~~ ~~and the implementation of credits and surcharges~~ over a ~~twelve-month~~twelve-month period beginning in ~~November 2012. The December 2012 order in DTE Gas' rate case requires the UETM be terminated effective November 1, 2012 and the reconciliation to be filed by March 31,~~October 2013. ~~DTE Gas accrued a refund obligation of approximately $20 million~~ ~~for the 2012 over-recovery.~~

The Company files a consolidated federal income tax return. Total income tax expense varied from the statutory federal income tax rate for the following reasons:

Components of income tax expense were as follows:

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:

Production tax credits earned in prior years but not utilized totaled $~~254~~266 million and are carried forward indefinitely as alternative minimum tax credits. The majority of the production tax credits earned in prior years but not utilized, including all of those from our synfuel projects, were generated from projects that had received a private letter ruling (PLR) from the Internal Revenue Service (IRS). These PLRs provide assurance as to the appropriateness of using these credits to offset taxable income, however, these tax credits are subject to IRS audit and adjustment.

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

The Company has state deferred tax assets related to net operating loss and credit carry-forwards of $3743 million and $3037 million at December 31, ~~2012~~2013 and ~~2011~~2012, respectively. The state net operating loss and credit carry-forwards expire from ~~2013~~2014 through ~~2031.~~2033. The Company has recorded valuation allowances at December 31, ~~2012~~2013 and ~~2011~~2012 of approximately $3337 million and $2733 million, respectively, with respect to these deferred tax assets. In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.

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

The Company had $32 million and $43 million of unrecognized tax benefits at December 31, ~~2012~~2013 and at ~~December 31, 2011~~,2012, respectively, that, if recognized, would favorably impact its effective tax rate. During the next twelve months, it is reasonably possible that the ~~Company~~statute of limitation will ~~settle certain federal and~~expire on various state tax ~~examinations and audits.~~returns. As a result, the

The Company recognizes interest and penalties pertaining to income taxes in Interest expense and Other expenses, respectively, on its Consolidated Statements of Operations. Accrued interest pertaining to income taxes totaled $1 million and $21 million at December 31, ~~2012~~2013 and ~~December 31, 2011~~,2012, respectively. The Company had no accrued penalties pertaining to income taxes. The Company recognized interest expense (income) related to income taxes of a nominal amount, $(1) million, and $(2) million in 2013, 2012 and $~~1 million~~ ~~in 2012,~~ 2011, ~~and 2010,~~ respectively.

In ~~2012,~~2013, the Company settled a federal tax audit for the ~~2009 and 2010~~2011 tax ~~years,~~year, which resulted in the recognition of $~~30 million~~a nominal amount of unrecognized tax benefits. The Company's federal income tax returns for ~~2011~~2012 and subsequent years remain subject to examination by the IRS. The Company's Michigan Business Tax and Michigan Corporate Income Tax returns for the year 2008 and subsequent years remain subject to examination by the State of Michigan. The Company also files tax returns in numerous state and local jurisdictions with varying statutes of limitation.

~~On June 18,~~During 2013 and 2012, the Company contributed $~~80 million~~the following amounts of DTE Energy ~~common~~Common stock to the DTE Energy Company Affiliates Employee Benefit Plans Master ~~Trust.~~ Trust:

The ~~common stock was~~shares for all the contributions were valued ~~using~~at the closing market price of DTE Energy common stock on ~~that date~~the contribution dates in accordance with fair value measurement and accounting requirements.

Under the DTE Energy Company Long-Term Incentive Plan, the Company grants non-vested stock awards to key employees, primarily management. As a result of a stock award, a settlement of an award of performance shares, or by exercise of a participant’s stock option, the Company may deliver common stock from the Company’s authorized but unissued common stock and/or from outstanding common stock acquired by or on behalf of the Company in the name of the participant.

Certain of the Company’s credit facilities contain a provision requiring the Company to maintain a total funded debt to capitalization ratio, as defined in the agreements, of no more than 0.65 to 1,, which has the effect of limiting the amount of dividends the Company can pay in order to maintain compliance with this provision. See Note 17 for a definition of this ratio. The effect of this provision was to restrict the payment of approximately $~~239~~166 million at December 31, ~~2012~~2013 of total retained earnings of approximately $4 billion. There are no other effective limitations with respect to the Company’s ability to pay dividends.

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

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

In ~~2012, the Company issued~~2013, the following ~~long-term debt:~~debt was issued:

In 2013, the following debt was redeemed:

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

Substantially all of the net utility properties of DTE Electric and DTE Gas are subject to the lien of mortgages. Should DTE Electric or DTE Gas fail to timely pay their indebtedness under these mortgages, such failure may create cross defaults in the indebtedness of DTE Energy.

As of December 31, ~~2012~~2013, the amount of authorized and unissued stock is as follows:

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $7353 million which are used for various corporate purposes.

The weighted average interest rate for short-term borrowings was ~~0.4%~~0.2% and ~~0.5%~~0.4% at December 31, ~~2012~~2013 and ~~2011~~2012, respectively.

Lessee — The Company leases various assets under capital and operating leases, including coal railcars, office buildings, a warehouse, computers, vehicles and other equipment. The ~~Company has also entered into various power purchase agreements which meet the criteria of capital and operating leases. The~~ lease arrangements expire at various dates through ~~2032.~~ 2046.

Future minimum lease payments under non-cancelable leases at December 31, ~~2012~~2013 were:

Rental expense for operating leases was $34 million in 2013, $36 million in 2012, and $40 million in ~~2011, and $32 million~~ ~~in 2010. Contingent rental payments of $27 million~~ ~~were incurred in 2012 related to power purchase agreements. The contingent payments are based upon delivery of energy and renewable energy credits, which are dependent upon future production.~~2011.

