10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________________________________________

Form 10-K

þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2013
¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-11607

DTE ENERGY COMPANY

(Exact name of registrant as specified in its charter)

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

313-235-4000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files).  Yes þ     No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ

On June 28, 2013, the aggregate market value of the Registrant’s voting and non-voting common equity held by non-affiliates was approximately $11.7 billion (based on the New York Stock Exchange closing price on such date). There were 177,086,236 shares of common stock outstanding at January 31, 2014.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information in DTE Energy Company’s definitive Proxy Statement for its 2014 Annual Meeting of Common Shareholders to be held May 1, 2014, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, not later than 120 days after the end of the registrant’s fiscal year covered by this report on Form 10-K, is incorporated herein by reference to Part III (Items 10, 11, 12, 13 and 14) of this Form

10-K.

DTE Energy Company

Annual Report on Form 10-K

Year Ended December 31, 2013

Table of Contents

		Page
Definitions		1
Forward-Looking Statements		3
PART I
Items 1. & 2.	Business and Properties	4
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	20
Item 3.	Legal Proceedings	20
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	24
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 8.	Financial Statements and Supplementary Data	46
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	112
Item 9A.	Controls and Procedures	112
Item 9B.	Other Information	112
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	112
Item 11.	Executive Compensation	112
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	112
Item 13.	Certain Relationships and Related Transactions, and Director Independence	112
Item 14.	Principal Accountant Fees and Services	112
PART IV
Item 15.	Exhibits and Financial Statement Schedule	113
Signatures		122
EX-4.282
EX-4.283
EX-12.56
EX-21.9
EX-23.27
EX-31.87
EX-31.88
EX-32.87
EX-32.88
EX-99.55
EX-99.56
101.INS XBRL Instance Document
101.SCH XBRL Taxonomy Extension Schema
101.CAL XBRL Taxonomy Extension Calculation Linkbase
101.DEF XBRL Taxonomy Extension Definition Linkbase
101.LAB XBRL Taxonomy Extension Label Linkbase
101.PRE XBRL Taxonomy Extension Presentation Linkbase

DEFINITIONS

ASC	Accounting Standards Codification
ASU	Accounting Standards Update
CFTC	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
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	Midcontinent Independent System Operator, 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

1

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

2

FORWARD-LOOKING STATEMENTS

Certain information presented herein includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 with respect to the financial condition, results of operations and business of DTE Energy. Words such as “anticipate,” “believe,” “expect,” “projected,” “aspiration” and “goals” signify forward-looking statements. Forward-looking statements are not guarantees of future results and conditions, but rather are subject to numerous assumptions, risks and uncertainties that may cause actual future results to be materially different from those contemplated, projected, estimated or budgeted. Many factors may impact forward-looking statements including, but not limited to, the following:

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

• the amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals or new legislation; including legislative amendments and Customer Choice programs;

• economic conditions and population changes in our geographic area resulting in changes in demand, customer conservation and thefts of electricity and natural gas;

• environmental issues, laws, regulations, and the increasing costs of remediation and compliance, including actual and potential new federal and state requirements;

• health, safety, financial, environmental and regulatory risks associated with ownership and operation of nuclear facilities;

• changes in the cost and availability of coal and other raw materials, purchased power and natural gas;

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

• volatility in the short-term natural gas storage markets impacting third-party storage revenues;

• volatility in commodity markets, deviations in weather and related risks impacting the results of our energy trading operations;

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

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

• the timing and extent of changes in interest rates;

• the level of borrowings;

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

• changes in and application of federal, state and local tax laws and their interpretations, including the Internal Revenue Code, regulations, rulings, court proceedings and audits;

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

• unplanned outages;

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

• employee relations and the impact of collective bargaining agreements;

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

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

• the effects of competition;

• changes in and application of accounting standards and financial reporting regulations;

• changes in federal or state laws and their interpretation with respect to regulation, energy policy and other business issues;

• binding arbitration, litigation and related appeals; and

• the risks discussed in our public filings with the Securities and Exchange Commission.

New factors emerge from time to time. We cannot predict what factors may arise or how such factors may cause our results to differ materially from those contained in any forward-looking statement. Any forward-looking statements speak only as of the date on which such statements are made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.

3

Part I

Items 1. and 2.  Business and Properties

General

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

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

DTE Gas is a Michigan corporation organized in 1898 and is a public utility subject to regulation by the MPSC 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; and 3) energy marketing and trading operations.

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

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

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

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

Corporate Structure

Based on the following structure, we set strategic goals, allocate resources, and evaluate performance. See Note 22 of the Notes to Consolidated Financial Statements in Item 8 of this Report for financial information by segment for the last three years.

Electric

• The Electric segment consists principally of DTE Electric, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million residential, commercial and industrial customers in southeastern Michigan.

Gas

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

4

Non-utility Operations

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

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

• Energy Trading consists of energy marketing and trading operations.

Corporate and Other

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

Refer to our Management’s Discussion and Analysis in Item 7 of this Report for an in-depth analysis of each segment’s financial results. A description of each business unit follows.

ELECTRIC

Description

Our Electric segment consists principally of DTE Electric, an electric utility engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan. 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.

Revenue by Service

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

______________________________

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

5

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

Fuel Supply and Purchased Power

Our power is generated from a variety of fuels and is supplemented with purchased power. We expect to have an adequate supply of fuel and purchased power to meet our obligation to serve customers. Our generating capability is heavily dependent upon the availability of coal. Coal is purchased from various sources in different geographic areas under agreements that vary in both pricing and terms. We expect to obtain the majority of our coal requirements through long-term contracts, with the balance to be obtained through short-term agreements and spot purchases. We have long-term and short-term contracts for the purchase of approximately 29.4 million tons of low-sulfur western coal to be delivered from 2014 through 2016 and approximately 1.6 million tons of Appalachian coal to be delivered in 2014. All of these contracts have pricing schedules. We have approximately 92% of our 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 2018. All of our expected eastern coal rail requirements are under contract through 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, 2013 are 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)
Plant Name	County	(MW)	(%)	Year in Service
Fossil-fueled Steam-Electric
Belle River (b)	St. Clair	1,036	9.9	1984 and 1985
Greenwood	St. Clair	798	7.7	1979
Monroe (c)	Monroe	3,022	29.0	1971, 1973 and 1974
River Rouge	Wayne	537	5.2	1957 and 1958
St. Clair	St. Clair	1,386	13.3	1953, 1954, 1959, 1961 and 1969
Trenton Channel	Wayne	631	6.0	1949 and 1968
		7,410	71.1
Oil or Gas-fueled Peaking Units	Various	989	9.5	1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric Fermi 2 (d)	Monroe	1,102	10.6	1988
Hydroelectric Pumped Storage Ludington (e)	Mason	917	8.8	1973
		10,418	100.0

_______________________________________

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

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

(c) The Monroe generating plant provided 38% of DTE Electric’s total 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.

6

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 had approximately 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, 2013, which is projected to represent approximately 9.6% of electricity that will be sold to retail customers in 2015. Approximately 690 MW was in commercial operation at December 31, 2013. DTE Electric expects to meet the 10% renewable portfolio standard with the commercial operation of an additional 210 MW in 2014 and 50 MW in 2015.

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

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

	Circuit Miles
Operating Voltage-Kilovolts (kV)	Overhead	Underground
4.8 kV to 13.2 kV	27,739	14,578
24 kV	182	692
40 kV	2,289	383
120 kV	54	8
	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.

Regulation

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

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

Energy Assistance Programs

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

Strategy and Competition

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

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

7

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 2013, 2012 and 2011. Customers participating in the electric Customer Choice program consist primarily of industrial and commercial 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 Choice on our financial performance and full service customer rates. We expect that in 2014 customers choosing to purchase power from alternative electric suppliers will represent approximately 10% of retail sales.

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

GAS

Description

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

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

Revenue by Service

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

• Gas sales — Includes the sale and delivery of natural gas primarily to residential and small-volume commercial and industrial customers.

• End user transportation — Gas delivery service provided primarily to large-volume commercial and industrial customers. Additionally, the service is provided to residential customers, and small-volume commercial and industrial customers who have elected to participate in our gas Customer Choice program. End user transportation customers purchase natural gas directly from marketers, producers or brokers and utilize our pipeline network to transport the gas to their facilities or homes.

• Intermediate transportation — Gas delivery service is provided to producers, brokers and other gas companies that own the natural gas, but are not the ultimate consumers. Intermediate transportation customers use our gathering and high-pressure transportation system to transport the natural gas to storage fields, processing plants, pipeline interconnections or other locations.

• Storage and other — Includes revenues from natural gas storage, appliance maintenance, facility development and other energy-related services.

8

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 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's energy efficiency program, or 1.125% in year one, increasing to 2.25% for the second and future periods.

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

Natural Gas Supply

Our gas distribution system has a planned maximum daily send-out capacity of 2.5 Bcf, with approximately 67% of the volume coming from underground storage for 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 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:

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

Properties

We own distribution, storage and transportation properties that are located in the State of Michigan. Our distribution system includes approximately 19,000 miles of distribution mains, approximately 1,162,000 service pipelines and approximately 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 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.

9

Regulation

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

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

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

Energy Assistance Program

Energy assistance programs, funded by the federal government and the State of Michigan, remain critical to DTE Gas’s ability to control its uncollectible accounts receivable and collections expenses. DTE 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.

Strategy and Competition

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

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

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

DTE Gas’s storage capacity is used to store natural gas for delivery to DTE 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.

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GAS STORAGE AND PIPELINES

Description

Gas Storage and Pipelines controls two natural gas storage fields, intrastate lateral and intrastate gathering pipeline systems, and has ownership interests in two interstate pipelines serving the Midwest, Ontario and Northeast markets. The pipeline and storage assets are primarily supported by long-term, fixed-price revenue contracts.

Properties

The Gas Storage and Pipelines business holds the following property:

Property Classification	% Owned		Description	Location
Pipelines
Vector Pipeline	40	%	348-mile pipeline connecting Chicago, Michigan and Ontario market centers	IL, IN, MI & Ontario
Millennium Pipeline	26	%	182-mile pipeline serving markets in the Northeast	NY
Bluestone Lateral	100	%	44-mile pipeline delivering Marcellus Shale gas to Millennium Pipeline and Tennessee Pipeline	PA & NY
Susquehanna gathering system	100	%	Gathering system 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

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 Michigan gathering systems.

Regulation

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

Strategy and Competition

Our Gas Storage and Pipelines business expects to continue its steady growth plan by expanding existing assets and developing new assets that are typically supported with long−term customer commitments. We have competition from other pipelines and storage providers. The Gas Storage and Pipelines business focuses on asset development opportunities in the Midwest−to−Northeast region to supply natural gas to meet growing demand. Much of the growth in demand for natural gas is expected to occur in the Eastern Canada and the Northeast U.S. regions. We believe that the Vector and Millennium Pipelines are well positioned to provide access routes and low−cost expansion options to these markets. In addition, we believe that Millennium Pipeline is well positioned for growth in production from the Marcellus shale, especially with respect to Marcellus production in Northern Pennsylvania and along the southern tier of New York. Gas Storage and Pipelines has an agreement with Southwestern Energy Services Company and affiliates to support its Bluestone Lateral and Susquehanna gathering system. Bluestone Lateral is a 44-mile pipeline in Susquehanna County, Pennsylvania and Broome County, New York with the southern portion of the pipeline placed in service in 2012 and the northern portion placed in service in the first quarter of 2013. We expect to continue steady growth in the Gas Storage and Pipelines business and are evaluating new pipeline and storage investment opportunities that could include additional Millennium expansions and laterals, Bluestone laterals and gathering expansions and other Marcellus midstream development or partnering opportunities. 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 Gas Storage and Pipelines business.

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POWER AND INDUSTRIAL PROJECTS

Description

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

Steel and Petroleum Coke:  We produce metallurgical coke from two coke batteries with a capacity of 1.4 million tons per year. We have an investment in a third coke battery with a capacity of 1.2 million tons per year. We also provide pulverized coal and petroleum coke to the steel, pulp and paper, and other industries.

Onsite Energy:  We provide power generation, steam production, chilled water production, wastewater treatment and compressed air supply to industrial customers. We provide utility-type services using project assets usually located on or near the customers' premises in the automotive, airport, chemical and other industries.

Wholesale Power and Renewables:  We own and operate four biomass-fired electric generating plants with a capacity of 183 MWs. We own a coal-fired power plant currently undergoing conversion to biomass with an in-service date in 2014. The electric output is sold under long term power purchase agreements. We also develop landfill gas recovery systems that capture the gas and provide local utilities, industry and consumers with an opportunity to use a competitive, renewable source of energy, in addition to providing environmental benefits by reducing greenhouse gas emissions.

Reduced Emissions Fuel (REF): We own and operate nine REF facilities. Our facilities blend a proprietary additive with coal used in coal-fired power plants resulting in reduced emissions of Nitrogen Oxide (NO) and Mercury (Hg). Qualifying facilities are eligible to generate tax credits for ten years upon achieving certain criteria. The value of a tax credit is adjusted annually by an inflation factor published by the Internal Revenue Service. The value of the tax credit is reduced if the reference price of coal exceeds certain thresholds. The economic benefit of the REF facilities is dependent upon the generation of production tax credits. We placed in service five REF facilities in 2009 and an additional four REF facilities in 2011. To optimize income and cash flow from the REF operations, we sold membership interests at two of the facilities in 2011 and at two additional facilities in 2013. We continue to optimize these facilities by seeking investors for facilities operating at DTE Electric and other utility sites. Additionally, we intend to relocate certain underutilized facilities to alternative coal-fired power plants which may provide increased production and emission reduction opportunities in 2014 and future years.

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Properties and Other

The following are significant properties operated by the Power and Industrial Projects segment:

Facility	Location	Service Type
Steel and Petroleum Coke
Pulverized Coal Operations	MI	Pulverized Coal
Coke Production	MI, PA & IN	Metallurgical Coke Supply
Other Investment in Coke Production and Petroleum Coke	IN & MS	Metallurgical Coke 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	OH	Electricity, Steam, Hot and Chilled Water, Sewer, Compressed Air
Business Park	FL, 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
REF	MI, OK, IL & OH	REF Supply

	2013		2012		2011
	(In millions)
Production Tax Credits Generated (Allocated to DTE Energy)
REF	$	44	$	35	$	1
Power Generation	8		7		4
Landfill Gas Recovery	1		1		1
	$	53	$	43	$	6

Regulation

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

Strategy and Competition

Power and Industrial Projects will continue leveraging its energy-related operating experience and project management capability to develop and grow our steel, renewable power, on-site energy, landfill gas recovery and REF businesses. We also will continue to pursue opportunities to provide asset management and operations services to third parties. There are limited competitors for our existing disparate businesses who provide similar products and services. 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.

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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 competitors and our ability to achieve sustainable margins. We plan to maximize the effectiveness of our related businesses as we expand. As we pursue growth opportunities, our first priority will be to achieve value-added returns.

We intend to focus on the following areas for growth:

• Selling membership interests in our REF projects;

• Relocating our underutilized REF facilities to alternative coal-fired power plants which may provide increased production and emission reduction opportunities in 2014 and future years;

• Acquiring and developing landfill gas recovery facilities, renewable energy projects, and other energy projects which may qualify for tax credits; and

• Providing operating services to owners of industrial and power plants.

ENERGY TRADING

Description

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

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

Regulation

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

Strategy and Competition

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

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CORPORATE AND OTHER

Description

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

ENVIRONMENTAL MATTERS

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

	Electric		Gas		Non-utility		Total
	(In millions)
Air	$	1,420	$	—	$	—	$	1,420
Water	80		—		18		98
Contaminated and other sites	8		28		—		36
Estimated total future expenditures through 2021	$	1,508	$	28	$	18	$	1,554
Estimated 2014 expenditures	$	280	$	5	$	10	$	295
Estimated 2015 expenditures	$	95	$	6	$	8	$	109

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 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 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.

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

EMPLOYEES

We had approximately 9,900 employees as of December 31, 2013, of which approximately 4,900 were represented by unions. There are several bargaining units for the Company’s represented employees. The majority of represented employees are under contracts that expire in 2016 and 2017.

Item 1A.Risk Factors

There are various risks associated with the operations of DTE Energy's utility and non-utility businesses. To provide a framework to understand the operating environment of DTE Energy, we are providing a brief explanation of the more significant risks associated with our businesses. Although we have tried to identify and discuss key risk factors, others could emerge in the future. Each of the following risks could affect our performance.

We are subject to rate regulation.  Electric and gas rates for our utilities are set by the MPSC and the FERC and cannot be changed without regulatory authorization. We may be negatively impacted by new regulations or interpretations by the MPSC, the FERC or other regulatory bodies. Our ability to recover costs may be impacted by the time lag between the incurrence of costs and the recovery of the costs in customers' rates. Our regulators also may decide to disallow recovery of certain costs in customers' rates if they determine that those costs do not meet the standards for recovery under our governing laws and regulations. Our utilities typically self-implement base rate changes six months after rate case filings in accordance with Michigan law. However, if the final rates authorized by our regulators in the final rate order are lower than the amounts we collected during the self-implementation period, we must refund the difference with interest. Our regulators may also disagree with our rate calculations under the various tracking and decoupling mechanisms that are intended to mitigate the risk to our utilities of certain aspects of our business. If we cannot agree with our regulators on an appropriate reconciliation of those mechanisms, it may impact our ability to recover certain costs through our customer rates. Our regulators may also decide to eliminate these mechanisms in future rate cases, which may make it more difficult for us to recover our costs in the rates we charge customers. We cannot predict what rates an MPSC order will authorize in future rate cases. New legislation, regulations or interpretations could change how our business operates, impact our ability to recover costs through rates or require us to incur additional expenses.

Changes to Michigan's electric Customer Choice program could negatively impact our financial performance.  The State of Michigan currently experiences a hybrid market, where the MPSC continues to regulate electric rates for our customers, while alternative electric suppliers charge market-based rates. Energy legislation enacted by the State of Michigan in 2008, placed a 10% cap on the total potential electric Customer Choice related migration. However, even with the legislated 10% cap on participation , there continues to be legislative and financial risk associated with the electric Customer Choice program. Electric Customer Choice migration is sensitive to market price and full service electric price changes.

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

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

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

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Future environmental regulation of natural gas extraction techniques including hydraulic fracturing being discussed both at the United States federal level and by some states may affect the profitability of natural gas extraction businesses which could affect demand for and profitability of our gas transportation businesses.

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

The supply and/or price of energy commodities and/or related services may impact our financial results.  We are dependent on coal for much of our electrical generating capacity. Our access to natural gas supplies is critical to ensure reliability of service for our utility gas customers. Our non-utility businesses are also dependent upon supplies and prices of energy commodities and services. Price fluctuations, fuel supply disruptions and changes in transportation costs could have a negative impact on the amounts we charge our utility customers for electricity and gas and on the profitability of our non-utility businesses. We have hedging strategies and regulatory recovery mechanisms in place to mitigate some of the negative fluctuations in commodity supply prices in our utility and non-utility businesses, but there can be no assurances that our financial performance will not be negatively impacted by price fluctuations. The price of energy also impacts the market for our non-utility businesses that compete with utilities and alternative electric suppliers.

The supply and/or price of other industrial raw and finished inputs and/or related services may impact our financial results.  We are dependent on supplies of certain commodities, such as copper and limestone, among others, and industrial materials and services in order to maintain day-to-day operations and maintenance of our facilities. Price fluctuations or supply interruptions for these commodities and other items could have a negative impact on the amounts we charge our customers for our utility products and on the profitability of our non-utility businesses.

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

Poor investment performance of pension and other postretirement benefit plan assets and other factors impacting benefit plan costs could unfavorably impact our liquidity and results of operations.  Our costs of providing non-contributory defined benefit pension plans and other postretirement benefit plans are dependent upon a number of factors, such as the rates of return on plan assets, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation, and our required or voluntary contributions made to the plans. The performance of the debt and equity markets affects the value of assets that are held in trust to satisfy future obligations under our plans. We have significant benefit obligations and hold significant assets in trust to satisfy these obligations. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the pension and other postretirement benefit plan assets will increase the funding requirements under our pension and other postretirement benefit plans if the actual asset returns do not recover these declines in the foreseeable future. Additionally, our pension and other postretirement benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, resulting in increasing benefit expense and funding requirements. Also, if future increases in pension and other postretirement benefit costs as a result of reduced plan assets are not recoverable from our utility customers, the results of operations and financial position of our company could be negatively affected. Without sustained growth in the plan investments over time to increase the value of our plan assets, we could be required to fund our plans with significant amounts of cash. Such cash funding obligations could have a material impact on our cash flows, financial position, or results of operations.

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Our ability to access capital markets is important.  Our ability to access capital markets is important to operate our businesses. Turmoil in credit markets may constrain our ability, as well as the ability of our subsidiaries, to issue new debt, including commercial paper, and refinance existing debt at reasonable interest rates. In addition, the level of borrowing by other energy companies and the market as a whole could limit our access to capital markets. Our long term revolving credit facilities do not expire until 2018, but we regularly access capital markets to refinance existing debt or fund new projects at our utilities and non-utility businesses, and we cannot predict the pricing or demand for those future transactions.

Construction and capital improvements to our power facilities and distribution systems subject us to risk. We are managing ongoing and planning future significant construction and capital improvement projects at multiple power generation and distribution facilities and our gas distribution system. Many factors that could cause delays or increased prices for these complex projects are beyond our control, including the cost of materials and labor, subcontractor performance, timing and issuance of necessary permits, construction disputes and weather conditions. Failure to complete these projects on schedule and on budget for any reason could adversely affect our financial performance and operations at the affected facilities and businesses.

Our non-utility businesses may not perform to our expectations. We rely on our non-utility operations for an increasing portion of our earnings. If our current and contemplated non-utility investments do not perform at expected levels, we could experience diminished earnings and a corresponding decline in our shareholder value.

Our participation in energy trading markets subjects us to risk.  Events in the energy trading industry have increased the level of scrutiny on the energy trading business and the energy industry as a whole. In certain situations we may be required to post collateral to support trading operations, which could be substantial. If access to liquidity to support trading activities is curtailed, we could experience decreased earnings potential and cash flows. Energy trading activities take place in volatile markets and expose us to risks related to commodity price movements, deviations in weather and other related risks. We routinely have speculative trading positions in the market, within strict policy guidelines we set, resulting from the management of our business portfolio. To the extent speculative trading positions exist, fluctuating commodity prices can improve or diminish our financial results and financial position. We manage our exposure by establishing and enforcing strict risk limits and risk management procedures. During periods of extreme volatility, these risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities.

Our ability to utilize production tax credits may be limited.  To reduce U.S. dependence on imported oil, the Internal Revenue Code provides production tax credits as an incentive for taxpayers to produce fuels and electricity from alternative sources. We generated production tax credits from coke production, landfill gas recovery, biomass fired electric generation, reduced emission fuel, renewable energy generation and gas production operations. All production tax credits taken after 2011 are subject to audit by the Internal Revenue Service (IRS). If our production tax credits were disallowed in whole or in part as a result of an IRS audit, there could be additional tax liabilities owed for previously recognized tax credits that could significantly impact our earnings and cash flows.

Weather significantly affects operations.  Deviations from normal hot and cold weather conditions affect our earnings and cash flow. Mild temperatures can result in decreased utilization of our assets, lowering income and cash flow. Ice storms, tornadoes, or high winds can damage the electric distribution system infrastructure and power generation facilities and require us to perform emergency repairs and incur material unplanned expenses. The expenses of storm restoration efforts may not be fully recoverable through the regulatory process.

Unplanned power plant outages may be costly.  Unforeseen maintenance may be required to safely produce electricity or comply with environmental regulations. As a result of unforeseen maintenance, we may be required to make spot market purchases of electricity that exceed our costs of generation. Our financial performance may be negatively affected if we are unable to recover such increased costs.

We rely on cash flows from subsidiaries.  DTE Energy is a holding company. Cash flows from our utility and non-utility subsidiaries are required to pay interest expenses and dividends on DTE Energy debt and securities. Should a major subsidiary not be able to pay dividends or transfer cash flows to DTE Energy, our ability to pay interest and dividends would be restricted.

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Renewable portfolio standards and energy efficiency programs may affect our business.  We are subject to existing Michigan and potential future federal legislation and regulation requiring us to secure sources of renewable energy. We expect to comply with the existing state legislation, but we do not know what requirements may be added by federal legislation. In addition, there could be additional state requirements increasing the percentage of power required to be provided by renewable energy sources. We cannot predict the financial impact or costs associated with complying with potential future legislation and regulations. Compliance with these requirements can significantly increase capital expenditures and operating expenses and can negatively affect the affordability of the rates we charge to our customers.

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

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

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

In addition, our generation plants, gas pipeline and storage facilities and electrical distribution facilities in particular may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products. We have increased security as a result of past events and we may be required by our regulators or by the future terrorist threat environment to make investments in security that we cannot currently predict.

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

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

A work interruption may adversely affect us.  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 2016 and 2017. A union choosing to strike would have an impact on our business. We are unable to predict the effect a work stoppage would have on our costs of operation and financial performance.

If our goodwill becomes impaired, we may be required to record a charge to earnings.  We annually review the carrying value of goodwill associated with acquisitions made by the Company for impairment. Factors that may be considered for purposes of this analysis include any change in circumstances indicating that the carrying value of our goodwill may not be recoverable such as a decline in stock price and market capitalization, future cash flows, and slower growth rates in our industry. We cannot predict the timing, strength or duration of any economic slowdown or subsequent recovery, worldwide or in the economy or markets in which we operate; however, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable, the Company may take a non-cash impairment charge, which could potentially materially impact our results of operations and financial position.

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

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

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. In June 2010, the EPA issued a NOV/FOV making similar allegations related to a 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 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. On March 28, 2013, the Court of Appeals 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 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.

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

In March 2013, the Sierra Club filed suit against DTE Energy and DTE Electric alleging violations of the Clean Air Act at four of DTE Electric's coal-fired power plants. The plaintiffs allege 1,499 6-minute periods of excess opacity of air emissions from 2007-2012 at those facilities. The suit asks that the 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 amended complaint in the first quarter of 2014. The resolution of this matter is not expected to have a material effect on the Company's operations or financial statements.

For additional discussion on legal matters, see Notes 11 and 19 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

20

Item 4. Mine Safety Disclosures

Not applicable.

21

Part II

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

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

						Dividends Paid per Share
Year	Quarter	High		Low
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
	Second	$	60.25	$	53.70	$	0.5875
	Third	$	62.54	$	58.06	$	0.6200
	Fourth	$	62.49	$	58.20	$	0.6200

At December 31, 2013, there were 177,087,230 shares of our common stock outstanding. These shares were held by a total of 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. 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, 2013.

	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	723,697	$	42.60	2,044,255

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UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

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

	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
10/01/2013 — 10/31/2013	1,452	$	66.69	—	—	—
11/01/2013 — 11/30/2013	—	—		—	—	—
12/01/2013 — 12/31/2013	2,790	$	67.62	—	—	—
Total	4,242			—

_______________________________________

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

COMPARISON OF CUMULATIVE FIVE YEAR TOTAL RETURN

Total Return To Shareholders

(Includes reinvestment of dividends)

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

	Indexed Returns Year Ended December 31
	Base Period
Company/Index	2008	2009	2010	2011	2012	2013
DTE Energy Company	100	130.08	141.86	178.40	204.99	235.52
S&P 500 Index	100	126.46	145.51	148.59	172.37	228.19
S&P 500 Multi-Utilities Index	100	120.92	134.32	159.05	165.79	195.43

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Item 6. Selected Financial Data

The following selected financial data should be read in conjunction with the accompanying Management’s Discussion and Analysis in Item 7 of this Report and Notes to the Consolidated Financial Statements in Item 8 of this Report.

	2013		2012			2011			2010			2009
	(In millions, except per share amounts)
Operating Revenues	$	9,661	$	8,791		$	8,858		$	8,525		$	7,983
Net Income Attributable to DTE Energy Company
Income from continuing operations (a)	$	661	$	666		$	714		$	638		$	538
Discontinued operations (b)	—		(56		)	(3		)	(8		)	(6		)
Net Income Attributable to DTE Energy Company	$	661	$	610		$	711		$	630		$	532
Diluted Earnings Per Common Share
Income from continuing operations	$	3.76	$	3.88		$	4.20		$	3.78		$	3.27
Discontinued operations	—		(0.33		)	(0.02		)	(0.04		)	(0.03		)
Diluted Earnings Per Common Share	$	3.76	$	3.55		$	4.18		$	3.74		$	3.24
Financial Information
Dividends declared per share of common stock	$	2.59	$	2.42		$	2.32		$	2.18		$	2.12
Total assets	$	25,935	$	26,339		$	26,009		$	24,896		$	24,195
Long-term debt, including capital leases	$	7,214	$	7,014		$	7,187		$	7,089		$	7,370
Shareholders’ equity	$	7,921	$	7,373		$	7,009		$	6,722		$	6,278

_______________________________________

(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.

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

EXECUTIVE OVERVIEW

DTE Energy is a diversified energy company with 2013 operating revenues of approximately $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 Michigan. We operate three energy-related non-utility segments with operations throughout the United States.

The following table summarizes our financial results:

	2013		2012		2011
	(In millions, except per share amounts)
Income from continuing operations	$	668	$	674	$	723
Diluted earnings per common share from continuing operations	$	3.76	$	3.88	$	4.20

The decrease in 2013 income from continuing operations is primarily due to lower earnings in the Energy Trading segment, partially offset by higher earnings in the Gas and Power and Industrial Projects segments. The decrease in 2012 income from continuing operations is principally driven by an income tax benefit of $87 million in the Corporate and Other segment related to the enactment of the MCIT in the second quarter of 2011 and lower results in the Energy Trading segment, partially offset by improved results in the Electric segment.

Please see detailed explanations of segment performance in the following Results of Operations section.

DTE Energy's strategy is to achieve long-term earnings growth, a strong balance sheet and an attractive dividend yield.

Our utilities' growth will be driven by environmental and renewable investments in addition to base infrastructure investments. We are focused on executing plans to achieve operational excellence and customer satisfaction with a focus on customer affordability. We operate in a constructive regulatory environment and have solid relationships with our regulators.

We have significant investments in our non-utility businesses. We employ disciplined investment criteria when assessing meaningful, low-risk growth opportunities that leverage our assets, skills and expertise and provide diversity in earnings and geography. Specifically, we invest in targeted energy markets with attractive competitive dynamics where meaningful scale is in alignment with our risk profile. We expect growth opportunities in the Gas Storage and Pipelines and Power and Industrial Projects segments.

A key priority for DTE Energy is to maintain a strong balance sheet which facilitates access to capital markets and reasonably priced short-term and long-term financing. Near-term growth will be funded through internally generated cash flows, issuance of debt and issuance of equity through our dividend reinvestment plan and pension and other employee benefit plans. We have an enterprise risk management program that, among other things, is designed to monitor and manage our exposure to earnings and cash flow volatility related to commodity price changes, interest rates and counterparty credit risk.

CAPITAL INVESTMENTS

Our utility businesses require significant base capital investments each year in order to maintain and improve the reliability of asset bases, including power generation plants, distribution systems, storage fields and other facilities and fleets. DTE Electric's capital investments over the 2014-2018 period are estimated at $5.6 billion for base infrastructure, $700 million for mandated environmental compliance requirements and $400 million for renewable energy and energy efficiency expenditures. DTE Electric plans to seek regulatory approval in general rate case filings and renewable energy plan filings for capital expenditures consistent with prior ratemaking treatment.

DTE Gas's capital investments over the 2014-2018 period are estimated at $700 million for base infrastructure and $500 million for gas main renewal, meter move out and pipeline integrity programs. In April 2013, the MPSC issued an order approving an infrastructure recovery mechanism (IRM) and authorized the recovery of the cost of service related to $77 million of annual investment in its gas main renewal and meter move out and pipeline integrity programs. DTE Gas plans to seek regulatory approval in general rate case filings for base infrastructure capital expenditures consistent with prior ratemaking treatment.

25

ENVIRONMENTAL MATTERS

We are subject to extensive environmental regulation. Additional costs may result as the effects of various substances on the environment are studied and governmental regulations are developed and implemented. Actual costs to comply could vary substantially. We expect to continue recovering environmental costs related to utility operations through rates charged to our customers.

DTE Electric is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. These rules will lead to additional emission controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, acid gases, particulate matter and mercury emissions. To comply with these requirements, DTE Electric has spent approximately $2.0 billion through 2013. It is estimated that DTE Electric will make capital expenditures of approximately $280 million in 2014 and up to approximately $1.2 billion of additional capital expenditures through 2021 based on current regulations.

Climate regulation and/or legislation has been proposed and discussed within the U.S. Congress and the EPA. The EPA is implementing regulatory actions under the Clean Air Act to address emissions of greenhouse gases (GHGs). EPA regulation of GHGs requires the best available control technology (BACT) for new major sources or modifications to existing major sources that cause significant increases in GHG emissions. In June 2012, the EPA proposed new source performance standards for carbon dioxide emissions from new fossil-fueled power plants. These new source performance standards were re-proposed on September 20, 2013, under a presidential directive issued on June 25, 2013. Under the same presidential directive, the EPA is expected to propose performance standards for carbon dioxide emissions from existing and modified plants by June 1, 2014 and issue final standards by June 1, 2015. DTE Energy will be an active participant in working with the EPA and other stakeholders to shape the final performance standards for new and existing power plants. The standards for new sources are not expected to have a material impact on the Company. It is not possible to determine the potential impact of future regulations on existing sources at this time. Pending or future legislation or other regulatory actions could have a material impact on our operations and financial position and the rates we charge our customers. Impacts include expenditures for environmental equipment beyond what is currently planned, financing costs related to additional capital expenditures, the purchase of emission offsets from market sources and the retirement of facilities where control equipment is not economical. We would seek to recover these incremental costs through increased rates charged to our utility customers per MPSC protocols. Increased costs for energy produced from traditional coal based sources could also increase the economic viability of energy produced from renewable and/or nuclear sources, from energy efficiency initiatives, and from the potential development of market-based trading of carbon offsets which could provide new business opportunities for our utility and non-utility segments. At the present time, it is not possible to quantify the financial implication of these climate related legislative or regulatory initiatives on DTE Energy or its customers.

See Note 19 of the Notes to the Consolidated Financial Statements and Items 1. and 2. Business and Properties for further discussion of Environmental Matters.

OUTLOOK

The next few years will be a period of rapid change for DTE Energy and for the energy industry. Our strong utility base, combined with our integrated non-utility operations, position us well for long-term growth.

Looking forward, we will focus on several areas that we expect will improve future performance:

• electric and gas customer satisfaction;

• electric reliability;

• rate competitiveness and affordability;

• regulatory stability and investment recovery for our utilities;

• growth of our utility asset base;

• employee engagement;

• cost structure optimization across all business segments;

26

• cash, capital and liquidity to maintain or improve our financial strength; and

• investments that integrate our assets and leverage our skills and expertise.

We will continue to pursue opportunities to grow our businesses in a disciplined manner if we can secure opportunities that meet our strategic, financial and risk criteria.

RESULTS OF OPERATIONS

The following sections provide a detailed discussion of the operating performance and future outlook of our segments.

	2013			2012			2011
	(In millions)
Net Income (Loss) Attributable to DTE Energy by Segment:
Electric	$	484		$	483		$	434
Gas	143			115			110
Gas Storage and Pipelines	70			61			57
Power and Industrial Projects	66			42			38
Energy Trading	(58		)	12			52
Corporate and Other	(44		)	(47		)	23
Income From Continuing Operations Attributable to DTE Energy Company	661			666			714
Discontinued Operations	—			(56		)	(3		)
Net Income Attributable to DTE Energy Company	$	661		$	610		$	711

ELECTRIC

Our Electric segment consists principally of DTE Electric.

Electric results are discussed below:

	2013			2012			2011
	(In millions)
Operating Revenues	$	5,199		$	5,293		$	5,154
Fuel and Purchased Power	1,668			1,758			1,716
Gross Margin	3,531			3,535			3,438
Operation and Maintenance	1,377			1,429			1,370
Depreciation and Amortization	902			827			818
Taxes Other Than Income	261			257			240
Asset (Gains) and Losses, Reserves and Impairments, Net	(3		)	(2		)	13
Operating Income	994			1,024			997
Other (Income) and Deductions	258			261			298
Income Tax Expense	252			280			265
Net Income Attributable to DTE Energy Company	$	484		$	483		$	434
Operating Income as a % of Operating Revenues	19		%	19		%	19		%

Gross margin decreased by $4 million in 2013 and increased $97 million in 2012. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statements of Operations.

27

The following table details changes in various gross margin components relative to the comparable prior period:

	2013			2012
	(In millions)
Base sales, inclusive of weather effect	$	(54	)	$	79
Restoration tracker, discontinued in October 2011	—			(47		)
Securitization bond and tax surcharge	39			25
Renewable energy program	19			35
Low income energy assistance surcharge	(12		)	4
Regulatory mechanisms and other	4			1
Increase (decrease) in gross margin	$	(4	)	$	97

	2013	2012	2011
	(In thousands of MWh)
Electric Sales
Residential	15,273	15,666	15,907
Commercial	16,661	16,832	16,779
Industrial	10,303	9,989	9,739
Other	942	958	3,136
	43,179	43,445	45,561
Interconnection sales (a)	3,883	2,125	3,512
Total Electric Sales	47,062	45,570	49,073
Electric Deliveries
Retail and Wholesale	43,179	43,445	45,561
Electric Customer Choice, including self generators (b)	5,200	5,197	5,445
Total Electric Sales and Deliveries	48,379	48,642	51,006

______________________________

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

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

Operation and maintenance expense decreased $52 million in 2013 and increased $59 million in 2012. The decrease in 2013 is primarily due to lower employee benefit expenses of $90 million, lower power plant generation expenses of $14 million and reduced low income energy assistance of $12 million, partially offset by higher restoration and line clearance expenses of $19 million, higher corporate administrative expenses of $17 million, increased uncollectible expenses of $11 million, higher energy optimization and renewable energy expenses of $8 million, and increased distribution operations expenses of $8 million. The increase in 2012 is primarily due to higher employee benefit expenses of $53 million, increased energy optimization and renewable energy expenses of $17 million, higher power plant generation expenses of $12 million, increased distribution operations expenses of $4 million and higher expenses for low income energy assistance of $4 million, partially offset by reduced restoration and line clearance expenses of $22 million and reduced uncollectible expenses of $9 million.

Depreciation and amortization expense increased $75 million in 2013 and $9 million in 2012. The 2013 increase was due to higher amortization of regulatory assets of $57 million, primarily related to Securitization, and increased depreciation of $18 million due to a higher depreciable base. The 2012 increase was due to higher amortization of regulatory assets of $43 million, primarily related to Securitization, partially offset by the net effect of $34 million of lower depreciation rates on a higher depreciable base.

Asset (gains) and losses, reserves and impairments, net increased $1 million in 2013 and increased $15 million in 2012. The 2012 increase was primarily due to a 2011 accrual of $19 million resulting from management's revisions of the timing and estimate of cash flows for the decommissioning of Fermi 1, partially offset by a 2011 revision of $6 million in the timing and estimate of cash flows for the Fermi 1 asbestos removal obligation and other items.

Other (income) and deductions were lower by $3 million in 2013 and by $37 million in 2012. The decrease in 2013 was primarily due to 2012 one time expenses of $11 million related to Michigan ballot proposals and higher 2013 investment earnings of $10 million, offset by the 2013 contribution to the DTE Energy Foundation of $18 million. The decrease in 2012 was due primarily to the 2011 contribution to the DTE Energy Foundation of $21 million and lower interest expense of $17 million.

28

Income tax expense decreased $28 million in 2013 and increased $15 million in 2012. The variances were impacted by variations in pre-tax income and higher production tax credits.

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

In June 2013, the City of Detroit announced a transition of its Public Lighting Department's customers to the DTE Electric distribution system over a five to seven year system conversion period. See Note 11 of the Notes to Consolidated Financial Statements.

GAS

Our Gas segment consists of DTE Gas and Citizens.