Lessor- Capital Lease — The Company leases a portion of its pipeline system to the Vector Pipeline through a capital lease contract that expires in 2020, with renewal options extending for five years. The Company owns a 40% interest in the Vector Pipeline. In addition, the Company has an energy services agreement, a portion of which is accounted for as a capital lease. The agreement expires in 2019, with a three or five year renewal option. The components of the net investment in the capital leases at December 31, ~~2012~~2013, were as follows:

Air - DTE Electric is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze, mercury, and other air pollution. These rules have led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, mercury and other emissions. To comply with these requirements, DTE Electric has spent approximately $~~1.9~~2 billion through ~~2012.~~2013. The Company estimates DTE Electric will make capital expenditures of approximately $~~335~~280 million in ~~2013~~2014 and up to approximately $~~1.6~~1.2 billion of additional capital expenditures through ~~2020~~2021 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and other 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.~~U.S. Court of Appeals for the District of Columbia (D.C.) 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

The Mercury and Air Toxics Standard (MATS) rule, formerly known as the Electric Generating Unit Maximum Achievable Control Technology (EGU MACT) Rule, was finalized on December 16, 2011. The ~~EGU MACT~~MATS rule requires reductions of mercury and other hazardous air pollutants beginning in ~~2015. Because these rules were recently finalized~~April 2015, with a potential extension to April 2016. DTE Electric has requested and been granted compliance date extensions for some units to April 2016. DTE Electric has tested technologies to ~~comply are still being tested, it is~~determine technological and economic feasibility as MATS compliance alternatives to Flue Gas Desulfurization (FGD) systems. Implementation of Dry Sorbent Injection (DSI) and Activated Carbon Injection (ACI) technologies will allow several units that would not ~~possible~~have been economical for FGD installations to ~~quantify the impact of these rulemakings.~~continue operation in compliance with MATS.

In July 2009, DTE Energy received a Notice of Violation/Finding of Violation (NOV/FOV) from the EPA alleging, among other things, that five DTE Electric power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and operating permit requirements under the Clean Air Act. ~~An additional~~In June 2010, the EPA issued a NOV/FOV ~~was received in June 2010~~making similar allegations related to a ~~recent~~ project and outage at Unit 2 of the Monroe Power Plant. In March 2013, DTE Energy received a supplemental NOV from the EPA relating to the July 2009 NOV/FOV. The supplemental NOV alleged additional violations relating to the New Source Review provisions under the Clean Air Act, among other things.

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

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

On ~~November 9, 2012,~~March 13, 2013, the Sierra Club filed ~~a Notice of Intent to Sue~~suit against DTE Energy and DTE Electric ~~for Violations~~alleging violations of the Clean Air Act at ~~the St. Clair, Belle River, and Trenton Channel~~four of DTE Electric's coal-fired power plants. The ~~notice cites~~plaintiffs allege ~~1,330~~1,4996 ~~total exceedances~~-minute periods of excess opacity of air emissions from 2007-2012 at those facilities. The suit asks that 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~~court enjoin DTE Energy and DTE Electric from operating the power plants except in complete compliance with applicable laws and permit requirements, pay civil penalties, conduct beneficial environmental mitigation projects, pay attorney fees and require the installation of any necessary pollution controls or to convert and/or operate the plants' boilers on natural gas to avoid additional violations and to off-set historic unlawful emissions. In December 2013, a U.S. District Court judge issued an order dismissing, without prejudice, the plaintiff's complaint allowing them to file an amended complaint by January 17, 2014. The order dismissing the complaint resulted from a considerable number of plaintiff's claims being time barred based on the statute of limitations. On January 17, 2014, the plaintiffs filed an amended complaint for the period January 13, 2008 - June 30, 2012, reducing the total number of 6-minute periods from 1,499 to 1,139. DTE Energy and DTE Electric plan to file an answer to the ~~MDEQ.~~ No ~~enforcement actions~~amended complaint in the first quarter of 2014. The resolution of this matter is not expected to have ~~been initiated by~~a material effect on 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.~~Company's operations or financial statements.

Water - In response to an EPA regulation, DTE Electric would be required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of completed studies and expected future studies, DTE Electric may be required to install technologies to reduce the impacts of the water intake structures. The initial rule published in 2004 was subsequently remanded and a proposed rule published in 2011. The proposed rule specified an eight year compliance timeline. ~~In July 2012,~~Final action on this rule has been delayed and is expected in 2014. Depending on final regulations, its requirements may require modifications to some existing intake structures and could impact the rates we charge our customers. It is not possible to quantify the impact of those expected rulemakings at this time.

On April 19, 2013, the EPA ~~announced that a notice of its final action on the rule will be issued June 2013. The EPA has also issued an information collection request to begin a review of~~proposed revised steam electric effluent ~~guidelines. It~~guidelines regulating wastewater streams from coal-fired power plants including multiple possible options for compliance. The rules are expected to be finalized by May 2014. DTE Electric has provided comments to the EPA. However, it is not possible at this time to quantify the impacts of these developing requirements.

Contaminated and Other Sites — Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. The facilities, which produced gas, have been designated as manufactured gas plant (MGP) sites. DTE Electric conducted remedial investigations at contaminated sites, including three former MGP sites. The investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites, including the area surrounding an ash landfill, electrical distribution substations, electric generating power plants, and underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is expected to be incurred over the next several years. At December 31, ~~2012~~2013 and ~~2011,~~2012, the Company had $98 million and $89 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. The Company believes that the likelihood of a materially greater liability than the accrued amount is remote based on current knowledge of the conditions at each site.

DTE Electric owns and operates athree permitted engineered ash storage ~~facility at the Monroe Power Plant~~facilities to dispose of fly ash from ~~the~~ coal fired power ~~plant.~~plants. 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.

Contaminated Sites — Gas segment, owned or previously owned, 15 former MGP sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites. Cleanup activities associated with these sites will be conducted over the next several years.

The Company’s non-utility ~~affiliates~~businesses are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants.