Gas results are discussed below:

	2013			2012			2011
	(In millions)
Operating Revenues	$	1,474		$	1,315		$	1,505
Cost of Gas	624			550			744
Gross Margin	850			765			761
Operation and Maintenance	429			385			394
Depreciation and Amortization	95			92			89
Taxes Other Than Income	56			54			54
Operating Income	270			234			224
Other (Income) and Deductions	50			69			54
Income Tax Expense	77			50			60
Net Income Attributable to DTE Energy Company	$	143		$	115		$	110
Operating Income as a % of Operating Revenues	18		%	18		%	15		%

Gross margin increased $85 million in 2013 and increased $4 million in 2012. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statements of Operations.

The following table details changes in various gross margin components relative to the comparable prior period:

	2013			2012
	(In millions)
Weather	$	72		$	(41	)
Uncollectible tracking mechanism	20			—
Lost and stolen gas	9			29
Self implementation and rate orders	15			5
Revenue decoupling mechanism	(16		)	11
Energy optimization revenue	(3		)	6
Midstream storage and transportation revenues	(8		)	6
Other	(4		)	(12		)
Increase in gross margin	$	85		$	4

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	2013	2012	2011
Gas Markets (in Bcf)
Gas sales	128	104	123
End user transportation	157	157	141
	285	261	264
Intermediate transportation	300	264	273
	585	525	537

Operation and maintenance expense increased $44 million in 2013 and decreased $9 million in 2012. The increase in 2013 is primarily due to higher gas operations expenses of $24 million, higher maintenance and repair costs of $14 million, higher transmission costs of $14 million, higher corporate administrative expenses of $8 million and increased uncollectible expenses of $5 million, partially offset by lower employee benefit expenses of $19 million and reduced energy optimization expenses of $3 million. The decrease in 2012 is primarily due to reduced uncollectible expenses of $9 million, lower legal liability expenses of $4 million and lower customer service expenses of $3 million, partially offset by increased energy optimization expenses of $6 million and higher employee benefit expenses of $3 million.

Other (income) and deductions were lower by $19 million in 2013 and higher by $15 million in 2012. The decrease in 2013 is due to lack of a contribution to the DTE Energy Foundation in 2013, partially offset by a $5 million contribution to low income energy assistance funds. The increase in 2012 was due primarily to the contribution to the DTE Energy Foundation of $21 million, partially offset by lower interest expenses of $5 million.

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

GAS STORAGE AND PIPELINES

Our Gas Storage and Pipelines segment consists of our non-utility gas pipelines and storage businesses.

Gas Storage and Pipelines results are discussed below:

	2013			2012			2011
	(In millions)
Operating Revenues	$	132		$	96		$	91
Operation and Maintenance	25			19			16
Depreciation and Amortization	23			8			6
Taxes Other Than Income	3			3			3
Asset (Gains) and Losses and Reserves, Net	—			3			—
Operating Income	81			63			66
Other (Income) and Deductions	(36		)	(40		)	(28		)
Income Tax Expense	45			39			35
Net Income	72			64			59
Noncontrolling interest	2			3			2
Net Income Attributable to DTE Energy	$	70		$	61		$	57

Net income attributable to DTE Energy increased $9 million and $4 million in 2013 and 2012, respectively. Operating revenues increased $36 million and Depreciation expense increased $15 million in 2013 due to the operation of the Bluestone and Susquehanna projects. The 2013 increase in Operating revenues was partially offset by lower storage revenue due to lower market rates. The 2012 increase in Net income was primarily driven by higher earnings from our pipeline equity investments.

30

Outlook — Our Gas Storage and Pipelines business expects to maintain its steady growth by developing an asset portfolio with multiple growth platforms through investment in new projects and expansions. Millennium Pipeline completed its Phase One expansion in 2013, and its Phase Two expansion is scheduled to be in service in 2014. Additionally, Bluestone, a 44-mile lateral pipeline in Susquehanna County, Pennsylvania and Broome County, New York is in service and volumes are increasing. We plan to expand the capacity of the Bluestone lateral by constructing additional compression facilities, meter upgrades, and other initiatives to accommodate increased shipper demand. Through our agreement with Southwestern Energy Services Company and affiliates, we believe Bluestone lateral and Susquehanna gathering system are strategically positioned for future growth of the Marcellus shale.

POWER AND INDUSTRIAL PROJECTS

Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers; produce reduced emissions fuel (REF) and sell electricity from biomass-fired energy projects.

Power and Industrial Projects results are discussed below:

	2013			2012			2011
	(In millions)
Operating Revenues	$	1,950		$	1,823		$	1,129
Operation and Maintenance	1,914			1,788			1,025
Depreciation and Amortization	72			65			60
Taxes other than Income	15			16			10
Asset (Gains) and Losses, Reserves and Impairments, Net	(4		)	(5		)	(12		)
Operating Income (Loss)	(47		)	(41		)	46
Other (Income) and Deductions	(73		)	(44		)	(10		)
Income Taxes
Expense	8			—			17
Production Tax Credits	(53		)	(44		)	(6		)
	(45		)	(44		)	11
Net Income	71			47			45
Noncontrolling interest	5			5			7
Net Income Attributable to DTE Energy Company	$	66		$	42		$	38

Operating revenues increased $127 million in 2013 and increased $694 million in 2012. The 2013 increase is primarily due to a $161 million increase associated with higher volumes from REF projects, of which $25 million represents affiliate transactions, and a $102 million increase due to the on-site energy projects acquired in the 2012 fourth quarter, partially offset by a $75 million decrease from exiting the coal transportation and marketing business, and a $63 million decrease due primarily to lower coal prices associated with the steel business. The 2012 increase is primarily due to a $740 million increase associated with higher volumes from REF projects, of which $554 million represents affiliate transactions, and a $30 million increase due to the on-site energy projects acquired in the 2012 fourth quarter, partially offset by a $44 million decrease primarily due to lower volumes associated with the steel business, and a $28 million decrease in coal transportation and marketing services business.

Operation and maintenance expense increased $126 million in 2013 and increased $763 million in 2012. The 2013 increase is primarily due to a $173 million increase associated with higher volumes from REF projects, of which $25 million represents affiliate transactions and an $84 million increase due to the on-site energy projects acquired in the 2012 fourth quarter, partially offset by a $67 million decrease from exiting the coal transportation and marketing business, and a $67 million decrease due primarily to lower coal prices associated with the steel business. The 2012 increase is primarily due to a $770 million increase associated with higher volumes from REF projects, of which $562 million represents affiliate transactions, a $25 million increase due to the on-site energy projects acquired in the 2012 fourth quarter and an $11 million customer settlement, partially offset by a $20 million decrease primarily due to lower volumes associated with the steel business and a $26 million decrease in coal transportation and marketing services business.

Depreciation and amortization expenseincreased by $7 million in 2013 and increased by $5 million in 2012. The 2013 increase is primarily due to $10 million associated with the on-site energy projects acquired in the 2012 fourth quarter, partially offset by a $3 million decrease from exiting the coal transportation and marketing business. The 2012 increase was primarily due to $4 million associated with the on-site energy projects acquired in the 2012 fourth quarter.

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Asset (gains) and losses, reserves and impairments, net decreased by $1 million in 2013 and decreased by $7 million in 2012. The 2012 decrease was due primarily to a $3 million loss on the sale of assets associated with our coal transloading terminal and $3 million of impairments related to non-strategic assets.

Other (income) and deductions were higher by $29 million in 2013 and $34 million in 2012 due primarily to income that is recognized when refined coal is produced and tax credits are generated.

Production tax credits increased by $9 million in 2013 and $38 million in 2012 primarily due to tax credits earned from REF projects.

Outlook— The Company has constructed and placed in service nine REF facilities including four facilities located at third party owned coal-fired power plants. The Company has sold membership interests in four of the facilities. We continue to optimize these facilities by seeking investors for facilities operating at DTE Electric and other utility sites. Additionally, we intend to relocate two underutilized facilities, located at DTE Electric sites, to alternative coal-fired power plants which may provide increased production and emission reduction opportunities in 2014 and future years.

We expect sustained production levels of metallurgical coke and pulverized coal supplied to steel industry customers for 2014. Substantially all of the metallurgical coke margin is maintained under long-term contracts. We have four biomass-fired power generation facilities in operation, and we are converting an additional facility to be placed in service in 2014. Our on-site energy services will continue to be delivered in accordance with the terms of long-term contracts. We will begin construction on a new natural gas-fired cogeneration facility and two landfill gas to energy projects during the year which are expected to be completed in 2014. We will continue to look for additional investment opportunities and other energy projects at favorable prices.

Power and Industrial Projects will continue to leverage its extensive energy-related operating experience and project management capability to develop additional energy projects to serve energy intensive industrial customers.

ENERGY TRADING

Energy Trading focuses on physical and financial power, natural 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, and the supply or purchase of renewable energy credits to various customers.

Energy Trading results are discussed below:

	2013			2012		2011
	(In millions)
Operating Revenues	$	1,771		$	1,109	$	1,276
Fuel, Purchased Power and Gas	1,782			1,011		1,112
Gross Margin	(11		)	98		164
Operation and Maintenance	72			66		63
Depreciation and Amortization	1			2		3
Taxes Other Than Income	4			3		3
Operating Income (Loss)	(88		)	27		95
Other (Income) and Deductions	8			8		9
Income Tax Expense (Benefit)	(38		)	7		34
Net Income (Loss) Attributable to DTE Energy Company	$	(58	)	$	12	$	52

Gross margin decreased $109 million in 2013 and decreased $66 million in 2012. The overall decrease in gross margin in 2013 was primarily due to timing from mark-to-market adjustments on certain transactions in our gas structured strategy.

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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 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 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.

Outlook — In the near term, we expect market conditions to remain challenging and the profitability of this segment may be impacted by the volatility in commodity prices in the markets we participate in and the uncertainty of impacts associated with financial reform, regulatory changes and changes in operating rules of regional transmission organizations.

The Energy Trading portfolio includes financial instruments, physical commodity contracts and 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

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 and lower interest costs.

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

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DISCONTINUED OPERATIONS

Unconventional Gas Production

In December 2012, the Company sold its 100% equity interest in its Unconventional Gas Production business which consisted of gas and oil production assets in the western Barnett and Marble Falls shale areas of Texas. See Note 7 of the Notes to Consolidated Financial Statements.

CAPITAL RESOURCES AND LIQUIDITY

Cash Requirements

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 2014, we expect that cash from operations will be $1.6 billion due to lower surcharge collections and higher 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 2014 of approximately $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.

	2013			2012			2011
	(In millions)
Cash and Cash Equivalents
Cash Flow From (Used For)
Operating activities:
Net income	$	668		$	618		$	720
Depreciation, depletion and amortization	1,094			1,018			995
Nuclear fuel amortization	38			29			46
Allowance for equity funds used during construction	(15		)	(13		)	(6		)
Deferred income taxes	164			47			220
Loss on sale of non-utility business	—			83			—
Asset (gains) and losses, reserves and impairments, net	(8		)	1			(21		)
Working capital and other	213			426			54
	2,154			2,209			2,008
Investing activities:
Plant and equipment expenditures — utility	(1,534		)	(1,451		)	(1,382		)
Plant and equipment expenditures — non-utility	(342		)	(369		)	(102		)
Proceeds from sale of non-utility business	—			255			—
Proceeds from sale of assets	36			38			18
Acquisition, net of cash acquired	—			(198		)	—
Other	(66		)	(44		)	(94		)
	(1,906		)	(1,769		)	(1,560		)
Financing activities:
Issuance of long-term debt	1,234			759			1,179
Redemption of long-term debt	(961		)	(639		)	(1,455		)
Short-term borrowings, net	(109		)	(179		)	269
Issuance of common stock	39			39			—
Repurchase of common stock	—			—			(18		)
Dividends on common stock	(445		)	(407		)	(389		)
Other	(19		)	(16		)	(31		)
	(261		)	(443		)	(445		)
Net Increase (Decrease) in Cash and Cash Equivalents	$	(13	)	$	(3	)	$	3

Cash from Operating Activities

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.

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

The change in working capital items in 2013 primarily related to fuel inventories, derivative assets and liabilities and pension and other postretirement liabilities, partially offset by the change in accounts receivable, net. The change in working capital items in 2012 primarily related to pension and other postretirement obligations and income taxes.

Cash used for Investing Activities

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

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

Capital spending within our non-utility businesses is primarily for ongoing maintenance, expansion and 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 2013 due primarily to increased capital expenditures by our utility businesses.

Net cash used for investing activities was higher by $209 million in 2012 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 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% to 52%, to ensure it is consistent with our objective to have a strong investment grade debt rating.

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

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

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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 timing of collection 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 $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, 2013, consisting of cash and amounts available under unsecured revolving credit agreements.

At the discretion of management, and depending upon financial market conditions, we anticipate making 2014 contributions to the pension plans of up to $345 million and up to $145 million to the other postretirement benefit plans.

Various 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, 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 $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, 2013:

	Total		2014		2015-2016		2017-2018		2019 and Beyond
	(In millions)
Long-term debt:
Mortgage bonds, notes and other (a)	$	7,326	$	695	$	836	$	416	$	5,379
Securitization bonds	302		197		105		—		—
Junior subordinated debentures	480		—		—		—		480
Capital lease obligations	19		8		11		—		—
Interest	6,091		429		670		631		4,361
Operating leases	230		35		58		45		92
Electric, gas, fuel, transportation and storage purchase obligations (b)	8,499		2,577		1,802		645		3,475
Other long-term obligations (c)(d)(e)	99		40		36		11		12
Total obligations	$	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.

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

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

(e) At December 31, 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 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. 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.

37

In January 2013, Fitch raised the senior secured debt rating for DTE Gas from 'A-' to 'A' and affirmed the senior unsecured debt rating for DTE 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 'Baa2' to 'Baa1' and upgraded the secured debt rating of DTE Electric and DTE Gas from 'A2' to 'A1'. In August 2013, S&P raised the credit outlook from 'stable' to 'positive' for DTE Energy, DTE Electric, and DTE Gas pointing to the Company's improving business risk profile. S&P also revised its business risk profile to 'excellent'. In January 2014, based on a favorable view of the U.S. regulatory environment, Moody's upgraded DTE Energy's unsecured debt rating from 'Baa1' to 'A3' and upgraded the secured debt rating of DTE Electric and DTE Gas from 'A1' to '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, 2013 and 2012. Management believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

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 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, 2013 and determined that the estimated fair value of each reporting unit exceeded its carrying value, and no impairment existed. 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.

As of October 1, 2013 Valuation Date:

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

_______________________________________

(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 2014-2018 projected cash flows plus a calculated terminal value.
(d)	Power and Industrial Projects excludes the Biomass reporting unit as this unit has no allocated goodwill.
(e)	Asset sales were assumed except for Power and Industrial Projects' reduced emissions fuels projects, which assumed stock sales.

The Energy Trading reporting unit passed Step 1 of the impairment test by a 15% margin. A substantive increase in the market interest rate or disruptions in cash flows for the Energy Trading reporting unit could result in an impairment charge in the foreseeable future. For example, holding all other variables constant, a 2% increase in the discount rate would lower the fair value by approximately $49 million. At the lower fair value, the Energy Trading reporting unit would likely fail Step 1 of the test, potentially resulting in a charge for impairment of goodwill following the completion of the Step 2 analysis.

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We perform an annual impairment test each October. In between annual tests, we monitor our estimates and assumptions regarding estimated future cash flows, including the impact of movements in market indicators in future quarters and will update our impairment analyses if a triggering event occurs. While we believe our assumptions are reasonable, actual results may differ from our projections. To the extent projected results or cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill, which would adversely impact our earnings.

Long-Lived Assets

We evaluate the carrying value of our long-lived assets, excluding goodwill, when circumstances indicate that the carrying value of those assets may not be recoverable. Conditions that could have an adverse impact on the cash flows and fair value of the long-lived assets are deteriorating business climate, condition of the asset, or plans to dispose of the asset before the end of its useful life. The review of long-lived assets for impairment requires significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level for which independent cash flows of long-lived assets can be identified from other groups of assets and liabilities. Impairment may occur when the carrying value of the asset exceeds the future undiscounted cash flows. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the long-lived asset over its fair value. An impairment would require us to reduce both the long-lived asset and current period earnings by the amount of the impairment, which would adversely impact our earnings.

Pension and Other Postretirement Costs

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. Other postretirement benefits costs (credit) were $(42) million in 2013, $151 million in 2012 and $122 million in 2011. Pension and other postretirement benefits costs for 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 2014 expected long-term rate of return on pension plan assets is based on an asset allocation assumption utilizing active investment management of 47% in equity markets, 25% in fixed income markets, and 28% invested in other assets. Because of market volatility, we periodically review our asset allocation and rebalance our portfolio when considered appropriate. Given market conditions and financial market risk considerations, we are changing our long-term rate of return assumptions for our pension plans and our other postretirement health and life plans from 8.25% for 2013 to 7.75% for our pension plans and to 8% for our other postretirement health and life plans for 2014. We believe these rates are reasonable assumptions for the long-term rate of return on our plan assets for 2014 given our investment strategy. We will continue to evaluate our actuarial assumptions, including our expected rate of return, at least annually.

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

40

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 increased to 4.95% at December 31, 2013 from 4.15% at December 31, 2012. We estimate that our 2014 total pension costs will approximate $175 million compared to $228 million in 2013 primarily due to greater than expected 2013 returns, a higher discount rate, lower amortization of net actuarial losses and 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 7.5% for 2014 and 2015, 7% for 2016 and 2017, 6.5% in 2018, 6% in 2019, 5.75% in 2020, 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.

Lowering the expected long-term rate of return on our plan assets by one percentage point would have increased our 2013 pension costs by approximately $32 million. Lowering the discount rate and the salary increase assumptions by one percentage point would have increased our 2013 pension costs by approximately $16 million. Lowering the expected long-term rate of return on our plan assets by one percentage point would have increased our 2013 other postretirement costs by approximately $13 million. Lowering the discount rate assumption by one percentage point would have decreased our 2013 other postretirement credit by approximately $27 million. Lowering the health care cost trend assumptions by one percentage point would have increased our other postretirement credit for 2013 by approximately $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. At December 31, 2013, our qualified pension plans were underfunded by $565 million and our other postretirement benefit plans were underfunded by $351 million. The 2013 funding levels generally 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 2013 and 2012.

Pension and other postretirement costs and pension cash funding requirements may increase in future years without typical returns in the financial markets. We made contributions to our qualified pension plans of $277 million in 2013 and $229 million in 2012. At the discretion of management, consistent with the Pension Protection Act of 2006, and depending upon financial market conditions, we anticipate making contributions to our qualified pension plans of up to $345 million in 2014 and up to $1.0 billion over the next five years. We made other postretirement benefit plan contributions of $264 million and $140 million in 2013 and 2012, respectively. We are required by orders issued by the MPSC to make other postretirement benefit contributions at least equal to the amounts included in our utilities' base rates. As a result, we anticipate making up to a $145 million contribution to our other postretirement plans in 2014 and, subject to MPSC funding requirements, up to $165 million over the next five years. The planned contributions will be made in cash, DTE Energy common stock or a combination of cash and stock.

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

Legal Reserves

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

Insured and Uninsured Risks

Our comprehensive insurance program provides coverage for various types of risks. Our insurance policies cover risk of loss including property damage, general liability, workers’ compensation, auto liability, and directors’ and officers’ liability. Under our risk management policy, we self-insure portions of certain risks up to specified limits, depending on the type of exposure. The maximum self-insured retention for various risks is as follows: property damage - $10 million, general liability - $7 million, workers’ compensation - $9 million, and auto liability - $7 million. We have an actuarially determined estimate of our incurred but not reported (IBNR) liability prepared annually and we adjust our reserves for self-insured risks as appropriate. As of December 31, 2013, this IBNR liability was approximately $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 are 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, the 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 markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). For further discussion of the fair value hierarchy, see Note 3 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

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

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

42

The table below shows the maturity of our MTM positions:

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

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Price Risk

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

The Electric and Gas businesses have risks in conjunction with the anticipated purchases of coal, natural gas, uranium, electricity, and base metals to meet their service obligations. However, the Company does not bear significant exposure to earnings risk as such changes are included in the PSCR and GCR regulatory rate-recovery mechanisms. In addition, changes in the price of natural gas can impact the valuation of lost and stolen gas and storage sales revenue 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. The Company manages its exposures to commodity price risk through the use of long-term contracts.

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

Credit Risk

Bankruptcies

The Company purchases and sells electricity, 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 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 Company's utilities provide services to the city of 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 impact on its financial results.

Other

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

43

Trading Activities

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

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

	Credit Exposure Before Cash Collateral		Cash Collateral			Net Credit Exposure
	(In millions)
Investment Grade (a)
A− and Greater	$	154	$	(33	)	$	121
BBB+ and BBB	240		—			240
BBB−	108		—			108
Total Investment Grade	502		(33		)	469
Non-investment grade (b)	1		—			1
Internally Rated — investment grade (c)	173		—			173
Internally Rated — non-investment grade (d)	21		(6		)	15
Total	$	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 31% of the total gross credit exposure.

(b) This category includes counterparties with credit ratings that are below investment grade. The five largest counterparty exposures combined for this category represented less than 1% 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 18% of the total gross credit exposure.

(d) This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, and are considered non-investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately 2% of the total gross credit exposure.

Interest Rate Risk

We are subject to interest rate risk in connection with the issuance of 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, 2013, we had a floating rate debt-to-total debt ratio of approximately 2% (excluding securitized debt).

Foreign Currency Exchange Risk

We have foreign currency exchange risk arising from market price fluctuations associated with fixed priced contracts. These contracts are denominated in Canadian dollars and are primarily for the purchase and sale of 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.

Summary of Sensitivity Analysis

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

44

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

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

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

45

Item 8. Financial Statements and Supplementary Data

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

	Page
Controls and Procedures	47
Report of Independent Registered Public Accounting Firm	48
Consolidated Statements of Operations	49
Consolidated Statements of Comprehensive Income	50
Consolidated Statements of Cash Flows	51
Consolidated Statements of Financial Position	52
Consolidated Statements of Changes in Equity	54
Notes to Consolidated Financial Statements	55
Note 1. Organization and Basis of Presentation	55
Note 2. Significant Accounting Policies	57
Note 3. Fair Value	61
Note 4. Financial and Other Derivative Instruments	67
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	74
Note 11. Regulatory Matters	75
Note 12. Income Taxes	82
Note 13. Common Stock	85
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	89
Note 18. Capital and Operating Leases	90
Note 19. Commitments and Contingencies	91
Note 20. Retirement Benefits and Trusteed Assets	96
Note 21. Stock-based Compensation	106
Note 22. Segment and Related Information	108
Note 23. Supplementary Quarterly Financial Information (Unaudited)	111
Financial Statement Schedule
Schedule II — Valuation and Qualifying Accounts	121

46

Controls and Procedures

(a) Evaluation of disclosure controls and procedures

Management of the Company carried out an evaluation, under the supervision and with the participation of DTE Energy’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2013, which is the end of the period covered by this report. Based on this evaluation, the Company’s CEO and CFO have concluded that such disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) is accumulated and communicated to the Company’s management, including its CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.

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

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

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

Management of the Company has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2013. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (1992 COSO) in Internal Control - Integrated Framework. Based on this assessment, management concluded that, as of December 31, 2013, the Company’s internal control over financial reporting was effective based on those criteria.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 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.

(c) Changes in internal control over financial reporting

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

47

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

DTE Energy Company

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of DTE Energy Company and its subsidiaries at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying indexpresents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

/s/ PricewaterhouseCoopers LLP

Detroit, Michigan

February 14, 2014

48

DTE Energy Company

Consolidated Statements of Operations

	Year Ended December 31
	2013			2012			2011
	(In millions, except per share amounts)
Operating Revenues	$	9,661		$	8,791		$	8,858
Operating Expenses
Fuel, purchased power and gas	4,055			3,296			3,537
Operation and maintenance	2,978			2,892			2,612
Depreciation, depletion and amortization	1,094			995			977
Taxes other than income	340			332			310
Asset (gains) and losses, reserves and impairments, net	(9		)	(3		)	1
	8,458			7,512			7,437
Operating Income	1,203			1,279			1,421
Other (Income) and Deductions
Interest expense	436			440			488
Interest income	(9		)	(10		)	(10		)
Other income	(201		)	(173		)	(117		)
Other expenses	55			62			69
	281			319			430
Income Before Income Taxes	922			960			991
Income Tax Expense	254			286			268
Income from Continuing Operations	668			674			723
Loss from Discontinued Operations, net of tax	—			(56		)	(3		)
Net Income	668			618			720
Less: Net Income Attributable to Noncontrolling Interest	7			8			9
Net Income Attributable to DTE Energy Company	$	661		$	610		$	711
Basic Earnings per Common Share
Income from continuing operations	$	3.76		$	3.89		$	4.21
Loss from discontinued operations, net of tax	—			(0.33		)	(0.02		)
Total	$	3.76		$	3.56		$	4.19
Diluted Earnings per Common Share
Income from continuing operations	$	3.76		$	3.88		$	4.20
Loss from discontinued operations, net of tax	—			(0.33		)	(0.02		)
Total	$	3.76		$	3.55		$	4.18
Weighted Average Common Shares Outstanding
Basic	175			171			169
Diluted	175			172			170
Dividends Declared per Common Share	$	2.59		$	2.42		$	2.32

See Notes to Consolidated Financial Statements

49

DTE Energy Company

Consolidated Statements of Comprehensive Income

	Year Ended December 31,
	2013			2012			2011
	(In millions)
Net income	$	668		$	618		$	720
Other comprehensive income (loss), net of tax:
Benefit obligations, net of taxes of $13, $(1) and $(5)	22			(2		)	(9		)
Net unrealized gains on investments during the period, net of taxes of $1, $1 and $—	2			1			—
Foreign currency translation, net of taxes of $(1), $— and $—	(2		)	1			—
Other comprehensive income (loss)	22			—			(9		)
Comprehensive income	690			618			711
Less comprehensive income attributable to noncontrolling interests	7			8			9
Comprehensive income attributable to DTE Energy Company	$	683		$	610		$	702

See Notes to Consolidated Financial Statements

50

DTE Energy Company

Consolidated Statements of Cash Flows

	Year Ended December 31
	2013			2012			2011
	(In millions)
Operating Activities
Net income	$	668		$	618		$	720
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	1,094			1,018			995
Nuclear fuel amortization	38			29			46
Allowance for equity funds used during construction	(15		)	(13		)	(6		)
Deferred income taxes	164			47			220
Loss on sale of non-utility business	—			83			—
Asset (gains) and losses, reserves and impairments, net	(8		)	1			(21		)
Changes in assets and liabilities:
Accounts receivable, net	(154		)	52			71
Inventories	123			35			(129		)
Accounts payable	14			40			(23		)
Derivative assets and liabilities	107			53			(94		)
Accrued pension obligation	(644		)	280			432
Accrued postretirement obligation	(526		)	(323		)	209
Regulatory assets and liabilities	1,269			278			(662		)
Other assets	(24		)	55			44
Other liabilities	48			(44		)	206
Net cash from operating activities	2,154			2,209			2,008
Investing Activities
Plant and equipment expenditures — utility	(1,534		)	(1,451		)	(1,382		)
Plant and equipment expenditures — non-utility	(342		)	(369		)	(102		)
Proceeds from sale of non-utility business	—			255			—
Proceeds from sale of assets	36			38			18
Restricted cash for debt redemption, principally Securitization	(1		)	2			(5		)
Acquisition, net of cash acquired	—			(198		)	—
Proceeds from sale of nuclear decommissioning trust fund assets	1,118			759			833
Investment in nuclear decommissioning trust funds	(1,134		)	(764		)	(850		)
Other	(49		)	(41		)	(72		)
Net cash used for investing activities	(1,906		)	(1,769		)	(1,560		)
Financing Activities
Issuance of long-term debt, net of issuance costs	1,234			759			1,179
Redemption of long-term debt	(961		)	(639		)	(1,455		)
Short-term borrowings, net	(109		)	(179		)	269
Issuance of common stock	39			39			—
Repurchase of common stock	—			—			(18		)
Dividends on common stock	(445		)	(407		)	(389		)
Other	(19		)	(16		)	(31		)
Net cash used for financing activities	(261		)	(443		)	(445		)
Net Increase (Decrease) in Cash and Cash Equivalents	(13		)	(3		)	3
Cash and Cash Equivalents at Beginning of Period	65			68			65
Cash and Cash Equivalents at End of Period	$	52		$	65		$	68
Supplemental disclosure of cash information
Cash paid (received) for:
Interest (net of interest capitalized)	$	418		$	438		$	485
Income taxes	$	121		$	173		$	(205	)
Supplemental disclosure of non-cash information
Common stock issued for employee benefit and compensation plans	$	293		$	155		$	15
Plant and equipment expenditures in accounts payable	$	329		$	235		$	212

See Notes to Consolidated Financial Statements

51

DTE Energy Company

Consolidated Statements of Financial Position

	December 31
	2013			2012
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	52		$	65
Restricted cash, principally Securitization	123			122
Accounts receivable (less allowance for doubtful accounts of $55 and $62, respectively)
Customer	1,542			1,336
Other	127			126
Inventories
Fuel and gas	363			527
Materials and supplies	265			234
Derivative assets	99			108
Regulatory assets	26			182
Other	209			215
	2,806			2,915
Investments
Nuclear decommissioning trust funds	1,191			1,037
Other	603			554
	1,794			1,591
Property
Property, plant and equipment	25,123			23,631
Less accumulated depreciation, depletion and amortization	(9,323		)	(8,947		)
	15,800			14,684
Other Assets
Goodwill	2,018			2,018
Regulatory assets	2,837			4,235
Securitized regulatory assets	231			413
Intangible assets	122			135
Notes receivable	102			112
Derivative assets	27			39
Other	198			197
	5,535			7,149
Total Assets	$	25,935		$	26,339

See Notes to Consolidated Financial Statements

52

DTE Energy Company

Consolidated Statements of Financial Position — (Continued)

	December 31
	2013			2012
	(In millions, except shares)
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	962		$	848
Accrued interest	90			93
Dividends payable	116			107
Short-term borrowings	131			240
Current portion long-term debt, including capital leases	898			817
Derivative liabilities	195			125
Regulatory liabilities	302			89
Other	495			449
	3,189			2,768
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	6,618			6,220
Securitization bonds	105			302
Junior subordinated debentures	480			480
Capital lease obligations	11			12
	7,214			7,014
Other Liabilities
Deferred income taxes	3,321			3,191
Regulatory liabilities	862			1,031
Asset retirement obligations	1,827			1,719
Unamortized investment tax credit	47			56
Derivative liabilities	43			26
Accrued pension liability	653			1,498
Accrued postretirement liability	350			1,160
Nuclear decommissioning	178			159
Other	297			306
	7,578			9,146
Commitments and Contingencies (Notes 11 and 19)
Equity
Common stock, without par value, 400,000,000 shares authorized, 177,087,230 and 172,351,680 shares issued and outstanding, respectively	3,907			3,587
Retained earnings	4,150			3,944
Accumulated other comprehensive loss	(136		)	(158		)
Total DTE Energy Company Equity	7,921			7,373
Noncontrolling interests	33			38
Total Equity	7,954			7,411
Total Liabilities and Equity	$	25,935		$	26,339

See Notes to Consolidated Financial Statements

53

DTE Energy Company

Consolidated Statements of Changes in Equity

									Accumulated Other Comprehensive Loss			Non-Controlling Interests
	Common Stock					Retained Earnings
	Shares		Amount												Total
	(Dollars in millions, shares in thousands)
Balance, December 31, 2010	169,428		$	3,440		$	3,431		$	(149	)	$	45		$	6,767
Net income	—		—			711			—			9			720
Dividends declared on common stock	—		—			(392		)	—			—			(392		)
Repurchase of common stock	(1,184	)	(58		)	—			—			—			(58		)
Benefit obligations, net of tax	—		—			—			(9		)	—			(9		)
Stock-based compensation, distributions to noncontrolling interests and other	1,003		35			—			—			(10		)	25
Balance, December 31, 2011	169,247		$	3,417		$	3,750		$	(158	)	$	44		$	7,053
Net Income	—		—			610			—			8			618
Dividends declared on common stock	—		—			(414		)	—			—			(414		)
Issuance of common stock	684		39			—			—			—			39
Contribution of common stock to pension plan	1,335		80			—			—			—			80
Foreign currency translation, net of tax	—		—			—			1			—			1
Benefit obligations, net of tax	—		—			—			(2		)	—			(2		)
Net change in unrealized losses on investments, net of tax	—		—			—			1			—			1
Stock-based compensation, distributions to noncontrolling interests and other	1,086		51			(2		)	—			(14		)	35
Balance, December 31, 2012	172,352		$	3,587		$	3,944		$	(158	)	$	38		$	7,411
Net Income	—		—			661			—			7			668
Dividends declared on common stock	—		—			(454		)	—			—			(454		)
Issuance of common stock	589		39			—			—			—			39
Contribution of common stock to pension plan	3,026		200			—			—			—			200
Foreign currency translation, net of tax	—		—			—			(2		)	—			(2		)
Benefit obligations, net of tax	—		—			—			22			—			22
Net change in unrealized losses on investments, net of tax	—		—			—			2			—			2
Stock-based compensation, distributions to noncontrolling interests and other	1,120		81			(1		)	—			(12		)	68
Balance, December 31, 2013	177,087		$	3,907		$	4,150		$	(136	)	$	33		$	7,954

See Notes to Consolidated Financial Statements

54

DTE Energy Company

Notes to Consolidated Financial Statements

NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION

Corporate Structure

DTE Energy owns the following businesses:

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

• DTE Gas, a natural gas utility engaged in the purchase, storage, transportation, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan and the sale of storage and transportation capacity; and

• Other businesses involved in 1) natural gas pipelines, gathering and storage; 2) power and industrial projects; and 3) energy marketing and trading operations.

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

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

Basis of Presentation

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

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

Principles of Consolidation

The Company consolidates all majority-owned subsidiaries and investments in entities in which it has controlling influence. Non-majority owned investments are accounted for using the equity method when the Company is able to influence the operating policies of the investee. 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.

55

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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. 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 and are consolidated when the Company is the primary beneficiary. In addition, 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, 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, 2013 and 2012. All assets and liabilities of a consolidated VIE are presented where it has been determined that 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. VIEs, in which the Company holds a majority voting interest and is the primary beneficiary, that meet the definition of a business and whose assets can be used for purposes other than the settlement of the VIE's obligations have been excluded from the table below.

	December 31, 2013						December 31, 2012
	Securitization		Other		Total		Securitization		Other		Total
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	12	$	12	$	—	$	10	$	10
Restricted cash	100		8		108		102		7		109
Accounts receivable	34		16		50		34		7		41
Inventories	—		118		118		—		141		141
Other current assets	—		1		1		—		1		1
Property, plant and equipment	—		99		99		—		93		93
Securitized regulatory assets	231		—		231		413		—		413
Other assets	4		8		12		7		11		18
	$	369	$	262	$	631	$	556	$	270	$	826
LIABILITIES
Accounts payable and accrued current liabilities	$	7	$	23	$	30	$	11	$	14	$	25
Current portion long-term debt, including capital leases	196		9		205		177		8		185
Current regulatory liabilities	43		—		43		50		—		50
Other current liabilities	—		4		4		—		4		4
Mortgage bonds, notes and other	—		21		21		—		25		25
Securitization bonds	105		—		105		302		—		302
Capital lease obligations	—		7		7		—		11		11
Other long-term liabilities	8		2		10		7		2		9
	$	359	$	66	$	425	$	547	$	64	$	611

56

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

	December 31, 2013		December 31, 2012
	(In millions)
Other investments	$	141	$	130
Notes receivable	$	8	$	6

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

Revenues

Revenues from the sale and delivery of electricity, and the sale, delivery and storage of natural gas are recognized as services are provided. DTE Electric and DTE Gas record revenues for electricity and gas provided but unbilled at the end of each month. Rates for DTE Electric and DTE Gas include provisions to adjust billings for fluctuations in fuel and purchased power costs, cost of natural gas and certain other costs. Revenues are adjusted for differences between actual costs subject to reconciliation and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are recorded on the Consolidated Statements of Financial Position and are recovered or returned to customers through adjustments to the billing factors.

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

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

Other Income

Other income is recognized for non-operating income such as equity earnings, interest and dividends, allowance for funds using during construction and contract services. Power & Industrial Projects also recognizes Other income in connection with the sale of membership interests in reduced emissions fuel facilities to investors. In exchange for the cash received, the investors will receive a portion of the economic attributes of the facilities, including income tax attributes. The transactions are not treated as a sale of membership interests for financial reporting purposes. Other income is considered earned when refined coal is produced and tax credits are generated. Power & Industrial Projects recognized approximately $81 million, $63 million, and $15 million of Other income for the years ended December 31, 2013, 2012, and 2011, respectively.

Accounting for ISO Transactions

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

Energy Trading participates in the energy markets through various independent system operators and regional transmission organizations (ISOs and RTOs). These markets require that Energy Trading submits hourly day-ahead, real-time bids and offers for energy at locations across each region. 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 trading contracts which are presented on a net basis in Operating Revenues in the Consolidated Statements of Operations.

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

57

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Comprehensive Income (Loss)

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 tables, amounts recorded to accumulated other comprehensive loss for the year ended December 31, 2013 include unrealized gains and losses from derivatives accounted for as cash flow hedges, unrealized gains and losses on available-for-sale securities, the Company’s interest in 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.

	Changes in Accumulated Other Comprehensive Loss by Component (a)
	For The Year Ended December 31, 2013
	Net Unrealized Gain/(Loss) on Derivatives			Net Unrealized Gain/(Loss) on Investments			Benefit Obligations (b)			Foreign Currency Translation			Total
	(In millions)
Beginning balances December 31, 2012	$	(4	)	$	(8	)	$	(148	)	$	2		$	(158	)
Other comprehensive income (loss) before reclassifications	—			2			13			(2		)	13
Amounts reclassified from accumulated other comprehensive income (loss)	—			—			9			—			9
Net current-period other comprehensive income (loss)	—			2			22			(2		)	22
Ending balances December 31, 2013	$	(4	)	$	(6	)	$	(126	)	$	—		$	(136	)

______________________________________

(a) All amounts are net of tax.

(b) The amounts reclassified from accumulated other comprehensive income (loss) are included in the computation of the net periodic pension and other postretirement benefit costs (see Note 20).

Cash Equivalents and Restricted Cash

Cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with remaining maturities of three months or less. Restricted cash consists of funds held to satisfy requirements of certain debt, primarily Securitization bonds, and partnership operating agreements. Restricted cash designated for interest and principal payments within one year is classified as a current asset.

Receivables

Accounts receivable are primarily composed of trade receivables and unbilled revenue. Our accounts receivable are stated at net realizable value.

The allowance for doubtful accounts for DTE Electric and DTE Gas is generally calculated using the aging approach that utilizes rates developed in reserve studies. We establish an allowance for uncollectible accounts based on historical losses and management’s assessment of existing economic conditions, customer trends, and other factors. Customer accounts are generally considered delinquent if the amount billed is not received by the due date, which is typically in 21 days, however, factors such as assistance programs may delay aggressive action. We assess late payment fees on trade receivables based on past-due terms with customers. Customer accounts are written off when collection efforts have been exhausted. The time period for write-off is 150 days after service has been terminated.

The customer allowance for doubtful accounts for our other businesses is calculated based on specific review of probable future collections based on receivable balances in excess of 30 days.

Unbilled revenues of $815 million and $686 million are included in customer accounts receivable at December 31, 2013 and 2012, respectively.

58

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Notes Receivable

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

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

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

Inventories

The Company generally values inventory at average cost.

Natural gas inventory of $4 million and $37 million as of December 31, 2013 and 2012, respectively, at DTE Gas is determined using the last-in, first-out (LIFO) method. At December 31, 2013, the replacement cost of gas remaining in storage exceeded the LIFO cost by $170 million. At December 31, 2012, the replacement cost of gas remaining in storage exceeded the LIFO cost by $113 million.

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

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

Utility property at DTE Electric and DTE Gas is depreciated over its estimated useful life using straight-line rates approved by the MPSC.

Non-utility property is depreciated over its estimated useful life using the straight-line and units of production methods.

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

Approximately $26 million and $12 million of expenses related to Fermi 2 refueling outages were accrued at December 31, 2013 and 2012, respectively. Amounts are accrued on a pro-rata basis, generally over an 18-month period, that coincides with scheduled refueling outages at Fermi 2. This accrual of outage costs matches the regulatory recovery of these costs in rates set by the MPSC. See Note 11.