The Michigan coke battery facility received and responded to information requests from the EPA that resulted in the issuance of a NOV in June 2007 alleging potential maximum achievable control technologies and new source review violations. The EPA is in the process of reviewing the Company’s position of demonstrated compliance and has not initiated escalated enforcement. At this time, the Company cannot predict the impact of this issue. Furthermore, the Michigan coke battery facility is the subject of an investigation by the MDEQ concerning visible emissions readings that resulted from the Company self reporting to MDEQ questionable activities by an employee of a contractor hired by the Company to perform the visible emissions readings. At this time, the Company cannot predict the impact of this investigation.

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

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

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

DTE Electric maintains a policy for extra expenses, including replacement power costs necessitated by Fermi 2’s unavailability due to an insured event. This policy has a 12-week waiting period and provides an aggregate $490 million of coverage over a 3three-year period.

DTE Electric has $500 million in primary coverage and $2.25 billion of excess coverage for stabilization, decontamination, debris removal, repair and/or replacement of property and decommissioning. The combined coverage limit for total property damage is $2.75 billion, subject to a $1 million deductible. As of April 1, 2013, the total limit for property damage for non-nuclear events is $1.8 billion and an aggregate of $327 million of coverage for extra expenses over a two-year period.

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

Under the NEIL policies, DTE Electric could be liable for maximum assessments of up to approximately $3134 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.

As ~~of January 1, 2013, as~~ required by federal law, DTE Electric maintains $375 million of public liability insurance for a nuclear incident. For liabilities arising from a terrorist act outside the scope of TRIA, the policy is subject to one industry aggregate limit of $300 million. Further, under the Price-Anderson Amendments Act of 2005, deferred premium charges up to $~~117.5~~127.3 million could be levied against each licensed nuclear facility, but not more than $~~17.5~~19 million per year per facility.

In accordance with the Federal Nuclear Waste Policy Act of 1982, DTE Electric has a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. DTE Electric is obligated to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold. The fee is a component of nuclear fuel expense. The DOE's Yucca Mountain Nuclear Waste Repository program for the acceptance and disposal of spent nuclear fuel was terminated in 2011. DTE Electric currently employs a spent nuclear fuel storage strategy utilizing a fuel pool. The Company continues to develop its on-site dry cask storage facility and has ~~postponed~~scheduled the initial offload from the spent fuel pool ~~until~~in 2014. The dry cask storage facility is expected to provide sufficient spent fuel storage capability for the life of the plant as defined by the original operating license.

DTE Electric is a party in the litigation against the DOE for both past and future costs associated with the DOE's failure to accept spent nuclear fuel under the timetable set forth in the Federal Nuclear Waste Policy Act of 1982. In July 2012, DTE Electric executed a settlement agreement with the federal government for costs associated with the DOE's delay in acceptance of spent nuclear fuel from Fermi 2 for permanent storage. The settlement provided for a payment of approximately $48 million, received in August 2012, for delay-related costs experienced by DTE Electric through 2010, and a claims process for submittal of delay-related costs from 2011 through 2013. DTE Electric has begun the claims process and claims are being settled on a timely basis. The settlement proceeds reduced the cost of the dry cask storage facility assets. In January 2014, the settlement agreement was extended through 2016. The federal government continues to maintain its legal obligation to accept spent nuclear fuel from Fermi 2 for permanent storage. Issues relating to long-term waste disposal policy and to the disposition of funds contributed by DTE Electric ratepayers to the federal waste fund await future governmental action.

In certain limited circumstances, the Company enters into contractual guarantees. The Company may guarantee another entity’s obligation in the event it fails to perform. The Company may provide guarantees in certain indemnification agreements. Finally, the Company may provide indirect guarantees for the indebtedness of others. The Company’s guarantees are not individually material with maximum potential payments totaling $5060 million at December 31, ~~2012.~~2013. Payment under these guarantees is considered remote.

The Company is periodically required to obtain performance surety bonds in support of obligations to various governmental entities and other companies in connection with its operations. As of December 31, ~~2012,~~2013, the Company had approximately $41 million of performance bonds outstanding. In the event that such bonds are called for nonperformance, the Company would be obligated to reimburse the issuer of the performance bond. The Company is released from the performance bonds as the contractual performance is completed and does not believe that a material amount of any currently outstanding performance bonds will be called.

There are several bargaining units for the Company's approximately 4,900 represented employees. The majority of the represented employees are under contracts that expire in 2016 and 2017.

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

The Company also estimates that ~~2013~~2014 capital expenditures will be approximately $~~2.2~~2.3 billion. The Company has made certain commitments in connection with expected capital expenditures.

The Company purchases and sells electricity, natural gas, coal, coke and other energy products from and to governmental entities and numerous companies operating in the steel, automotive, energy, retail, financial and other industries. Certain of its customers have filed for bankruptcy protection under ~~Chapter 11 of~~ the U.S. Bankruptcy Code. The Company regularly reviews contingent matters relating to these customers and its purchase and sale contracts and records provisions for amounts considered at risk of probable loss. The Company believes its accrued amounts are adequate for probable loss.

The ~~final resolution~~Company's utilities provide services to the city of ~~these matters may~~Detroit, Michigan (Detroit). Detroit filed for Chapter 9 bankruptcy protection on July 18, 2013. The Company had pre-petition accounts receivable of approximately $20 million outstanding as of the bankruptcy filing date. Detroit has been paying amounts owed in a timely manner and its accounts are substantially current. The Company does not expect Detroit's bankruptcy filing to have a material ~~effect~~impact on its ~~consolidated~~ financial ~~statements.~~results.

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

See Notes 4 and 11 for a discussion of contingencies related to derivatives and regulatory matters.