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

Long-Lived Assets

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

59

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Intangible Assets

The Company has certain intangible assets relating to emission allowances, renewable energy credits and non-utility contracts as shown below:

	December 31,		December 31,
	2013		2012
	(In millions)
Emission allowances	$	2	$	6
Renewable energy credits	51		44
Contract intangible assets	126		139
	179		189
Less accumulated amortization	45		34
Intangible assets, net	134		155
Less current intangible assets	12		20
	$	122	$	135

Emission allowances and renewable energy credits are charged to expense, using average cost, as the allowances and credits are consumed in the operation of the business. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 1 to 28 years. Intangible assets amortization expense was $14 million in 2013, $6 million in 2012 and $5 million in 2011.

The following table summarizes the estimated amortization expense expected to be recognized during each year through 2018:

Estimated amortization expense	(In millions)
2014	$	13
2015	$	12
2016	$	11
2017	$	8
2018	$	8

Excise and Sales Taxes

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

Deferred Debt Costs

The costs related to the issuance of long-term debt are deferred and amortized over the life of each debt issue. In accordance with MPSC regulations applicable to the Company’s electric and gas utilities, the unamortized discount, premium and expense related to 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.

Investments in Debt and Equity Securities

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

60

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Government Grants

Grants are recognized when there is reasonable assurance that the grant will be received and that any conditions associated with the grant will be met. When grants are received related to Property, Plant and Equipment, the Company reduces the 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.

DTE Energy Foundation

Charitable contributions to the DTE Energy Foundation were $18 million, $21 million, and $21 million for the years ended December 31, 2013, 2012 and 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.

Other Accounting Policies

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

Note	Title
3	Fair Value
4	Financial and Other Derivative Instruments
10	Asset Retirement Obligations
11	Regulatory Matters
12	Income Taxes
21	Stock-based Compensation

NOTE 3 — FAIR VALUE

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

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

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

61

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

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

	December 31, 2013															December 31, 2012
	Level 1			Level 2			Level 3			Netting (a)			Net Balance			Level 1			Level 2			Level 3			Netting (a)			Net Balance
	(In millions)
Assets:
Cash equivalents (b)	$	10		$	115		$	—		$	—		$	125		$	—		$	123		$	—		$	—		$	123
Nuclear decommissioning trusts	779			412			—			—			1,191			694			343			—			—			1,037
Other investments (c) (d)	92			44			—			—			136			66			44			—			—			110
Derivative assets:
Commodity Contracts:
Natural Gas	273			89			34			(382		)	14			555			66			24			(605		)	40
Electricity	—			261			139			(291		)	109			—			226			134			(258		)	102
Other	33			1			3			(34		)	3			6			3			2			(6		)	5
Total derivative assets	306			351			176			(707		)	126			561			295			160			(869		)	147
Total	$	1,187		$	922		$	176		$	(707	)	$	1,578		$	1,321		$	805		$	160		$	(869	)	$	1,417
Liabilities:
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(277	)	$	(140	)	$	(86	)	$	395		$	(108	)	$	(526	)	$	(73	)	$	(62	)	$	605		$	(56	)
Electricity	—			(272		)	(126		)	269			(129		)	—			(240		)	(111		)	258			(93		)
Other	(32		)	(2		)	—			34			—			(6		)	(1		)	—			6			(1		)
Other derivative contracts (f)	—			(1		)	—			—			(1		)	—			(1		)	—			—			(1		)
Total derivative liabilities	(309		)	(415		)	(212		)	698			(238		)	(532		)	(315		)	(173		)	869			(151		)
Total	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)
Net Assets (liabilities) at the end of the period	$	878		$	507		$	(36	)	$	(9	)	$	1,340		$	789		$	490		$	(13	)	$	—		$	1,266
Assets:
Current	$	277		$	400		$	139		$	(592	)	$	224		$	493		$	372		$	120		$	(754	)	$	231
Noncurrent (e)	910			522			37			(115		)	1,354			828			433			40			(115		)	1,186
Total Assets	$	1,187		$	922		$	176		$	(707	)	$	1,578		$	1,321		$	805		$	160		$	(869	)	$	1,417
Liabilities:
Current	$	(268	)	$	(328	)	$	(177	)	$	578		$	(195	)	$	(466	)	$	(269	)	$	(144	)	$	754		$	(125	)
Noncurrent	(41		)	(87		)	(35		)	120			(43		)	(66		)	(46		)	(29		)	115			(26		)
Total Liabilities	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)
Net Assets (liabilities) at the end of the period	$	878		$	507		$	(36	)	$	(9	)	$	1,340		$	789		$	490		$	(13	)	$	—		$	1,266

_______________________________________

(a) Amounts represent the impact of master netting agreements that allow the Company to net gain and loss positions and cash collateral held or placed with the same counterparties.

(b) At December 31, 2013, available-for-sale securities of $125 million included $109 million and $16 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively. At December 31, 2012, available-for-sale securities of $123 million, included $109 million and $14 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively.

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

(d) Available-for-sale equity securities of $7 million at December 31, 2013 and $5 million at December 31, 2012 are included in Other investments on the Consolidated Statements of Financial Position.

(e) Includes $136 million and $110 million of Other investments that are included in the Consolidated Statements of Financial Position in Other investments at December 31, 2013 and 2012, respectively.

(f) Includes Interest rate contracts and Foreign currency exchange contracts.

62

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Cash Equivalents

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

Nuclear Decommissioning Trusts and Other Investments

The nuclear decommissioning trusts and other investments hold debt and equity securities directly and indirectly through institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices in actively traded markets. The 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 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 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 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

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.

63

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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, 2013 and 2012:

	Year Ended December 31, 2013												Year Ended December 31, 2012
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of December 31	$	(38	)	$	23		$	2		$	(13	)	$	6		$	32		$	6		$	44
Transfers into Level 3	1			—			—			1			1			—			—			1
Total gains (losses):
Included in earnings	(32		)	75			—			43			(41		)	101			—			60
Recorded in regulatory assets/liabilities	—			—			5			5			—			—			15			15
Purchases, issuances and settlements:
Purchases	(8		)	1			—			(7		)	—			2			—			2
Issuances	—			(1		)	—			(1		)	—			—			—			—
Settlements	25			(85		)	(4		)	(64		)	(4		)	(112		)	(19		)	(135		)
Net Assets (Liabilities) as of December 31	$	(52	)	$	13		$	3		$	(36	)	$	(38	)	$	23		$	2		$	(13	)
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at December 31, 2013 and 2012 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(49	)	$	48		$	—		$	(1	)	$	(33	)	$	91		$	—		$	58

Derivatives are transferred between levels primarily due to changes in the source data used to construct price curves as a result of changes in market liquidity. Transfers in and transfers out are reflected as if they had occurred at the beginning of the period. The following table shows transfers between the levels of the fair value hierarchy for the years ended December 31, 2013 and 2012:

	Year Ended December 31, 2013					Year Ended December 31, 2012
	Level 1	Level 2		Level 3		Level 1	Level 2		Level 3
	(In millions)
Transfers into Level 1 from	$ N/A	$	—	$	—	$ N/A	$	—	$	—
Transfers into Level 2 from	—	N/A		—		—	N/A		—
Transfers into Level 3 from	—	1		N/A		—	1		N/A

The following table presents the unobservable inputs related to Level 3 assets and liabilities as of December 31, 2013 and 2012:

	December 31, 2013
Commodity Contracts	Derivative Assets		Derivative Liabilities			Valuation Techniques	Unobservable Input	Range							Weighted Average
	(In millions)
Natural Gas	$	34	$	(86	)	Discounted Cash Flow	Forward basis price (per MMBtu)	$	(0.88	)	—	$	5.07	/MMBtu	$	(0.16	)/MMBtu
Electricity	$	139	$	(126	)	Discounted Cash Flow	Forward basis price (per MWh)	$	(7	)	—	$	15	/MWh	$	3	/MWh

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

64

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

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

Fair Value of Financial Instruments

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

The following table presents the carrying amount and fair value of financial instruments as of December 31, 2013 and 2012:

	December 31, 2013								December 31, 2012
	Carrying		Fair Value						Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Amount		Level 1		Level 2		Level 3
	(In millions)
Notes receivable, excluding capital leases	$	41	$	—	$	—	$	41	$	39	$	—	$	—	$	39
Dividends payable	$	116	$	116	$	—	$	—	$	107	$	107	$	—	$	—
Short-term borrowings	$	131	$	—	$	131	$	—	$	240	$	—	$	240	$	—
Long-term debt	$	8,094	$	425	$	7,551	$	499	$	7,813	$	507	$	7,453	$	933

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

Nuclear Decommissioning Trust Funds

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

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

	December 31, 2013		December 31, 2012
	(In millions)
Fermi 2	$	1,172	$	1,021
Fermi 1	3		3
Low level radioactive waste	16		13
Total	$	1,191	$	1,037

65

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

	Year Ended December 31
	2013			2012			2011
	(In millions)
Realized gains	$	83		$	37		$	46
Realized losses	$	(41	)	$	(31	)	$	(38	)
Proceeds from sales of securities	$	1,118		$	759		$	833

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

	December 31, 2013				December 31, 2012
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
	(In millions)
Equity securities	$	730	$	201	$	631	$	122
Debt securities	442		12		399		27
Cash and cash equivalents	19		—		7		—
	$	1,191	$	213	$	1,037	$	149

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.

Unrealized losses incurred by the Fermi 2 trust are recognized as a Regulatory asset. DTE Electric recognized $31 million and $44 million of unrealized losses as Regulatory assets at December 31, 2013 and 2012, respectively. Since the decommissioning of Fermi 1 is funded by DTE Electric rather than through a regulatory recovery mechanism, there is no corresponding regulatory asset treatment. Therefore, unrealized losses incurred by the Fermi 1 trust are recognized in earnings immediately. There were no unrealized losses recognized in 2013, 2012 and 2011 for Fermi 1.

Other Securities

At December 31, 2013 and 2012, the securities were comprised primarily of money-market and equity securities. During the years ended December 31, 2013 and 2012, no amounts of unrealized losses on available-for-sale securities were reclassified out of other comprehensive income and realized into net income for the periods. Gains related to trading securities held at December 31, 2013, 2012, and 2011 were $22 million, $11 million and $4 million, respectively.

66

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 4 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

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

The Company’s primary market risk exposure is associated with commodity prices, credit and interest rates. The Company has risk management policies to monitor and manage market risks. The Company uses derivative instruments to manage some of the exposure. The Company uses derivative instruments for trading purposes in its Energy Trading segment. Contracts classified as derivative instruments include power, natural gas, oil and certain coal forwards, futures, options and swaps, and foreign currency exchange contracts. Items not classified as derivatives include natural gas inventory, pipeline transportation contracts, renewable energy credits and natural gas storage assets.

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

Gas — DTE Gas purchases, stores, transports, distributes and sells natural gas and sells storage and transportation capacity. DTE Gas has fixed-priced contracts for portions of its expected gas supply requirements through 2016. Substantially all of these contracts meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. DTE Gas may also sell forward transportation and storage capacity contracts. Forward transportation and storage contracts are generally not derivatives and are therefore accounted for under the accrual method.

Gas Storage and Pipelines — This segment is primarily engaged in services related to the transportation and storage of natural gas. Primarily fixed-priced contracts are used in the marketing and management of transportation and storage services. Generally these contracts are not derivatives and are therefore accounted for under the accrual method.

Power and Industrial Projects — This segment manages and operates energy and pulverized coal projects, coke batteries, reduced emissions fuel projects, landfill gas recovery and power generation assets. Primarily fixed-price contracts are used in the marketing and management of the segment assets. These contracts are generally not derivatives and are therefore accounted for under the accrual method.

Energy Trading — Commodity Price Risk — Energy Trading markets and trades electricity, coal, natural gas physical products and energy financial instruments, and provides energy and asset management services utilizing energy commodity derivative instruments. Forwards, futures, options and swap agreements are used to manage exposure to the risk of market price and volume fluctuations in its operations. These derivatives are accounted for by recording changes in fair value to earnings unless hedge accounting criteria are met.

Energy Trading — Foreign Currency Exchange Risk — Energy Trading has foreign currency exchange forward contracts to economically hedge fixed Canadian dollar commitments existing under natural gas and power purchase and sale contracts and natural gas transportation contracts. The Company enters into these contracts to mitigate price volatility with respect to fluctuations of the Canadian dollar relative to the U.S. dollar. These derivatives are accounted for by recording changes in fair value to earnings unless hedge accounting criteria are met.

67

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Corporate and Other — Interest Rate Risk — The Company uses interest rate swaps, treasury locks and other derivatives to hedge the risk associated with interest rate market volatility. In 2004 and 2000, the Company entered into a series of interest rate derivatives to limit its sensitivity to market interest rate risk associated with the issuance of long-term debt. Such instruments were designated as cash flow hedges. The Company subsequently issued long-term debt and terminated these hedges at a cost that is included in Other comprehensive loss. Amounts recorded in Other comprehensive loss will be reclassified to interest expense through 2033. In 2014, the Company estimates reclassifying less than $1 million of losses to earnings.

Credit Risk — The utility and non-utility businesses are exposed to credit risk if customers or counterparties do not comply with their contractual obligations. The Company maintains credit policies that significantly minimize overall credit risk. These policies include an evaluation of potential customers’ and counterparties’ financial condition, credit rating, collateral requirements or other credit enhancements such as letters of credit or guarantees. The Company generally uses standardized agreements that allow the netting of positive and negative transactions associated with a single counterparty. The Company maintains a provision for credit losses based on factors surrounding the credit risk of its customers, historical trends, and other information. Based on the Company’s credit policies and its December 31, 2013 and 2012 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to have a material adverse effect on the Company’s financial statements.

Derivative Activities

The Company manages its mark-to-market (MTM) risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, it records and manages the energy purchase and sale obligations under its contracts in separate components based on the commodity (e.g. electricity or 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 following describes the categories of activities represented by their operating characteristics and key risks:

• Asset Optimization — Represents derivative activity associated with assets owned and contracted by DTE Energy, including forward natural gas purchases and sales, natural gas transportation and storage capacity. Changes in the value of derivatives in this category typically economically offset changes in the value of underlying non-derivative positions, which do not qualify for fair value accounting. The difference in accounting treatment of derivatives in this category and the underlying non-derivative positions can result in significant earnings volatility.

• Marketing and Origination — Represents derivative activity transacted by originating substantially hedged positions with wholesale energy marketers, producers, end users, utilities, retail aggregators and alternative energy suppliers.

• Fundamentals Based Trading — Represents derivative activity transacted with the intent of taking a view, capturing market price changes, or putting capital at risk. This activity is speculative in nature as opposed to hedging an existing exposure.

• Other — Includes derivative activity at DTE Electric related to FTRs. Changes in the value of derivative contracts at DTE Electric are recorded as Derivative Assets or Liabilities, with an offset to Regulatory Assets or Liabilities as the settlement value of these contracts will be included in the PSCR mechanism when realized.

68

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The following tables present the fair value of derivative instruments as of December 31, 2013 and 2012:

	December 31, 2013					December 31, 2012
	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	—		$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	—	$	(1	)	$	—	$	—
Commodity Contracts:
Natural Gas	396		(503		)	645		(661		)
Electricity	400		(398		)	360		(351		)
Other	37		(34		)	11		(7		)
Total derivatives not designated as hedging instruments:	$	833	$	(936	)	$	1,016	$	(1,019	)
Total derivatives:
Current	$	691	$	(773	)	$	862	$	(879	)
Noncurrent	142		(163		)	154		(141		)
Total derivatives	$	833	$	(936	)	$	1,016	$	(1,020	)

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.

For contracts with certain clearing agents the fair value of derivative instruments is netted against realized positions with the net balance reflected as either 1) a derivative asset or liability or 2) an account receivable or payable. Other than certain clearing agents, accounts receivable and accounts payable that are subject to netting arrangements have not been offset against the fair value of derivative assets and liabilities. Certain contracts that have netting arrangements have not been offset in the Consolidated Statements of Financial Position. The impact of netting these derivative instruments and cash collateral related to such contracts is not material. Only the gross amounts for these derivative instruments are included in the table below.

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.

69

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The following table presents the netting offsets of derivative assets and liabilities at December 31, 2013 and 2012:

	December 31, 2013									December 31, 2012
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position			Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position
	(In millions)
Derivative assets:
Commodity Contracts:
Natural Gas	$	396		$	(382	)	$	14		$	645		$	(605	)	$	40
Electricity	400			(291		)	109			360			(258		)	102
Other	37			(34		)	3			11			(6		)	5
Total derivative assets	$	833		$	(707	)	$	126		$	1,016		$	(869	)	$	147
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(503	)	$	395		$	(108	)	$	(661	)	$	605		$	(56	)
Electricity	(398		)	269			(129		)	(351		)	258			(93		)
Other	(34		)	34			—			(7		)	6			(1		)
Other derivative liabilities	(1		)	—			(1		)	(1		)	—			(1		)
Total derivative liabilities	$	(936	)	$	698		$	(238	)	$	(1,020	)	$	869		$	(151	)

The following table presents the netting offsets of derivative assets and liabilities at December 31, 2013 and 2012:

	December 31, 2013												December 31, 2012
	Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent			Current			Noncurrent			Current			Noncurrent
	(In millions)
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	691		$	142		$	(773	)	$	(163	)	$	862		$	154		$	(879	)	$	(141	)
Counterparty netting	(566		)	(115		)	566			115			(754		)	(115		)	754			115
Collateral adjustment	(26		)	—			12			5			—			—			—			—
Total derivatives as reported	$	99		$	27		$	(195	)	$	(43	)	$	108		$	39		$	(125	)	$	(26	)

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

	Location of Gain (Loss) Recognized in Income on Derivatives	Gain (Loss) Recognized in Income on Derivatives for Years Ended December 31
Derivatives not Designated as Hedging Instruments		2013			2012
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	(1	)	$	—
Commodity Contracts:
Natural Gas	Operating Revenue	(48		)	(29		)
Natural Gas	Fuel, purchased power and gas	(44		)	25
Electricity	Operating Revenue	82			64
Other	Operating Revenue	—			5
Total		$	(11	)	$	65

70

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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.

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

Commodity	Number of Units
Natural Gas (MMBtu)	795,553,773
Electricity (MWh)	55,658,483
Foreign Currency Exchange ($ CAD)	65,074,206
FTR (MWh)	10,485,618

Various 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, 2013, DTE Energy's contractual obligation in the form of cash or letter of credit in the event of a downgrade to below investment grade, under both hard trigger and soft trigger provisions, was approximately $406 million.

As of December 31, 2013, the Company had approximately $1,176 million of derivatives in net liability positions, for which hard triggers exist. Collateral of approximately $25 million has been posted against such liabilities, including cash and letters of credit. Associated derivative net asset positions for which contractual offset exists were approximately $902 million. The net remaining amount of approximately $249 million is derived from the $406 million noted above.

NOTE 5 — GOODWILL

The Company has goodwill resulting from purchase business combinations.

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

	2013		2012
	(In millions)
Balance as of January 1	$	2,018	$	2,020
Goodwill attributable to sale of Unconventional Gas Production business	—		(2		)
Balance at December 31	$	2,018	$	2,018

NOTE 6 — ACQUISITION

In the fourth quarter of 2012, the Company closed on the purchase of a portfolio of fourteen on-site energy projects from subsidiaries of Duke Energy Corporation and GDF Suez Energy North America, Inc. This acquisition provided a growth opportunity for the Company's Power and Industrial Projects segment that leverages its extensive energy-related operating experience and project management capabilities.

71

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The purchase of equity interests ranged from 46 percent to 100 percent of the project companies for a total purchase price of approximately $294 million, which consisted of $220 million paid in cash and assumption of approximately $74 million of debt. The debt assumed related to two project companies which have been deemed variable interest entities. DTE, however, was determined not to be the primary beneficiary and thus the VIEs' assets and liabilities are not included in the Company's Consolidated Statements of Financial Position. Therefore, the assumed debt was not included in the purchase price allocation table below. There was no exposure to loss related to the debt assumed as the customer of the project companies is obligated to pay the loans in the event of default or termination. The following table summarizes the fair value of the assets acquired and liabilities assumed as of the closing date:

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

The intangible assets recorded as a result of the acquisition pertained to existing contracts and agreements, which were valued at approximately $75 million as of the closing date. The intangible assets are amortized on a straight line basis over a weighted-average amortization period of approximately eight years. The Company did not record any goodwill due to the acquisition.