The Company has qualified defined benefit retirement plans for eligible represented and non-represented employees. The plans are noncontributory and cover ~~substantially all~~most employees. The plans provide traditional retirement benefits based on the employees’ years of benefit service, average final compensation and age at retirement. In addition, certain represented and non-represented employees are covered under cash balance provisions that determine benefits on annual employer contributions and interest credits. The Company also maintains supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees. These plans provide for benefits that supplement those provided by DTE Energy’s other retirement plans.

Effective January 1, 2012 for non-represented employees, and in June 2011 and March 2013 for the majority of represented employees, the Company discontinued offering ~~future non-represented employees~~ a ~~cash balance~~defined benefit retirement ~~plan benefit.~~plan. In its place, the Company will annually contribute an amount equivalent to ~~four percent~~4% (8% for certain DTE Gas represented employees) of an employee's eligible pay to the employee's defined contribution retirement savings plan.

The Company’s policy is to fund pension costs by contributing amounts consistent with the provisions of the Pension Protection Act of 2006 ~~provisions~~ and additional amounts when it deems appropriate. The Company contributed $~~229~~277 million to its qualified pension plans in ~~2012.~~2013. At the discretion of management, and depending upon financial market conditions, we anticipate making up to a $~~315~~345 million ~~contribution~~in contributions to the pension plans in ~~2013.~~2014.

Net pension cost includes the following components:

The following table reconciles the obligations, assets and funded status of the plans as well as the amounts recognized as prepaid pension cost or pension liability in the Consolidated Statements of Financial Position at December 31:

At December 31, ~~2012,~~2013, 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:

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

The Company employs a formal process in determining the long-term rate of return for various asset classes. Management reviews historic financial market risks and returns and long-term historic relationships between the asset classes of equities, fixed income and other assets, consistent with the widely accepted capital market principle that asset classes with higher volatility generate a greater return over the long-term. Current market factors such as inflation, interest rates, asset class risks and asset class returns are evaluated and considered before long-term capital market assumptions are determined. The long-term portfolio return is also established employing a consistent formal process, with due consideration of diversification, active investment management and rebalancing. Peer data is reviewed to check for reasonableness. As a result of this process, the Company has long-term rate of return assumptions for its pension plans of 7.75% and other postretirement benefit plans of 8.00%, for 2014. The Company believes these rates are a reasonable assumption for the long-term rate of return on its plan assets for 2014 given its investment strategy.

The Company employs a total return investment approach whereby a mix of equities, fixed income and other investments are used to maximize the long-term return on plan assets consistent with prudent levels of risk, with consideration given to the liquidity needs of the plan. Risk tolerance is established through consideration of future plan cash flows, plan funded status, and corporate financial considerations. The investment portfolio contains a diversified blend of equity, fixed income and other investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, growth and value ~~investment styles,~~stocks, and large and small market capitalizations. Fixed income securities generally include ~~corporate~~market and long duration bonds of companies from diversified industries, mortgage-backed securities, non-US securities, bank loans and U.S. Treasuries. Other assets such as private ~~equity~~markets and hedge funds are used to enhance long-term returns while improving portfolio diversification. Derivatives may be utilized in a risk controlled manner, to potentially increase the portfolio beyond the market value of invested assets and/or reduce portfolio investment risk. Investment risk is measured and monitored on an ongoing basis through annual liability measurements, periodic asset/liability studies, and quarterly investment portfolio reviews.

Target allocations for pension plan assets as of December 31, ~~2012~~2013 are listed below:

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 and are valued based on ~~underlying securities, using quoted prices in actively traded markets.~~stated net asset values (NAV). 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~~trustee monitors prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustees challenge an assigned price and determine that another price source is considered to be preferable. DTE Energy has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, DTE Energy selectively corroborates the fair values of securities by comparison of market-based price sources.

The Company provides certain other postretirement health care and life insurance benefits for employees who are eligible for these benefits. The Company’s policy is to fund certain trusts to meet its other postretirement benefit obligations. Separate qualified Voluntary Employees Beneficiary Association (VEBA) and 401(h) trusts exist for represented and non-represented employees. The Company contributed $~~140~~$264 million to its other postretirement medical and life insurance benefit plans during ~~2012.~~2013. At the discretion of management, we anticipate making up to $145 million of contributions to the VEBA trusts in 2014.

99

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

Net other postretirement cost includes the following components:

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

At December 31, ~~2012,~~2013, 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:

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

A one percentage point increase in health care cost trend rates would have increased the total service cost and interest cost components of benefit costs by $289 million in 2013 and increased the accumulated benefit obligation by $~~279~~124 million at December 31, ~~2012.~~2013. A one percentage point decrease in the health care cost trend rates would have decreased the total service and interest cost components of benefit costs by $198 million in 2013 and would have decreased the accumulated benefit obligation by $~~264~~108 million at December 31, ~~2012.~~2013.

The process used in determining the long-term rate of return for assets and the investment approach for the Company’s other postretirement benefits plans is similar to those previously described for its pension plans.

Target allocations for other postretirement benefit plan assets as of December 31, ~~2012~~2013 are listed below:

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

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

In March 2013, the Company reached agreements on new four-year labor contracts with certain represented employees under several bargaining units. As a term of the agreements, the Company replaced sponsored retiree medical, prescription drug and dental coverage for future Medicare eligible retirees with a Retiree Health Care Allowance (RHCA) account of $3,250 per year. The modification in retiree health coverage will reduce future other postretirement benefit costs.

Based on the impact of such benefit cost savings on the consolidated financial statements, the Company re-measured its retiree health plan as of March 31, 2013. In performing the re-measurement, the Company updated its significant actuarial assumptions, including an adjustment to the discount rate from 4.15% at December 31, 2012 to 4.30% at March 31, 2013. Plan assets were also updated to reflect fair value as of the re-measurement date. Beginning April 2013, net other postretirement benefit costs were recorded based on the updated actuarial assumptions and ~~2011.~~benefit changes resulting from the new labor contracts.

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 other postretirement benefit costs by $1 million in 2013, $6 million in 2012 and $6 million in ~~2011 and $7 million~~ ~~in 2010.~~2011.

DTE Gas maintains a Grantor Trust to fund other postretirement benefit obligations that invests in life insurance contracts and income securities. Employees and retirees have no right, title or interest in the assets of the Grantor Trust, and DTE Gas can revoke the trust subject to providing the MPSC with prior notification. The Company accounts for its investment at fair value, approximately $1417 million and $14 million at December 31, 2013 and 2012, respectively, with unrealized gains and losses recorded to earnings. The Grantor Trust investment is included in Other investments on the Consolidated Statements of Financial Position.

~~Table~~The Company also sponsors defined contribution retirement savings plans. Participation in one of ~~Contents~~

~~DTE Energy Company~~

~~Notes~~these plans is available to ~~Consolidated Financial Statements — (Continued)~~substantially all represented and non-represented employees. The Company matches employee contributions up to certain predefined limits based upon eligible compensation, the employee’s contribution rate and, in some cases, years of credited service. The cost of these plans was $41 million, $37 million, and $35 million in each of the years 2013, 2012, and 2011, respectively.

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

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

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

Options are exercisable according to the terms of the individual stock option award agreements and expire 10 years after the date of the grant. The option exercise price equals the fair value of the stock on the date that the option was granted. Stock options vest ratably over a 3-year period.

Stock option activity was as follows:

As of December 31, ~~2012~~2013, the weighted average remaining contractual life for the exercisable shares is ~~4.30~~3.83 years. As of December 31, ~~2012~~2013, all options were vested. During 2013, 200,844 ~~options were non-vested. During~~ ~~2012~~, ~~332,026~~ options vested.

There were no options granted during 2013, 2012 or 2011. The intrinsic value of options exercised for the years ended December 31, ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011 was $12 million, $25 million, $~~20 million~~, and $920 million, respectively. Total option expense recognized during ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011 waszero, $0.7 million, and $2 ~~million~~ ~~and $~~4 million, respectively.

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

Stock awards granted under the plan are restricted for varying periods, generally for three years. Participants have all rights of a shareholder with respect to a stock award, including the right to receive dividends and vote the shares. Prior to vesting in stock awards, the participant: (i) may not sell, transfer, pledge, exchange or otherwise dispose of shares; (ii) shall not retain custody of the share certificates; and (iii) will deliver to the Company a stock power with respect to each stock award upon request.

The stock awards are recorded at cost that approximates fair value on the date of grant. The cost is amortized to compensation expense over the vesting period.

Stock award activity for the ~~periods~~years ended December 31 was:

The following table summarizes the Company’s stock awards activity for the period ended December 31, ~~2012~~2013:

Performance shares awarded under the plan are for a specified number of shares of common stock that entitle the holder to receive a cash payment, shares of common stock or a combination thereof. The final value of the award is determined by the achievement of certain performance objectives and market conditions. The awards vest at the end of a specified period, usually three years. The Company accounts for performance share awards by accruing compensation expense over the vesting period based on: (i) the number of shares expected to be paid which is based on the probable achievement of performance objectives; and (ii) the closing stock price market value. The settlement of the award is based on the closing price at the settlement date.

The Company recorded compensation expense for performance share awards as follows:

During the vesting period, the recipient of a performance share award has no shareholder rights. ~~Performance shares granted are entitled to dividend equivalent payments before the performance shares granted are earned and vested.~~ During the period beginning on the date the performance shares are awarded and ending on the certification date of the performance objectives, the number of performance shares awarded will be increased, assuming full dividend reinvestment at the fair market value on the dividend payment date. The cumulative number of performance shares will be adjusted to determine the final payment ~~bases~~based on the performance objectives achieved. Performance share awards are nontransferable and are subject to risk of forfeiture.

The following table summarizes the Company’s performance share activity for the period ended December 31, ~~2012~~2013:

As of December 31, ~~2012~~2013, there was $5855 million of total unrecognized compensation cost related to non-vested ~~stock incentive plan~~stock-based compensation arrangements. That cost is expected to be recognized over a weighted-average period of ~~1.37~~0.93 years.

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

The federal income tax provisions or benefits of DTE Energy’s subsidiaries are determined on an individual company basis and recognize the tax benefit of production tax credits and net operating losses if applicable. The state and local income tax provisions of the utility subsidiaries is determined on an individual company basis and recognizes the tax benefit of various

Inter-segment billing for goods and services exchanged between segments is based upon tariffed or market-based prices of the provider and primarily consists of the sale of reduced emissions fuel, power sales and natural gas sales ~~and coal transportation services~~ in the following segments:

Financial data of the business segments follows:

Quarterly earnings per share may not equal full year totals, since quarterly computations are based on weighted average common shares outstanding during each quarter.

None.

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.

Information required by Part III (Items 10, 11, 12, 13 and 14) of this Form 10-K is incorporated by reference from DTE Energy’s definitive Proxy Statement for its ~~2013~~2014 Annual Meeting of Shareholders to be held May ~~2, 2013.~~1, 2014. The Proxy Statement will be filed with the Securities and Exchange Commission, pursuant to Regulation 14A, not later than 120 days after the end of our fiscal year covered by this report on Form 10-K, all of which information is hereby incorporated by reference in, and made part of, this Form 10-K.