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

NOTE 7 — DISCONTINUED OPERATIONS

Sale of Unconventional Gas Production Business

In December 2012, the Company sold its 100% equity interest in its Unconventional Gas Production business which consisted of gas and oil production assets in the western Barnett and Marble Falls shale areas of Texas. The sale resulted in gross proceeds of approximately $255 million, which resulted in a pre-tax loss of approximately $83 million ($55 million after tax). The activity of the discontinued business is shown below. The amounts exclude general corporate overhead costs, and related tax effects, and no portion of corporate interest costs were allocated to discontinued operations.

	2012			2011
	(In millions)
Operating Revenues	$	55		$	39
Operation and Maintenance	24			16
Depreciation, Depletion and Amortization	23			18
Taxes Other Than Income	4			3
Asset (Gains) and Losses, Net	83			—
	134			37
Operating Income (Loss)	(79		)	2
Other (Income) and Deductions	6			6
Loss Before Income Taxes	(85		)	(4		)
Income Tax Expense (Benefit)	(29		)	(1		)
Net Loss Attributable to DTE Energy Company	$	(56	)	$	(3	)

72

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 8 — PROPERTY, PLANT AND EQUIPMENT

Summary of property by classification as of December 31:

	2013			2012
Property, Plant and Equipment	(In millions)
DTE Electric
Generation	$	11,127		$	10,383
Distribution	7,603			7,306
Total DTE Electric	18,730			17,689
DTE Gas
Distribution	2,834			2,704
Storage	431			426
Other	836			852
Total DTE Gas	4,101			3,982
Non-utility and other	2,292			1,960
Total	25,123			23,631
Less Accumulated Depreciation, Depletion and Amortization
DTE Electric
Generation	(4,004		)	(3,880		)
Distribution	(2,947		)	(2,837		)
Total DTE Electric	(6,951		)	(6,717		)
DTE Gas
Distribution	(1,129		)	(1,057		)
Storage	(138		)	(132		)
Other	(338		)	(365		)
Total DTE Gas	(1,605		)	(1,554		)
Non-utility and other	(767		)	(676		)
Total	(9,323		)	(8,947		)
Net Property, Plant and Equipment	$	15,800		$	14,684

The Allowance for Funds used During Construction (AFUDC) capitalized was approximately $23 million and $20 million during 2013 and 2012, respectively.

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

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

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

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

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

Capitalized software costs amortization expense was $71 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 $668 million and $384 million, respectively. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2012 were $608 million and $313 million, respectively.

73

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Gross property under capital leases was $35 million and $32 million at December 31, 2013 and 2012, respectively. Accumulated amortization of property under capital leases was $21 million and $20 million at December 31, 2013 and 2012, respectively.

NOTE 9 — JOINTLY OWNED UTILITY PLANT

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

	Belle River			Ludington Hydroelectric Pumped Storage
In-service date	1984-1985			1973
Total plant capacity	1,270		MW	1,872		MW
Ownership interest	(a)			49		%
Investment in property, plant and equipment (in millions)	$	1,702		$	354
Accumulated depreciation (in millions)	$	969		$	170

_______________________________________

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

Belle River

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

Ludington Hydroelectric Pumped Storage

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

NOTE 10 — ASSET RETIREMENT OBLIGATIONS

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

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

74

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

A reconciliation of the asset retirement obligations for 2013 follows:

	(In millions)
Asset retirement obligations at December 31, 2012	$	1,719
Accretion	106
Liabilities incurred	5
Liabilities settled	(13		)
Revision in estimated cash flows	10
Asset retirement obligations at December 31, 2013	$	1,827

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

In October 2011, the MPSC approved DTE Electric's request for a reduction to the nuclear decommissioning surcharge under the assumption that it would request an extension of the Fermi 2 license for an additional 20 years beyond the term of the existing license which expires in 2025. DTE Electric expects to request the license extension in 2014. This proposed extension of the license, including the associated impact on spent nuclear fuel, resulted in a revision in estimated cash flows for the Fermi 2 asset retirement obligation of approximately $22 million in 2011. It is estimated that the cost of decommissioning Fermi 2 is $1.6 billion in 2013 dollars and $10 billion in 2045 dollars, using a 6% inflation rate. Approximately $1.6 billion of the asset retirement obligations represent nuclear decommissioning liabilities that are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear plant.

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

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

NOTE 11 — REGULATORY MATTERS

Regulation

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

75

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

Regulatory Assets and Liabilities

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

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

	2013			2012
	(In millions)
Assets
Recoverable pension and other postretirement costs:
Pension	$	1,660		$	2,420
Other postretirement costs	—			426
Asset retirement obligation	394			424
Recoverable Michigan income taxes	286			304
Recoverable income taxes related to securitized regulatory assets	126			226
Cost to achieve Performance Excellence Process	75			96
Other recoverable income taxes	71			76
Unamortized loss on reacquired debt	63			63
Deferred environmental costs	59			58
Enterprise Business Systems costs	13			16
Recoverable revenue decoupling	9			28
Choice incentive mechanism	3			66
Accrued PSCR/GCR revenue	—			87
Recoverable restoration expense	—			49
Other	104			78
	2,863			4,417
Less amount included in current assets	(26		)	(182		)
	$	2,837		$	4,235
Securitized regulatory assets	$	231		$	413

76

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

	2013			2012
	(In millions)
Liabilities
Asset removal costs	$	351		$	439
Renewable energy	277			230
Refundable revenue decoupling/deferred gain	127			127
Negative pension offset	84			105
Over recovery of Securitization	72			54
Refundable other postretirement costs	72			—
Accrued PSCR/GCR	65			16
Refundable income taxes	45			56
Energy optimization	31			34
Fermi 2 refueling outage	26			12
Refundable uncollectible expense	12			37
Other	2			10
	$	1,164		$	1,120
Less amount included current liabilities	(302		)	(89		)
	$	862		$	1,031

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

ASSETS

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

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

• Recoverable Michigan income taxes— In July 2007, the Michigan Business Tax (MBT) was enacted by the State of Michigan. State deferred tax liabilities were established for the Company’s utilities, and offsetting regulatory assets were recorded as the impacts of the deferred tax liabilities will be reflected in rates as the related taxable temporary differences reverse and flow through current income tax expense. In May 2011, the MBT was repealed and the Michigan Corporate Income Tax (MCIT) was enacted. The regulatory asset was remeasured to reflect the impact of the MCIT tax rate. (a)

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

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

77

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

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

• Deferred environmental costs — The MPSC approved the deferral of investigation and remediation costs associated with DTE Gas's former MGP sites. Amortization of deferred costs is over a ten-year period beginning in the year after costs were incurred, with recovery (net of any insurance proceeds) through base rate filings. (a)

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

• Recoverable revenue decoupling — Amounts recoverable from DTE Gas customers for the change in revenue resulting from the difference in weather-adjusted average sales per customer compared to the base level of average sales per customer established by the MPSC. The December 2012 order in DTE Gas's rate case required the RDM be discontinued effective November 1, 2012. The order provided for a new RDM, which began in November 2013.

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

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

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

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

_________________________________

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

LIABILITIES

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

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

• Refundable revenue decoupling / deferred gain — Amounts were originally accrued as refundable to DTE Electric customers for the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established by the MPSC. In 2012, the Michigan Court of Appeals issued a decision reversing the MPSC's decision to authorize a RDM for DTE Electric. The revenue decoupling liability was reversed and, after receiving an order from the MPSC to defer the resulting gain for future amortization, DTE Electric created a regulatory liability representing its obligation to refund the gain. The deferred gain will be amortized into earnings in 2014.

• Negative pension offset — DTE Gas's negative pension costs are not included as a reduction to its authorized rates; therefore, the Company is accruing a regulatory liability to eliminate the impact on earnings of the negative pension expense accrued. This regulatory liability will reverse to the extent DTE Gas’s pension expense is positive in future years.

78

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

• Refundable other postretirement costs — Accounting rules for other postretirement benefit costs require, among other things, the recognition in other comprehensive income of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. DTE Electric and DTE Gas record the favorable impact of actuarial gains or losses and prior service credits as a regulatory liability since the impact will reduce expense in a future rate setting process as the deferred items are recognized as a component of net periodic benefit costs.

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

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

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

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

• Refundable uncollectible expense (UETM) — DTE Electric and DTE Gas liability for the MPSC approved uncollectible expense tracking mechanism that tracks the difference in the fluctuation in uncollectible accounts and amounts recognized pursuant to the MPSC authorization. The UETM was terminated for DTE Electric in the October 20, 2011 MPSC rate case order and terminated for DTE Gas in the December 20, 2012 MPSC approval of the partial settlement agreement.

2009 Electric Rate Case Filing - Court of Appeals Decision

In April 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. The COA found that the record of evidence in the January 2010 rate order was insufficient to support the MPSC's authorization to recover costs for the advanced metering infrastructure (AMI) program and remanded this matter to the MPSC. On October 17, 2013, the MPSC issued an order affirming the approximately $8 million rate increase authorized in the MPSC's January 2010 rate order for the AMI program and further concluded that the evidence presented after remand supports the authorized cost recovery.

2010 Electric Rate Case Filing - Court of Appeals Decision

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 AMI program and remanded this matter to the MPSC. The MPSC had approved an approximately $11 million rate increase related to the AMI program in the October 2011 order. DTE Electric is currently operating its AMI program pursuant to the MPSC's approval set forth in the October 2011 order. On August 29, 2013, the MPSC reopened the 2010 electric rate case for the limited purpose of addressing the COA's opinion on AMI. The Company is unable to predict the outcome of this matter or the timing of its resolution.

79

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Transition of the City of Detroit's Public Lighting Department's (PLD) Customers to DTE Electric's Distribution System

Accounting Authority

On June 28, 2013, DTE Electric filed an application for accounting authority to defer certain costs associated with the transition of the City of Detroit's PLD customers to the DTE Electric distribution system over a five to seven year system conversion period. The Company requested authority to defer as a regulatory asset, all net incremental revenue requirement associated with the transition. The net incremental revenue requirement includes costs to install meters and attach customers; system and customer facility upgrades and repairs; and the difference between DTE Electric's tariff rates and any transitional rates approved in the future. On July 11, 2013, the MPSC approved DTE Electric's request to defer, for accounting purposes, the net incremental revenue requirement.

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 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.

Transitional Reconciliation Mechanism (TRM)

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 be requesting recovery, in subsequent PSCR cases, of PLD transmission delivery service costs incurred while DTE Electric 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 recoverable in the PSCR, the Company requested recovery as part of the TRM.

Energy Optimization (EO) Plans

The EO plan is designed to help 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 2013, DTE Electric and DTE Gas filed separate applications for approval of their respective reconciliations of their 2012 EO plan expenses. DTE Electric’s EO reconciliation included a cumulative $26 million net over-recovery and DTE Gas’s EO reconciliation included a cumulative $7 million net over-recovery for their 2012 EO plans. DTE Electric and DTE Gas proposed that the calculated over-recoveries for 2012 be carried forward into 2013 and used as beginning balances for the 2013 reconciliations. On December 6, 2013, the MPSC approved settlement agreements of the DTE Electric and DTE Gas 2012 EO reconciliations that carried forward to 2013 the 2012 over-recoveries. In addition, the MPSC authorized performance incentive surcharges, over a 12-month period effective January 1, 2014, of approximately $10 million and $4 million for DTE Electric and DTE Gas, respectively.

In July 2013, DTE Electric and DTE Gas filed separate applications with the MPSC for the biennial review of their EO plans. On December 19, 2013, the MPSC approved settlement agreements for the EO plans of DTE Electric and DTE Gas.

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

In January 2012, DTE Electric filed an application with the MPSC for approval of the reconciliation of its 2011 RETM and LCT. The Company's 2011 restoration expenses were higher than the amount provided in rates. Accordingly, DTE Electric requested net recovery of approximately $44 million. On February 28, 2013, the MPSC approved a settlement agreement and authorized a $44 million net surcharge to recover the costs over a three-month period beginning April 1, 2013.

DTE Electric Uncollectible Expense True-Up Mechanism (UETM)

In February 2012, DTE Electric filed an application with the MPSC for approval of its UETM for 2011 requesting authority to refund approximately $9 million consisting of costs related to 2011 uncollectible expense. On February 28, 2013, the MPSC approved a settlement agreement and authorized a $9 million credit to refund the over-recovery over a one month period beginning April 1, 2013.

80

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Low Income Energy Assistance Fund (LIEAF)

On July 1, 2013, Michigan Public Act 95 was signed into law and created the LIEAF. The legislation allows the use of a LIEAF funding factor to be determined by the MPSC and assessed on all customer classes of Michigan electric utilities to fund the LIEAF. On July 29, 2013, the MPSC adopted a funding factor of $0.99 per meter per month for all Michigan electric utilities that are participating in the program, including DTE Electric, effective with the September 2013 billing month. The surcharge billed by DTE Electric is remitted to the State of Michigan for subsequent distribution through a grant process to social service agencies and utilities to assist low income customers.

Renewable Energy Plan (REP)

In June 2013, DTE Electric filed an application for the biennial review and approval of its amended REP with the MPSC requesting authority to reduce its annual surcharge revenue recovery from approximately $100 million to $15 million. The proposed level is appropriate to continue to properly implement DTE Electric’s 20-year REP, designed to deliver cleaner, renewable electric generation to its customers, to further diversify DTE Electric’s and the State of Michigan’s sources of electric supply, and to address the state and national goals of increasing energy independence. On December 19, 2013, the MPSC approved DTE Electric’s amended REP.

Power Supply Cost Recovery Proceedings

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

2010 PSCR Year - On April 25, 2013, the MPSC approved the 2010 PSCR net under-recovery of $52.6 million and the recovery of this amount as part of the 2011 PSCR reconciliation. The order also approved DTE Electric's Pension Equalization Mechanism reconciliation and authorized a one month surcharge in June 2013 and approved the recovery of the over-refund of the self-implemented rate increase related to the 2009 electric rate case filing as part of the 2011 PSCR reconciliation.

2012 PSCR Year - In March 2013, DTE Electric filed the 2012 PSCR reconciliation calculating a net under-recovery of approximately $87 million that includes an under-recovery of approximately $148 million for the 2011 PSCR year. The reconciliation includes purchased power costs related to the manual shutdown of our Fermi 2 nuclear power plant in June 2012 caused by the failure of one of the plant's two non-safety related feed-water pumps. The plant was restarted on July 30, 2012, which restored production to nominal 68% of full capacity. In September 2013, the repair to the plant was completed and production was returned to full capacity. DTE Electric was able to purchase sufficient power from MISO to continue to provide uninterrupted service to our customers. Certain intervenors in the reconciliation case have challenged the recovery of up to $32 million of the Fermi-related purchased power costs. Resolution of this matter is expected in 2014.

2012 Gas Rate Case Filing

DTE Gas filed a rate case on April 20, 2012 based on a projected test year for the twelve-month period ending October 31, 2013. On December 20, 2012, the MPSC approved a partial settlement agreement and authorized the Company to increase its annual gas revenues by $19.9 million for service rendered on and after January 1, 2013. The partial settlement agreement did not resolve the proposal for an infrastructure recovery mechanism (IRM) designed to recover DTE Gas' projected costs over a five-year period related to its gas main renewal, pipeline integrity and meter move out programs. On April 16, 2013, the MPSC issued an order approving the IRM and authorized the recovery of the cost of service related to $77 million of annual investment in the programs beginning in May 2013. The IRM will adjust annually in July for the incremental investment each year, after a limited hearing on the reconciliation of the prior year capital expenditures. When DTE Gas files a rate case, all capital invested as part of the IRM will be rolled into rate base and recovery would continue through base rates as part of a base rate case filing. As part of any future rate case, DTE Gas may propose to implement an updated IRM to address the recovery of future infrastructure investments.

81

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

DTE Gas UETM

In March 2013, DTE Gas filed an application with the MPSC for approval of its UETM reconciliation for 2012 requesting authority to refund approximately $20 million. On September 10, 2013, the MPSC approved a settlement agreement approving the requested 2012 UETM refund over a twelve-month period beginning in October 2013.

DTE Gas Revenue Decoupling Mechanism (RDM)

In October 2012, DTE Gas filed an application with the MPSC for approval of its RDM reconciliation for the period July 1, 2011 through June 30, 2012. The application requests authority to adjust existing retail gas rates so as to collect a net amount of approximately $9 million, plus interest. On March 15, 2013, the MPSC approved a settlement agreement and authorized the implementation of surcharges during the billing months of April 2013 through March 2014.

In May 2013, DTE Gas filed an application with the MPSC for approval of its RDM reconciliation for the period July 1, 2012 through October 31, 2012. DTE Gas's RDM application proposed the recovery of a net under-recovery of approximately $5.2 million. On November 14, 2013, the MPSC approved a settlement agreement and authorized the implementation of surcharges during the billing months of December 2013 through March 2014.

The December 2012 order in DTE Gas's rate case required the RDM be discontinued effective November 1, 2012. The order also provided for a new RDM for the period November 1, 2013 through October 31, 2014. The new RDM decouples weather normalized distribution revenue inside caps. The caps are tied to expected conservation targets: 1.125% in the first reconciliation period and 2.25% for the second and future periods.

DTE Gas Depreciation Filing

In compliance with an MPSC order, DTE Gas filed a depreciation case in June 2012. On May 15, 2013, the MPSC approved a settlement agreement increasing DTE Gas’s composite depreciation rates from 2.29% to 2.51%, effective on the same date as the MPSC-approved rates are effective in DTE Gas’s next general rate case. The Company cannot predict when DTE Gas will file its next rate case.

NOTE 12 — INCOME TAXES

Income Tax Summary

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

	2013			2012			2011
	(In millions)
Income before income taxes	$	922		$	960		$	991
Income tax expense at 35% statutory rate	$	323		$	336		$	347
Production tax credits	(68		)	(49		)	(6		)
Investment tax credits	(6		)	(6		)	(6		)
Depreciation	(4		)	(4		)	(4		)
AFUDC - Equity	(5		)	(4		)	(1		)
Employee Stock Ownership Plan dividends	(4		)	(4		)	(4		)
Domestic production activities deduction	(14		)	(14		)	(7		)
State and local income taxes, net of federal benefit	37			37			37
Enactment of Michigan Corporate Income Tax, net of federal expense	—			—			(87		)
Other, net	(5		)	(6		)	(1		)
Income tax expense	$	254		$	286		$	268
Effective income tax rate	27.5		%	29.8		%	27.0		%

82

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Components of income tax expense were as follows:

	2013		2012			2011
	(In millions)
Current income tax expense (benefit)
Federal	$	74	$	190		$	27
State and other income tax	16		49			21
Total current income taxes	90		239			48
Deferred income tax expense (benefit)
Federal	122		39			318
State and other income tax	42		8			(98		)
Total deferred income taxes	164		47			220
Total income taxes from continuing operations	254		286			268
Discontinued operations	—		(29		)	(1		)
Total	$	254	$	257		$	267

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:

	2013			2012
	(In millions)
Property, plant and equipment	$	(3,372	)	$	(3,389	)
Securitized regulatory assets	(127		)	(256		)
Alternative minimum tax credit carry-forwards	266			254
Merger basis differences	18			42
Pension and benefits	(30		)	(33		)
Other comprehensive loss	—			101
Derivative assets and liabilities	—			66
State net operating loss and credit carry-forwards	43			37
Other	(110		)	41
	(3,312		)	(3,137		)
Less valuation allowance	(37		)	(33		)
	$	(3,349	)	$	(3,170	)
Current deferred income tax assets (liabilities)	$	(28	)	$	21
Long-term deferred income tax liabilities	(3,321		)	(3,191		)
	$	(3,349	)	$	(3,170	)
Deferred income tax assets	$	1,808		$	1,038
Deferred income tax liabilities	(5,157		)	(4,208		)
	$	(3,349	)	$	(3,170	)

Production tax credits earned in prior years but not utilized totaled $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.

83

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The Company has state deferred tax assets related to net operating loss and credit carry-forwards of $43 million and $37 million at December 31, 2013 and 2012, respectively. The state net operating loss and credit carry-forwards expire from 2014 through 2033. The Company has recorded valuation allowances at December 31, 2013 and 2012 of approximately $37 million and $33 million, respectively, with respect to these deferred tax assets. In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.