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~~2013
¨		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



Michigan		38-3217752
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
One Energy Plaza, Detroit, Michigan		48226-1279
(Address of principal executive offices)		(Zip Code)



Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, without par value		New York Stock Exchange
2011 Series I 6.5% Junior Subordinated Debentures due 2061		New York Stock Exchange
2012 Series C 5.25% Junior Subordinated Debentures due 2062		New York Stock Exchange



Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o



		Page
Definitions		1
Forward-Looking Statements		3
PART I
Items 1. & 2.	Business and Properties	4
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	2120
Item 3.	Legal Proceedings	2120
Item 4.	Mine Safety Disclosures	21
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	22
Item 6.	Selected Financial Data	2524
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	4543
Item 8.	Financial Statements and Supplementary Data	4846
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	~~111~~112
Item 9A.	Controls and Procedures	~~111~~112
Item 9B.	Other Information	~~111~~112
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	~~111~~112
Item 11.	Executive Compensation	~~111~~112
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~111~~112
Item 13.	Certain Relationships and Related Transactions, and Director Independence	~~111~~112
Item 14.	Principal Accountant Fees and Services	~~111~~112
PART IV
Item 15.	Exhibits and Financial Statement ~~Schedules~~Schedule	~~111~~113
Signatures		~~120~~122
~~EX-4.279~~EX-4.282
~~EX-10.81~~EX-4.283
~~EX-12.52~~EX-12.56
~~EX-21.8~~EX-21.9
~~EX-23.26~~EX-23.27
~~EX-31.79~~EX-31.87
~~EX-31.80~~EX-31.88
~~EX-32.79~~EX-32.87
~~EX-32.80~~EX-32.88
~~EX-101 INSTANCE DOCUMENT~~EX-99.55
~~EX-101 SCHEMA DOCUMENT~~EX-99.56
~~EX-101 CALCULATION LINKBASE DOCUMENT~~101.INS XBRL Instance Document
~~EX-101 LABELS LINKBASE DOCUMENT~~101.SCH XBRL Taxonomy Extension Schema
~~EX-101 PRESENTATION LINKBASE DOCUMENT~~101.CAL XBRL Taxonomy Extension Calculation Linkbase
~~EX-101 DEFINITION LINKBASE DOCUMENT~~101.DEF XBRL Taxonomy Extension Definition Linkbase
101.LAB XBRL Taxonomy Extension Label Linkbase
101.PRE XBRL Taxonomy Extension Presentation Linkbase



	ASC	Accounting Standards Codification

	ASU	Accounting Standards Update

	~~CIM~~CFTC	~~A Choice Incentive Mechanism authorized by the MPSC that allows DTE Electric to recover or refund non-fuel revenues lost or gained as a result of fluctuations in electric Customer Choice sales.~~U.S. Commodity Futures Trading Commission

	Citizens	Citizens Fuel Gas Company, which distributes natural gas in Adrian, Michigan

	Company	DTE Energy Company and any subsidiary companies

	Customer Choice	Michigan legislation giving customers the option to choose alternative suppliers for electricity and ~~gas.~~gas

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

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

	DTE Gas	DTE Gas Company (an indirect wholly owned subsidiary of DTE Energy) and subsidiary companies. Formerly known as Michigan Consolidated Gas Company.

	EPA	United States Environmental Protection Agency

	FASB	Financial Accounting Standards Board

	FERC	Federal Energy Regulatory Commission

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

	GCR	A Gas Cost Recovery mechanism authorized by the MPSC that allows DTE Gas to recover through rates its natural gas costs.

	MCIT	Michigan Corporate Income Tax

	MDEQ	Michigan Department of Environmental Quality

	MISO	~~Midwest~~Midcontinent Independent System Operator, ~~is an Independent System Operator and the Regional Transmission Organization serving the Midwest United States and Manitoba, Canada.~~Inc.

	MPSC	Michigan Public Service Commission

	Non-utility	An entity that is not a public utility. Its conditions of service, prices of goods and services and other operating related matters are not directly regulated by the MPSC.

	NRC	United States Nuclear Regulatory Commission

	Production tax credits	Tax credits as authorized under Sections 45K and 45 of the Internal Revenue Code that are designed to stimulate investment in and development of alternate fuel sources. The amount of a production tax credit can vary each year as determined by the Internal Revenue Service.




	PSCR	A Power Supply Cost Recovery mechanism authorized by the MPSC that allows DTE Electric to recover through rates its fuel, fuel-related and purchased power costs.

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

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

	Subsidiaries	The direct and indirect subsidiaries of DTE Energy Company

	VIE	Variable Interest Entity



	Units of Measurement

	Bcf	Billion cubic feet of gas

	Bcfe	Conversion metric using a standard ratio of one barrel of oil and/or natural gas liquids to 6 Mcf of natural gas equivalents.

	BTU	Heat value (energy content) of fuel

	dth/d	Decatherms per day

	kWh	Kilowatthour of electricity

	Mcf	Thousand cubic feet of gas

	MMcf	Million cubic feet of gas

	MW	Megawatt of electricity

	MWh	Megawatthour of electricity


	2012		2011		2010		2013		2012		2011
	(In millions)						(In millions)
Residential	$	2,354	$	2,182	$	2,052	$	2,351	$	2,354	$	2,182
Commercial	1,898		1,704		1,629		1,883		1,898		1,704
Industrial	784		692		688		799		784		692
Other	152		458		479		45		152		458
Subtotal	5,188		5,036		4,848		5,078		5,188		5,036
Interconnection sales (a)	105		118		145		121		105		118
Total Revenue	$	5,293	$	5,154	$	4,993	$	5,199	$	5,293	$	5,154


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


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


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


(c)	The Monroe generating plant provided ~~37%~~38% of DTE Electric’s total ~~2012~~2013 power generation.


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


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


	2012		2011		2010		2013		2012		2011
	(In millions)						(In millions)
Gas sales	$	957	$	1,150	$	1,281	$	1,093	$	957	$	1,150
End user transportation	198		194		185		212		198		194
Intermediate transportation	58		58		69		59		58		58
Storage and other	102		103		113		110		102		103
Total Revenue	$	1,315	$	1,505	$	1,648	$	1,474	$	1,315	$	1,505


	Availability (MMcf/d)	Contract Expiration	Availability (MMcf/d)	Contract Expiration
Great Lakes Gas Transmission L.P.	80	2013	30	2014
Viking Gas Transmission Company	51	2013	21	2017
Vector Pipeline L.P.	50	2015	50	2015
ANR Pipeline Company	195	2017	224	2028
Panhandle Eastern Pipeline Company	75	2029	75	2029



Facility	Location	Service Type
Steel ~~Steel Industry Fuel,~~ and Petroleum Coke
Pulverized Coal Operations	MI ~~& MD~~	Pulverized Coal
Coke Production	MI, PA & IN	Metallurgical Coke ~~Supply/Steel Industry Fuels~~Supply
Other Investment in Coke Production and Petroleum Coke	IN & MS	Metallurgical Coke ~~Supply/Steel Industry Fuels,~~Supply and Pulverized Petroleum Coke

On-Site Energy
Automotive	Various sites in	Electric Distribution, Chilled Water,
	MI, IN, OH & NY	Waste Water, Steam, Cooling Tower Water, Reverse Osmosis Water, Compressed Air, Mist and Dust Collectors
Airports	MI & PA	Electricity, Hot and Chilled Water
Chemical Manufacturing	IL, KY & OH	Electricity, Steam, Natural Gas, Compressed Air and Wastewater
Consumer Manufacturing	~~KY &~~ OH	Electricity, Steam, Hot and Chilled Water, Sewer, Compressed Air
Business Park	FL, ~~NY,~~ OH & PA	Electricity, Steam, Hot and Chilled Water, Compressed Air
Hospital	CA	Electricity, Steam and Chilled Water

Wholesale Power and Renewables
Pulp and Paper	AL	Electric Generation and Steam
Renewables	CA, MN & WI	Electric Generation
Landfill Gas Recovery	Various U.S. sites	Electric Generation and Landfill Gas

~~Other Industries~~
REF	MI, OK, IL & OH	REF Supply


						Dividends Paid per Share							Dividends Paid per Share
Year	Quarter	High		Low		Dividends Paid per Share		Quarter	High		Low		Dividends Paid per Share
2013
								First	$	68.38	$	60.33	$	0.6200
								Second	$	73.32	$	63.38	$	0.6550
								Third	$	71.77	$	64.71	$	0.6550
								Fourth	$	70.64	$	64.45	$	0.6550
2012
	First	$	56.52	$	52.46	$	0.5875	First	$	56.52	$	52.46	$	0.5875
	Second	$	60.25	$	53.70	$	0.5875	Second	$	60.25	$	53.70	$	0.5875
	Third	$	62.54	$	58.06	$	0.6200	Third	$	62.54	$	58.06	$	0.6200
	Fourth	$	62.49	$	58.20	$	0.6200	Fourth	$	62.49	$	58.20	$	0.6200
2011
	First	$	49.36	$	45.17	$	0.5600
	Second	$	52.78	$	48.06	$	0.5875
	Third	$	52.00	$	43.22	$	0.5875
	Fourth	$	55.28	$	47.03	$	0.5875



Property Classification	% Owned		Description	Location
Pipelines
Vector Pipeline	40	%	348-mile pipeline ~~with 1,300 MMcf per day capacity~~connecting Chicago, Michigan and Ontario market centers	IL, IN, MI & Ontario
Millennium Pipeline	26	%	182-mile pipeline ~~with 525 MMcf per day capacity~~serving markets in the Northeast	NY
Bluestone Lateral	100	%	44-mile pipeline ~~designed~~delivering Marcellus Shale gas to ~~flow over 275 MMcf per day~~Millennium Pipeline and Tennessee Pipeline	PA & NY
Susquehanna gathering system	100	%	Gathering system ~~to transport~~delivering Southwestern Energy's Marcellus Shale gas production to Bluestone Lateral	PA
Michigan gathering systems	100	%	Gathers production gas in northern Michigan	MI
Storage
Washington 10	100	%	75 Bcf of storage capacity	MI
Washington 28	50	%	16 Bcf of storage capacity	MI


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



	Number of Securities to be Issued Upon Exercise of Outstanding Options	Weighted-Average Exercise Price of Outstanding Options	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans
Plans approved by shareholders	1,192,670	$41.86	3,784,351



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


(a)	Represents shares of common stock purchased on the open market to provide shares to participants under various employee compensation and incentive programs. These purchases were not made pursuant to a publicly announced plan or program. Also includes shares of common stock withheld to satisfy income tax obligations upon the vesting of restricted stock.


	Annual Return Percentage Year Ended December 31						Annual Return Percentage Year Ended December 31
Company/Index	2008		2009	2010	2011	2012	2009	2010	2011	2012	2013
DTE Energy Company	(14.37	)	30.08	9.06	25.76	14.90	30.08	9.06	25.76	14.90	14.89
S&P 500 Index	(37.00	)	26.46	15.06	2.11	16.00	26.46	15.06	2.11	16.00	32.39
S&P 500 Multi-Utilities Index	(24.34	)	20.92	11.08	18.41	4.24	20.92	11.08	18.41	4.24	17.88


	Indexed Returns Year Ended December 31						Indexed Returns Year Ended December 31
	Base Period						Base Period
Company/Index	2007	2008	2009	2010	2011	2012	2008	2009	2010	2011	2012	2013
DTE Energy Company	100	85.63	111.38	121.47	152.76	175.53	100	130.08	141.86	178.40	204.99	235.52
S&P 500 Index	100	63.00	79.67	91.68	93.61	108.59	100	126.46	145.51	148.59	172.37	228.19
S&P 500 Multi-Utilities Index	100	75.66	91.49	101.63	120.33	125.43	100	120.92	134.32	159.05	165.79	195.43


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


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


(a)	Represents ~~power that is not distributed by DTE Electric.~~shares of common stock withheld to satisfy income tax obligations upon the vesting of restricted stock.


(a)	Represents shares of common stock withheld to satisfy income tax obligations upon the vesting of restricted stock.


(b)	Represents deliveries for self generators who have purchased power from alternative energy suppliers to supplement their power requirements.