Uncertain Tax Positions

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

	2013			2012			2011
	(In millions)
Balance at January 1	$	11		$	48		$	28
Additions for tax positions of prior years	—			—			27
Reductions for tax positions of prior years	—			(2		)	(4		)
Additions for tax positions of current year	—			1			1
Settlements	—			(30		)	(3		)
Lapse of statute of limitations	(1		)	(6		)	(1		)
Balance at December 31	$	10		$	11		$	48

The Company had $2 million and $3 million of unrecognized tax benefits at December 31, 2013 and at 2012, respectively, that, if recognized, would favorably impact its effective tax rate. During the next twelve months, it is reasonably possible that the statute of limitation will expire on various state tax returns. As a result, the Company believes that it is possible that there will be a decrease in unrecognized tax benefits of up to $1 million within the next twelve months.

The Company recognizes interest and penalties pertaining to income taxes in Interest expense and Other expenses, respectively, on its Consolidated Statements of Operations. Accrued interest pertaining to income taxes totaled $1 million and $1 million at December 31, 2013 and 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 2011, respectively.

In 2013, the Company settled a federal tax audit for the 2011 tax year, which resulted in the recognition of a nominal amount of unrecognized tax benefits. The Company's federal income tax returns for 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.

Michigan Corporate Income Tax (MCIT)

In May 2011, the Michigan Business Tax (MBT) was repealed and the MCIT was enacted and became effective January 1, 2012. The MCIT subjects corporations with business activity in Michigan to a 6% tax rate on an apportioned income tax base and eliminates the modified gross receipts tax and nearly all credits available under the MBT. The MCIT also eliminated the future deductions allowed under MBT that enabled companies to establish a one-time deferred tax asset upon enactment of the MBT to offset deferred tax liabilities that resulted from enactment of the MBT.

As a result of the enactment of the MCIT, the net state deferred tax liability was remeasured to reflect the impact of the MCIT tax rate on cumulative temporary differences expected to reverse after the effective date. The net impact of this remeasurement was a reduction of the net deferred tax assets attributable to our regulated utilities, partially offset by a decrease in deferred tax liabilities attributable to our non-utilities of $87 million primarily due to a lower apportionment factor from inclusion of non-utility entities in DTE Energy's unitary Michigan tax return and was recognized as a reduction to income tax expense in 2011.

No recognition of these non-cash transactions have been reflected in the Consolidated Statements of Cash Flows.

84

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 13 — COMMON STOCK

Common Stock

During 2013 and 2012, the Company contributed the following amounts of DTE Energy Common stock to the DTE Energy Company Affiliates Employee Benefit Plans Master Trust:

Date	Number of Shares	Price Per Share		Amount
				(In millions)
March 12, 2013	750,075	$	66.66	$	50
June 12, 2013	753,579	$	66.35	50
September 12, 2013	1,522,301	$	65.69	100
				$	200
June 18, 2012	1,334,668	$	59.94	$	80

The shares for all the contributions were valued at the closing market price of DTE Energy common stock on 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.

Dividends

Certain of the Company’s credit facilities contain a provision requiring the Company to maintain a total funded debt to capitalization ratio, as defined in the agreements, of no more than 0.65 to 1, which has the effect of limiting the amount of dividends the Company can pay in order to maintain compliance with this provision. See Note 17 for a definition of this ratio. The effect of this provision was to restrict the payment of approximately $166 million at December 31, 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.

85

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 14 — EARNINGS PER SHARE

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

	2013		2012		2011
	(In millions, expect per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	661	$	610	$	711
Average number of common shares outstanding	175		171		169
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	453	$	413	$	392
Dividends declared — net restricted shares	1		1		1
Total distributed earnings	$	454	$	414	$	393
Net income less distributed earnings	$	207	$	196	$	318
Distributed (dividends per common share)	$	2.59	$	2.42	$	2.32
Undistributed	1.17		1.14		1.87
Total Basic Earnings per Common Share	$	3.76	$	3.56	$	4.19
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	661	$	610	$	711
Average number of common shares outstanding	175		171		169
Average incremental shares from assumed exercise of options	—		1		1
Common shares for dilutive calculation	175		172		170
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	453	$	413	$	392
Dividends declared — net restricted shares	1		1		1
Total distributed earnings	$	454	$	414	$	393
Net income less distributed earnings	$	207	$	196	$	318
Distributed (dividends per common share)	$	2.59	$	2.42	$	2.32
Undistributed	1.17		1.13		1.86
Total Diluted Earnings per Common Share	$	3.76	$	3.55	$	4.18

86

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 15 — LONG-TERM DEBT

Long-Term Debt

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

	2013			2012
	(In millions)
Mortgage bonds, notes, and other
DTE Energy Debt, Unsecured
6.1% due 2014 to 2033	$	1,297		$	1,298
DTE Electric Taxable Debt, Principally Secured
4.7% due 2014 to 2043	4,286			3,777
DTE Electric Tax-Exempt Revenue Bonds (b)
5.1% due 2014 to 2036	558			707
DTE Gas Taxable Debt, Principally Secured
5.6% due 2014 to 2042	1,029			919
Other Long-Term Debt, Including Non-Recourse Debt	142			153
	7,312			6,854
Less amount due within one year	(694		)	(634		)
	$	6,618		$	6,220
Securitization bonds
6.6% due 2015	$	302		$	479
Less amount due within one year	(197		)	(177		)
	$	105		$	302
Junior Subordinated Debentures
6.5% due 2061	$	280		$	280
5.25% due 2062	200			200
	$	480		$	480

_______________________________________

(a) Weighted average interest rates as of December 31, 2013 are shown below the description of each category of debt.

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

Debt Issuances

In 2013, the following debt was issued:

Company	Month Issued	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March	Mortgage Bonds (a)	4.00	%	2043	$	375
DTE Electric	August	Mortgage Bonds (a)	3.65	%	2024	400
DTE Energy	November	Senior Notes (a)	3.85	%	2023	300
DTE Gas	December	Mortgage Bonds (a)	3.64	%	2023	50
DTE Gas	December	Mortgage Bonds (a)	3.74	%	2025	70
DTE Gas	December	Mortgage Bonds (a)	3.94	%	2028	50
						$	1,245

_______________________________________

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

87

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Debt Redemptions

In 2013, the following debt was redeemed:

Company	Month	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March	Securitization Bonds	6.42	%	2013	$	88
DTE Electric	March	Tax Exempt Revenue Bonds (a)	5.30	%	2030	51
DTE Electric	April	Other Long-Term Debt	Various		2013	13
DTE Gas	April	Senior Notes	5.26	%	2013	60
DTE Energy	June	Senior Notes	Variable		2013	300
DTE Electric	September	Securitization Bonds	6.62	%	2013	89
DTE Electric	September	Senior Notes	6.40	%	2013	250
DTE Electric	December	Tax Exempt Revenue Bonds (a)	5.50	%	2030	49
DTE Electric	December	Tax Exempt Revenue Bonds (a)	6.75	%	2038	50
DTE Energy	Various	Other Long-Term Debt	Various		2013	11
						$	961

_______________________________________

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

The following table shows the scheduled debt maturities:

	2014		2015		2016		2017		2018		2019 and Thereafter		Total
	(In millions)
Amount to mature	$	891	$	476	$	465	$	9	$	407	$	5,846	$	8,094

Junior Subordinated Debentures

At December 31, 2013, the Company had $280 million of 6.5% Junior Subordinated Debentures due 2061 and $200 million of 5.25% Junior Subordinated Debentures due 2062. The Company has the right to defer interest payments on the debt securities. Should the Company exercise this right, it cannot declare or pay dividends on, or redeem, purchase or acquire, any of its capital stock during the deferral period. Any deferred interest payments will bear additional interest at the rate associated with the related debt issue.

Cross Default Provisions

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

NOTE 16 — PREFERRED AND PREFERENCE SECURITIES

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

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

88

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 17 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

DTE Energy and its wholly owned subsidiaries, DTE Electric and DTE Gas, have unsecured revolving credit agreements with a syndicate of 19 banks that can be used for general corporate borrowings, but are intended to provide liquidity support for each of the companies’ commercial paper programs. No one bank provides more than 8.7% of the commitment in any facility. Borrowings under the facilities are available at prevailing short-term interest rates. Additionally, DTE Energy has other facilities to support letter of credit issuance.

The agreements require the Company to maintain a total funded debt to capitalization ratio of no more than 0.65 to 1. In the agreements, “total funded debt” means all indebtedness of the Company and its consolidated subsidiaries, including capital lease obligations, hedge agreements and guarantees of third parties’ debt, but excluding contingent obligations, nonrecourse and junior subordinated debt and certain equity-linked securities and, except for calculations at the end of the second quarter, certain DTE Gas short-term debt. “Capitalization” means the sum of (a) total funded debt plus (b) “consolidated net worth,” which is equal to consolidated total stockholders’ equity of the Company and its consolidated subsidiaries (excluding pension effects under certain FASB statements), as determined in accordance with accounting principles generally accepted in the United States of America. At December 31, 2013, the total funded debt to total capitalization ratios for DTE Energy, DTE Electric and DTE Gas are 0.48 to 1, 0.50 to 1 and 0.48 to 1, respectively, and are in compliance with this financial covenant. The availability under the facilities in place at December 31, 2013 is shown in the following table:

	DTE Energy		DTE Electric		DTE Gas		Total
	(In millions)
Unsecured letter of credit facility, expiring in May 2014	$	50	$	—	$	—	$	50
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Unsecured revolving credit facility, expiring April 2018	1,200		300		300		1,800
	1,375		300		300		1,975
Amounts outstanding at December 31, 2013:
Commercial paper issuances	35		—		96		131
Letters of credit	244		—		—		244
	279		—		96		375
Net availability at December 31, 2013	$	1,096	$	300	$	204	$	1,600

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $53 million which are used for various corporate purposes.

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

In conjunction with maintaining certain exchange traded risk management positions, the Company may be required to post cash collateral with its clearing agent. The Company has a demand financing agreement for up to $100 million with its clearing agent. The agreement, as amended, also allows for up to $50 million of additional margin financing provided that the Company posts a letter of credit for the incremental amount. At December 31, 2013, a $50 million letter of credit was in place, raising the capacity under this facility to $150 million. The $50 million letter of credit is included in the table above. The amount outstanding under this agreement was $138 million and $65 million at December 31, 2013 and 2012, respectively.

89

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 18 — CAPITAL AND OPERATING LEASES

Lessee — The Company leases various assets under capital and operating leases, including coal railcars, office buildings, a warehouse, computers, vehicles and other equipment. The lease arrangements expire at various dates through 2046.

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

	Capital Leases		Operating Leases
	(In millions)
2014	$	8	$	35
2015	8		31
2016	3		27
2017	—		25
2018	—		20
Thereafter	—		92
Total minimum lease payments	$	19	$	230
Less imputed interest	1
Present value of net minimum lease payments	18
Less current portion	7
Non-current portion	$	11

Rental expense for operating leases was $34 million in 2013, $36 million in 2012, and $40 million in 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, 2013, were as follows:

	(In millions)
2014	$	12
2015	12
2016	12
2017	12
2018	12
Thereafter	19
Total minimum future lease receipts	79
Residual value of leased pipeline	40
Less unearned income	(40		)
Net investment in capital lease	79
Less current portion	(5		)
	$	74

90

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 19 — COMMITMENTS AND CONTINGENCIES

Environmental

Electric

Air - DTE Electric is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze, mercury, and other air pollution. These rules have led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, mercury and other emissions. To comply with these requirements, DTE Electric has spent approximately $2 billion through 2013. The Company estimates DTE Electric will make capital expenditures of approximately $280 million in 2014 and up to approximately $1.2 billion of additional capital expenditures through 2021 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and 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. 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 CAIR in place. The EPA's petition seeking a rehearing of the U.S. Court of Appeals' decision regarding the CSAPR was denied on January 24, 2013. On June 24, 2013, the U.S. Supreme Court granted the EPA's petition asking the Court to review the D.C. Circuit Court's decision on CSAPR. A ruling by the Supreme Court is expected in 2014. Notwithstanding the appeal filed with the Supreme Court, the EPA and a number of states have started working on the framework of revised CSAPR regulations which we anticipate to be proposed in the next few years.

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 MATS rule requires reductions of mercury and other hazardous air pollutants beginning in 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 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 have been economical for FGD installations to 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. In June 2010, the EPA issued a NOV/FOV making similar allegations related to a 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 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. On March 28, 2013, the Court of Appeals 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 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.

91

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

On March 13, 2013, the Sierra Club filed suit against DTE Energy and DTE Electric alleging violations of the Clean Air Act at four of DTE Electric's coal-fired power plants. The plaintiffs allege 1,4996-minute periods of excess opacity of air emissions from 2007-2012 at those facilities. The suit asks that the 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 amended complaint in the first quarter of 2014. The resolution of this matter is not expected to have a material effect on the 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. 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 proposed revised steam electric effluent 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, 2013 and 2012, the Company had $8 million and $9 million, respectively, accrued for remediation. Any 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 three permitted engineered ash storage facilities to dispose of fly ash from coal fired power 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.

92

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Gas

Contaminated Sites — Gas segment, owned or previously owned, 15 former MGP sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites. Cleanup activities associated with these sites will be conducted over the next several years. The MPSC has established a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites. As of December 31, 2013 and 2012, the Company had $28 million and $29 million, accrued for remediation, respectively. Any change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows. The Company anticipates the cost amortization methodology approved by the MPSC for DTE Gas, which allows DTE Gas to amortize the MGP costs over a ten-year period beginning with the year subsequent to the year the MGP costs were incurred and the cost deferral and rate recovery mechanism for Citizens approved by the City of Adrian, will prevent environmental costs from having a material adverse impact on the Company’s results of operations.

Non-utility

The Company’s non-utility 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 received two NOVs from the Pennsylvania Department of Environmental Protection (PADEP) in 2010 alleging violations of the permit for the Pennsylvania coke battery facility in connection with coal pile storm water runoff. The Company has implemented best management practices to address this issue. The Company recently received a permit to upgrade its existing waste water treatment system and is currently seeking a permit from the PADEP to upgrade its wastewater treatment technology to a biological treatment facility. The Company expects to spend less than $3 million on the existing waste water treatment system to comply with existing water discharge requirements and to upgrade its coal pile storm water runoff management program.

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

Other

In March 2011, the EPA finalized a new set of regulations regarding the identification of non-hazardous secondary materials that are considered solid waste, industrial boiler and process heater maximum achievable control technologies (IBMACT) for major and area sources, and commercial/industrial solid waste incinerator new source performance standard and emission guidelines (CISWI). The effective dates of the major source IBMACT and CISWI regulations were stayed and a re-proposal was issued by the EPA in December 2011. Final IBMACT and CISWI were issued by the EPA in December 2012. The Company is developing compliance plans to upgrade or convert existing industrial boilers to natural gas and to perform required energy assessments in compliance with the applicable new standards. Capital costs for the boiler conversions and the expenses for the one-time energy assessments are not expected to be material.

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 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 gathering stage and any required emission reductions for DTE Energy sources to meet the standard cannot be estimated currently.

93

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Nuclear Operations

Property Insurance

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

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

DTE Electric has $500 million in primary coverage and $2.25 billion of excess coverage for stabilization, decontamination, debris removal, repair and/or replacement of property and decommissioning. The combined coverage limit for total property damage is $2.75 billion, subject to a $1 million deductible. 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 $34 million per event if the loss associated with any one event at any nuclear plant should exceed the accumulated funds available to NEIL.

Public Liability Insurance

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 $127.3 million could be levied against each licensed nuclear facility, but not more than $19 million per year per facility. Thus, deferred premium charges could be levied against all owners of licensed nuclear facilities in the event of a nuclear incident at any of these facilities.

Nuclear Fuel Disposal Costs

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

94

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

In February 2013, the U.S. Court of Appeals for the District of Columbia (COA) granted a motion to reopen the fee adequacy litigation to review the DOE's latest fee adequacy report which was released in January 2013. In November 2013, the COA issued a decision ordering the DOE to submit a proposal to Congress to reduce the nuclear waste fee to zero until the DOE enacts an alternative nuclear waste management plan. In January 2014, the DOE submitted such a proposal to Congress that will take effect in 90 legislative calendar days, absent legislative action to the contrary. Simultaneously, the DOE filed a petition for rehearing of the November 2013 decision with the COA. DTE Electric continues to pay fees to the U.S. government's nuclear waste fund pending further developments in this proceeding.

Synthetic Fuel Guarantees

The Company discontinued the operations of its synthetic fuel production facilities throughout the United States as of December 31, 2007. The Company provided certain guarantees and indemnities in conjunction with the sales of interests in its synfuel facilities. The guarantees cover potential commercial, environmental, oil price and tax-related obligations and will survive until 90 days after expiration of all applicable statutes of limitations. The Company estimates that its maximum potential liability under these guarantees at December 31, 2013 is approximately $1.1 billion. Payment under these guarantees is considered remote.

Reduced Emissions Fuel Guarantees

The Company has provided certain guarantees and indemnities in conjunction with the sales of interests in its reduced emissions fuel facilities. The guarantees cover potential commercial, environmental, and tax-related obligations and will survive until 90 days after expiration of all applicable statutes of limitations. The Company estimates that its maximum potential liability under these guarantees at December 31, 2013 is approximately $144 million. Payment under these guarantees is considered remote.

Other Guarantees

In certain limited circumstances, the Company enters into contractual guarantees. The Company may guarantee another entity’s obligation in the event it fails to perform. The Company may provide guarantees in certain indemnification agreements. Finally, the Company may provide indirect guarantees for the indebtedness of others. The Company’s guarantees are not individually material with maximum potential payments totaling $60 million at December 31, 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, 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.

Labor Contracts

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.

95

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Purchase Commitments    

As of December 31, 2013, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments, renewable energy contracts and energy trading contracts. The Company estimates that these commitments will be approximately $8.6 billion from 2014 through 2051 as detailed in the following table:

	(In millions)
2014	$	2,617
2015	1,195
2016	643
2017	345
2018	311
2019 — 2051	3,487
	$	8,598

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

Bankruptcies

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 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 Company's utilities provide services to the city of 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 impact on its financial results.

Other Contingencies

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

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

NOTE 20 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

Pension Plan Benefits

The Company has qualified defined benefit retirement plans for eligible represented and non-represented employees. The plans are noncontributory and cover 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.

96

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 a defined benefit retirement plan. In its place, the Company will annually contribute an amount equivalent to 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 and additional amounts when it deems appropriate. The Company contributed $277 million to its qualified pension plans in 2013. At the discretion of management, and depending upon financial market conditions, we anticipate making up to $345 million in contributions to the pension plans in 2014.