(a)	Percentage by which the fair value of equity of the reporting unit would need to decline to equal its carrying value, including goodwill.
(b)	Multiple of enterprise value (sum of debt plus equity value) to earnings before interest, taxes, depreciation and amortization (EBITDA).
(c)	Discounted cash flows (DCF) incorporated ~~2013-2017~~2014-2018 projected cash flows plus a calculated terminal value.
(d)	Power and Industrial Projects excludes the Biomass ~~and Coal Services~~ reporting ~~units~~unit as ~~these units have~~this unit has no allocated goodwill.
(e)	Asset sales were assumed except for Power and Industrial Projects' reduced emissions ~~fuel~~fuels projects, which assumed stock sales.
~~(f)~~	Goodwill attributable to Unconventional Gas Production was written off in the fourth quarter of 2012 in connection with its sale. Refer to Note 7 of the Notes to Consolidated Financial Statements in Item 8 of this Report.


Source of Fair Value	2013			2014			2015			2016 and Beyond		Total Fair Value			2014			2015			2016			2017 and Beyond		Total Fair Value
	(In millions)														(In millions)
Level 1	$	26		$	9		$	(6	)	$	—	$	29		$	(3	)	$	—		$	—		$	—	$	(3	)
Level 2	(19		)	(1		)	—			—		(20		)	(42		)	(20		)	(2		)	—		(64		)
Level 3	(24		)	9			2			—		(13		)	(37		)	(2		)	2			1		(36		)
MTM before collateral adjustments	$	(17	)	$	17		$	(4	)	$	—	(4		)	$	(82	)	$	(22	)	$	—		$	1	(103		)
Collateral adjustments												—														(9		)
MTM at December 31, 2012												$	(4	)
MTM at December 31, 2013																										$	(112	)


	Credit Exposure Before Cash Collateral		Cash Collateral			Net Credit Exposure		Credit Exposure Before Cash Collateral		Cash Collateral			Net Credit Exposure
	(In millions)							(In millions)
Investment Grade (a)
A− and Greater	$	88	$	—		$	88	$	154	$	(33	)	$	121
BBB+ and BBB	259		—			259		240		—			240
BBB−	84		—			84		108		—			108
Total Investment Grade	431		—			431		502		(33		)	469
Non-investment grade (b)	2		—			2		1		—			1
Internally Rated — investment grade (c)	147		(3		)	144		173		—			173
Internally Rated — non-investment grade (d)	26		(1		)	25		21		(6		)	15
Total	$	606	$	(4	)	$	602	$	697	$	(39	)	$	658


(a)	This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s Investors Service (Moody’s) and BBB- assigned by Standard & Poor’s Rating Group (Standard & Poor’s). The five largest counterparty exposures combined for this category represented approximately ~~39 percent~~31% of the total gross credit exposure.


(c)	This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, but are considered investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately ~~16 percent~~18% of the total gross credit exposure.


	Assuming a 10% Increase in Rates						Assuming a 10% Decrease in Rates							Assuming a 10% Increase in Rates						Assuming a 10% Decrease in Rates
	As of December 31,						As of December 31,							As of December 31,						As of December 31,
Activity	2012			2011			2012			2011			Change in the Fair Value of	2013			2012			2013			2012			Change in the Fair Value of
	(In millions)													(In millions)
Coal contracts	$	2		$	(2	)	$	(1	)	$	2		Commodity contracts	$	—		$	2		$	—		$	(1	)	Commodity contracts
Gas contracts	$	(4	)	$	(9	)	$	3		$	13		Commodity contracts	$	(21	)	$	(4	)	$	21		$	3		Commodity contracts
Power contracts	$	4		$	4		$	(5	)	$	(6	)	Commodity contracts	$	14		$	4		$	(13	)	$	(5	)	Commodity contracts
Interest rate risk	$	(247	)	$	(260	)	$	260		$	276		Long-term debt	$	(291	)	$	(247	)	$	309		$	260		Long-term debt
Foreign currency exchange risk	$	—		$	—		$	—		$	—		Forward contracts	$	—		$	—		$	—		$	—		Forward contracts
Discount rates	$	—		$	—		$	—		$	—		Commodity contracts	$	—		$	—		$	—		$	—		Commodity contracts



	Page
Controls and Procedures	4947
Report of Independent Registered Public Accounting Firm	5048
Consolidated Statements of Operations	5149
Consolidated Statements of Comprehensive Income	5250
Consolidated Statements of Cash Flows	51
Consolidated Statements of Financial Position	53
~~Consolidated Statements of Cash Flows~~	5552
Consolidated Statements of Changes in Equity	5654
Notes to Consolidated Financial Statements	5755
Note 1. Organization and Basis of Presentation	5755
Note 2. Significant Accounting Policies	5957
Note 3. Fair Value	6361
Note 4. Financial and Other Derivative Instruments	6867
Note 5. Goodwill	71
Note 6. Acquisition	71
Note 7. Discontinued Operations	72
Note 8. Property, Plant and Equipment	73
Note 9. Jointly Owned Utility Plant	74
Note 10. Asset Retirement Obligations	7574
Note 11. Regulatory Matters	7675
Note 12. Income Taxes	82
Note 13. Common Stock	8485
Note 14. Earnings Per Share	86
Note 15. Long-Term Debt	87
Note 16. Preferred and Preference Securities	88
Note 17. Short-Term Credit Arrangements and Borrowings	8889
Note 18. Capital and Operating Leases	8990
Note 19. Commitments and Contingencies	9091
Note 20. Retirement Benefits and Trusteed Assets	9596
Note 21. Stock-based Compensation	~~105~~106
Note 22. ~~Supplemental Cash Flow Information~~	~~107~~
~~Note 23.~~ Segment and Related Information	108
Note ~~24.~~23. Supplementary Quarterly Financial Information (Unaudited)	~~110~~111
Financial Statement Schedule
Schedule II — Valuation and Qualifying Accounts	~~119~~121


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