Net pension cost includes the following components:

	2013			2012			2011
	(In millions)
Service cost	$	94		$	82		$	69
Interest cost	192			204			202
Expected return on plan assets	(266		)	(244		)	(246		)
Amortization of:
Net loss	208			176			142
Prior service cost	—			—			3
Special termination benefits	—			2			2
Net pension cost	$	228		$	220		$	172

	2013			2012
	(In millions)
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income
Net actuarial (gain) loss	$	(581	)	$	395
Amortization of net actuarial loss	(208		)	(178		)
Total recognized Regulatory assets and Other comprehensive income	$	(789	)	$	217
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	(561	)	$	437
Estimated amounts to be amortized from Regulatory assets and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year
Net actuarial loss	$	151		$	202

97

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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:

	2013			2012
	(In millions)
Accumulated benefit obligation, end of year	$	4,068		$	4,349
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	4,729		$	4,195
Service cost	94			82
Interest cost	192			204
Plan amendments	(3		)	—
Actuarial (gain) loss	(400		)	474
Special termination benefits	—			2
Benefits paid	(232		)	(228		)
Projected benefit obligation, end of year	$	4,380		$	4,729
Change in plan assets
Plan assets at fair value, beginning of year	$	3,223		$	2,886
Actual return on plan assets	445			325
Company contributions	284			240
Benefits paid	(232		)	(228		)
Plan assets at fair value, end of year	$	3,720		$	3,223
Funded status of the plans	$	(660	)	$	(1,506	)
Amount recorded as:
Current liabilities	$	(7	)	$	(8	)
Noncurrent liabilities	(653		)	(1,498		)
	$	(660	)	$	(1,506	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	174		$	205
Prior service (credit)	(1		)	(2		)
	$	173		$	203
Amounts recognized in Regulatory assets (see Note 11)
Net actuarial loss	$	1,654		$	2,413
Prior service cost	6			7
	$	1,660		$	2,420

At December 31, 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:

	(In millions)
2014	$	242
2015	250
2016	258
2017	268
2018	280
2019-2023	1,529
	$	2,827

98

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

	2013		2012		2011
Projected benefit obligation
Discount rate	4.95	%	4.15	%	5.00	%
Rate of compensation increase	4.20	%	4.20	%	4.20	%
Net pension costs
Discount rate	4.15	%	5.00	%	5.50	%
Rate of compensation increase	4.20	%	4.20	%	4.00	%
Expected long-term rate of return on plan assets	8.25	%	8.25	%	8.50	%

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 stocks, and large and small market capitalizations. Fixed income securities generally include 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 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, 2013 are listed below:

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

99

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Fair Value Measurements for pension plan assets at December 31, 2013 and 2012 (a):

	December 31, 2013								December 31, 2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In millions)
Asset Category:
Short-term investments (b)	$	22	$	—	$	—	$	22	$	—	$	24	$	—	$	24
Equity securities
U.S. Large Cap (c)	896		—		—		896		688		44		—		732
U.S. Small/Mid Cap (d)	221		—		—		221		153		5		—		158
Non U.S. (e)	611		130		—		741		530		120		—		650
Fixed income securities (f)	16		921		—		937		87		765		—		852
Hedge Funds and Similar Investments (g)	268		70		395		733		209		80		339		628
Private Equity and Other (h)	—		—		170		170		—		—		179		179
Total	$	2,034	$	1,121	$	565	$	3,720	$	1,667	$	1,038	$	518	$	3,223

_______________________________________

(a) See Note 3 — Fair Value for a description of levels within the fair value hierarchy.

(b) This category predominantly represents certain short-term fixed income securities and money market investments that are managed in separate accounts or commingled funds. Pricing for investments in this category are obtained from quoted prices in actively traded markets or valuations from brokers or pricing services.

(c) This category comprises both actively and not actively managed portfolios that track the S&P 500 low cost equity index funds. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(d) This category represents portfolios of small and medium capitalization domestic equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(e) This category primarily consists of portfolios of non-U.S. developed and emerging market equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(f) This category includes corporate bonds from diversified industries, U.S. Treasuries, and mortgage-backed securities. Pricing for investments in this category is obtained from quoted prices in actively traded markets and quotations from broker or pricing services. Non-exchange traded securities and exchange-traded securities held in commingled funds are classified as Level 2 assets.

(g) This category utilizes a diversified group of strategies that attempt to capture financial market inefficiencies and includes publicly traded debt and equity, publicly traded mutual funds, commingled and limited partnership funds and non-exchange traded securities. Pricing for Level 1 and Level 2 assets in this category is obtained from quoted prices in actively traded markets and quoted prices from broker or pricing services. Non-exchange traded securities held in commingled funds are classified as Level 2 assets. Valuations for some Level 3 assets in this category may be based on limited observable inputs as there may be little, if any, publicly available pricing.

(h) This category includes a diversified group of funds and strategies that primarily invests in private equity partnerships. This category also includes investments in timber and private mezzanine debt. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available pricing. Valuations for assets in this category may be based on discounted cash flow analyses, relevant publicly-traded comparables and comparable transactions.

The pension trust holds debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices in actively traded markets. The commingled funds and institutional mutual funds hold exchange-traded equity or debt securities and are valued based on 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 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.

100

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

	Year Ended December 31, 2013								Year Ended December 31, 2012
	Hedge Funds and Similar Investments		Private Equity and Other			Total			Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1	$	339	$	179		$	518		$	296		$	168		$	464
Total realized/unrealized gains (losses):
Realized gains (losses)	—		18			18			18			(6		)	12
Unrealized gains (losses)	40		(14		)	26			(5		)	12			7
Purchases, sales and settlements:
Purchases	16		15			31			250			33			283
Sales	—		(28		)	(28		)	(220		)	(28		)	(248		)
Ending Balance at December 31	$	395	$	170		$	565		$	339		$	179		$	518
The amount of total gains for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	38	$	3		$	41		$	16		$	6		$	22

There were no transfers between Level 3 and Level 2 and there were no significant transfers between Level 2 and Level 1 in the years ended December 31, 2013 and 2012.

Other Postretirement Benefits

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 $264 million to its other postretirement medical and life insurance benefit plans during 2013. At the discretion of management, we anticipate making up to $145 million of contributions to the VEBA trusts in 2014.

Starting in 2012, in lieu of offering future employees post-employment health care and life insurance benefits, the Company allocates a fixed amount per year to an account in a tax-exempt trust for each employee. These trusts are managed either by the Company (for non-represented and certain represented groups), or by the Utility Workers of America (UWUA) for Local 223 employees. The cost of these plans was $2 million in 2013 and less than $1 million in 2012.

Beginning in 2013, the Company replaced sponsored retiree medical, prescription drug and dental coverage 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; as well as future Medicare eligible represented retirees, spouses, surviving spouses or same sex domestic partners. The 2013 RHCA allowance ranged between $3,250 and $3,500 depending on an employee’s date of hire and will increase each year at the lower of the rate of medical inflation or 2%.

Net other postretirement cost includes the following components:

	2013			2012			2011
	(In millions)
Service cost	$	47		$	68		$	64
Interest cost	88			120			121
Expected return on plan assets	(110		)	(92		)	(94		)
Amortization of:
Net loss	64			80			55
Prior service credit	(131		)	(27		)	(26		)
Net transition asset	—			2			2
Net other postretirement cost (benefit)	$	(42	)	$	151		$	122

101

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

	2013			2012
	(In millions)
Other changes in plan assets and APBO recognized in Regulatory assets (liabilities) and Other comprehensive income
Net actuarial gain	$	(353	)	$	(34	)
Amortization of net actuarial loss	(64		)	(80		)
Prior service credit	(218		)	(264		)
Amortization of prior service credit	131			27
Amortization of transition asset	—			(2		)
Total recognized in Regulatory assets (liabilities) and Other comprehensive income	$	(504	)	$	(353	)
Total recognized in net periodic benefit cost, Regulatory assets (liabilities) and Other comprehensive income	$	(546	)	$	(202	)
Estimated amounts to be amortized from Regulatory assets (liabilities) and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year
Net actuarial loss	$	21		$	69
Prior service credit	$	(144	)	$	(91	)

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

	2013			2012
	(In millions)
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation, beginning of year	$	2,315		$	2,470
Service cost	47			68
Interest cost	88			120
Plan amendments	(218		)	(264		)
Actuarial (gain) loss	(267		)	5
Medicare Part D subsidy	1			6
Benefits paid	(88		)	(90		)
Accumulated postretirement benefit obligation, end of year	$	1,878		$	2,315
Change in plan assets
Plan assets at fair value, beginning of year	$	1,153		$	985
Actual return on plan assets	196			131
Company contributions	264			140
Benefits paid	(86		)	(103		)
Plan assets at fair value, end of year	$	1,527		$	1,153
Funded status, end of year	$	(351	)	$	(1,162	)
Amount recorded as:
Current liabilities	$	(1	)	$	(2	)
Noncurrent liabilities	(350		)	(1,160		)
	$	(351	)	$	(1,162	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	29		$	40
Prior service credit	(10		)	(14		)
Net transition asset	—			(1		)
	$	19		$	25
Amounts recognized in Regulatory assets (liabilities) (See Note 11)
Net actuarial loss	$	321		$	727
Prior service credit	(393		)	(302		)
Net transition obligation	—			1
	$	(72	)	$	426

102

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

At December 31, 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:

	(In millions)
2014	$	103
2015	110
2016	115
2017	123
2018	130
2019 — 2023	724
	$	1,305

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

	2013		2012		2011
Accumulated postretirement benefit obligation
Discount rate	4.95	%	4.15	%	5.00	%
Health care trend rate pre- and post- 65	7.50	/ 6.50%	7.00	%	7.00	%
Ultimate health care trend rate	4.50	%	5.00	%	5.00	%
Year in which ultimate reached pre- and post- 65	2025 / 2024		2021		2020
Other postretirement benefit costs
Discount rate (prior to interim remeasurement)	4.15	%	5.00	%	5.50	%
Discount rate (post interim remeasurement)	4.30	%	N/A		N/A
Expected long-term rate of return on plan assets	8.25	%	8.25	%	8.75	%
Health care trend rate pre- and post- 65	7.00	%	7.00	%	7.00	%
Ultimate health care trend rate	5.00	%	5.00	%	5.00	%
Year in which ultimate reached	2021		2020		2019

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 $9 million in 2013 and increased the accumulated benefit obligation by $124 million at December 31, 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 $8 million in 2013 and would have decreased the accumulated benefit obligation by $108 million at December 31, 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, 2013 are listed below:

U.S. Large Cap Equity Securities	17	%
U.S. Small Cap and Mid Cap Equity Securities	4
Non U.S. Equity Securities	20
Fixed Income Securities	25
Hedge Funds and Similar Investments	20
Private Equity and Other	14
	100	%

103

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Fair Value Measurements for other postretirement benefit plan assets at December 31, 2013 and 2012 (a):

	December 31, 2013								December 31, 2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Asset Category:	(In millions)
Short-term investments (b)	$	5	$	—	$	—	$	5	$	1	$	2	$	—	$	3
Equity securities:
U.S. Large Cap (c)	302		—		—		302		189		3		—		192
U.S. Small/Mid Cap (d)	147		—		—		147		105		—		—		105
Non U.S. (e)	282		9		—		291		230		7		—		237
Fixed income securities (f)	17		350		—		367		38		247		—		285
Hedge Funds and Similar Investments (g)	130		25		159		314		102		24		119		245
Private Equity and Other (h)	—		—		101		101		—		—		86		86
Total	$	883	$	384	$	260	$	1,527	$	665	$	283	$	205	$	1,153

_______________________________________

(a) See Note 3 — Fair Value for a description of levels within the fair value hierarchy.

(b) This category predominantly represents certain short-term fixed income securities and money market investments that are managed in separate accounts or commingled funds. Pricing for investments in this category are obtained from quoted prices in actively traded markets or valuations from brokers or pricing services.

(c) This category comprises both actively and not actively managed portfolios that track the S&P 500 low cost equity index funds. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(d) This category represents portfolios of small and medium capitalization domestic equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(e) This category primarily consists of portfolios of non-U.S. developed and emerging market equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(f) This category includes corporate bonds from diversified industries, U.S. Treasuries, bank loans and mortgage backed securities. Pricing for investments in this category is obtained from quoted prices in actively traded markets and quotations from broker or pricing services. Non-exchange traded securities and exchange-traded securities held in commingled funds are classified as Level 2 assets.

(g) This category utilizes a diversified group of strategies that attempt to capture financial market inefficiencies and includes publicly traded debt and equity, publicly traded mutual funds, commingled and limited partnership funds and non-exchange traded securities. Pricing for Level 1 and Level 2 assets in this category is obtained from quoted prices in actively traded markets and quoted prices from broker or pricing services. Non-exchange traded securities held in commingled funds are classified as Level 2 assets. Valuations for some Level 3 assets in this category may be based on limited observable inputs as there may be little, if any, publicly available pricing.

(h) This category includes a diversified group of funds and strategies that primarily invests in private equity partnerships. This category also includes investments in timber and private mezzanine debt. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available pricing. Valuations for assets in this category may be based on discounted cash flow analyses, relevant publicly-traded comparables and comparable transactions.

104

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 hold exchange-traded equity or debt securities and are valued based on 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):

	Year Ended December 31, 2013								Year Ended December 31, 2012
	Hedge Funds and Similar Investments		Private Equity and Other			Total			Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1	$	119	$	86		$	205		$	95		$	60		$	155
Total realized/unrealized gains (losses):
Realized gains (losses)	—		2			2			6			(11		)	(5		)
Unrealized gains	14		7			21			—			14			14
Purchases, sales and settlements:
Purchases	26		15			41			86			36			122
Sales	—		(9		)	(9		)	(68		)	(13		)	(81		)
Ending Balance at December 31	$	159	$	101		$	260		$	119		$	86		$	205
The amount of total gains for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	14	$	9		$	23		$	6		$	2		$	8

There were no transfers between Level 3 and Level 2 and there were no significant transfers between Level 2 and Level 1 in the years ended December 31, 2013 and 2012.

Interim Re-Measurement of Other Postretirement Benefit Obligation

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 benefit changes resulting from the new labor contracts.

Healthcare Legislation

In December 2003, the Medicare Act was signed into law which provides for a non-taxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least “actuarially equivalent” to the benefit established by law. The effects of the subsidy reduced net periodic other postretirement benefit costs by $1 million in 2013, $6 million in 2012 and $6 million in 2011.

105

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Grantor Trust

DTE Gas maintains a Grantor Trust to fund other postretirement benefit obligations that invests in life insurance contracts and income securities. Employees and retirees have no right, title or interest in the assets of the Grantor Trust, and DTE Gas can revoke the trust subject to providing the MPSC with prior notification. The Company accounts for its investment at fair value, approximately $17 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.

Defined Contribution Plans

The Company also sponsors defined contribution retirement savings plans. Participation in one of these plans is available to substantially all represented and non-represented employees. The Company matches employee contributions up to certain predefined limits based upon eligible compensation, the employee’s contribution rate and, in some cases, years of credited service. The cost of these plans was $41 million, $37 million, and $35 million in each of the years 2013, 2012, and 2011, respectively.

NOTE 21 — STOCK-BASED COMPENSATION

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

• Authorized limit is 11,500,000 shares of common stock;

• Prohibits the grant of a stock option with an exercise price that is less than the fair market value of the Company’s stock on the date of the grant; and

• Imposes the following award limits to a single participant in a single calendar year, (1) options for more than 500,000 shares of common stock; (2) stock awards for more than 150,000 shares of common stock; (3) performance share awards for more than 300,000 shares of common stock (based on the maximum payout under the award); or (4) more than 1,000,000 performance units, which have a face amount of $1.00 each.

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

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

	2013		2012		2011
	(In millions)
Stock-based compensation expense	$	99	$	83	$	66
Tax benefit	38		33		25
Stock-based compensation cost capitalized in property, plant and equipment	15		5		4

Stock Options

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

106

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Stock option activity was as follows:

	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In millions)
Options outstanding at December 31, 2012	1,192,670		$	41.86
Granted	—		$	—
Exercised	(458,603	)	$	40.71
Forfeited or expired	(10,370	)	$	41.46
Options outstanding and exercisable at December 31, 2013	723,697		$	42.60	$	18

As of December 31, 2013, the weighted average remaining contractual life for the exercisable shares is 3.83 years. As of December 31, 2013, all options were vested. During 2013, 200,844 options vested.

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

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

						Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)
					Number of Options
Range of Exercise Prices
$	27.00	—	$	38.00	67,257	$	28.30	5.15
$	38.01	—	$	42.00	167,447	$	41.23	3.21
$	42.01	—	$	45.00	351,893	$	44.02	4.16
$	45.01	—	$	50.00	137,100	$	47.67	3.08
					723,697	$	42.60	3.83

Restricted Stock Awards

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

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

Stock award activity for the years ended December 31 was:

	2013		2012		2011
Fair value of awards vested (in millions)	$	8	$	9	$	13
Restricted common shares awarded	127,785		167,320		381,840
Weighted average market price of shares awarded	$	64.72	$	53.71	$	47.98
Compensation cost charged against income (in millions)	$	23	$	12	$	12

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

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at December 31, 2012	597,648		$	48.33
Grants	127,785		$	64.72
Forfeitures	(7,155	)	$	54.61
Vested and issued	(225,949	)	$	45.54
Balance at December 31, 2013	492,329		$	53.76

107

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Performance Share Awards

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

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

	2013		2012		2011
	(In millions)
Compensation expense	$	77	$	71	$	53
Cash settlements (a)	$	9	$	4	$	3
Stock settlements (a)	$	56	$	41	$	25

_______________________________________

(a) Sum of cash and stock settlements approximates the intrinsic value of the liability.

During the vesting period, the recipient of a performance share award has no shareholder rights. 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 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, 2013:

	Performance Shares
Balance at December 31, 2012	1,634,364
Grants	564,561
Forfeitures	(41,512	)
Payouts	(548,624	)
Balance at December 31, 2013	1,608,789

Unrecognized Compensation Costs

As of December 31, 2013, there was $55 million of total unrecognized compensation cost related to non-vested stock-based compensation arrangements. That cost is expected to be recognized over a weighted-average period of 0.93 years.

	Unrecognized Compensation Cost		Weighted Average to be Recognized
	(In millions)		(In years)
Stock awards	$	10	0.93
Performance shares	45		0.93
	$	55	0.93

NOTE 22 — SEGMENT AND RELATED INFORMATION

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

Electric segment consists principally of DTE Electric, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million residential, commercial and industrial customers in southeastern Michigan.

108

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

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

Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers; produce reduced emissions fuel (REF) and sell electricity from biomass-fired energy projects.

Energy Trading consists of energy marketing and trading operations.

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

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

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

	2013			2012			2011
	(In millions)
Electric	$	26		$	29		$	33
Gas	4			4			2
Gas Storage and Pipelines	3			6			8
Power and Industrial Projects	816			801			238
Energy Trading	43			43			70
Corporate and Other	(24		)	(37		)	(50		)
Discontinued Operations	—			2			—
	$	868		$	848		$	301

Financial data of the business segments follows:

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures
	(In millions)
2013
Electric	$	5,199		$	902	$	(1	)	$	268		$	252		$	484		$	17,508		$	1,208	$	1,325
Gas	1,474			95		(7		)	58			77			143			3,938			743		209
Gas Storage and Pipelines	132			23		(7		)	18			45			70			824			24		245
Power and Industrial Projects	1,950			72		(6		)	27			(45		)	66			1,067			26		93
Energy Trading	1,771			1		—			8			(38		)	(58		)	623			17		3
Corporate and Other	3			1		(51		)	120			(37		)	(44		)	2,945			—		1
Reclassifications and Eliminations	(868		)	—		63			(63		)	—			—			(970		)	—		—
Total	$	9,661		$	1,094	$	(9	)	$	436		$	254		$	661		$	25,935		$	2,018	$	1,876

109

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures
	(In millions)
2012
Electric	$	5,293		$	827	$	(1	)	$	272		$	280		$	483		$	17,755		$	1,208	$	1,230
Gas	1,315			92		(7		)	59			50			115			4,059			745		221
Gas Storage and Pipelines	96			8		(8		)	8			39			61			668			22		233
Power and Industrial Projects	1,823			65		(7		)	37			(44		)	42			991			26		83
Energy Trading	1,109			2		—			8			7			12			629			17		1
Corporate and Other	3			1		(52		)	121			(46		)	(47		)	3,074			—		3
Reclassifications and Eliminations	(848		)	—		65			(65		)	—			—			(837		)	—		—
Total from Continuing Operations	$	8,791		$	995	$	(10	)	$	440		$	286		$	666		$	26,339		$	2,018	$	1,771
Discontinued Operations (Note 7)															(56		)	—			—		49
Total															$	610		$	26,339		$	2,018	$	1,820

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures
	(In millions)
2011
Electric	$	5,154		$	818	$	(1	)	$	289		$	265		$	434		$	17,567		$	1,208	$	1,203
Gas	1,505			89		(7		)	64			60			110			4,065			745		179
Gas Storage and Pipelines	91			6		(5		)	7			35			57			538			22		16
Power and Industrial Projects	1,129			60		(8		)	32			11			38			789			26		56
Energy Trading	1,276			3		—			9			34			52			612			17		1
Corporate & Other	4			1		(47		)	145			(136		)	23			2,605			—		—
Reclassifications and Eliminations	(301		)	—		58			(58		)	(1		)	—			(485		)	—		—
Total from Continuing Operations	$	8,858		$	977	$	(10	)	$	488		$	268		$	714		$	25,691		$	2,018	$	1,455
Discontinued Operations (Note 7)															(3		)	318			2		29
Total															$	711		$	26,009		$	2,020	$	1,484

110

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 23 — SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

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

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
	(In millions, except per share amounts)
2013
Operating Revenues	$	2,516	$	2,225	$	2,387	$	2,533	$	9,661
Operating Income	$	410	$	223	$	329	$	241	$	1,203
Net Income Attributable to DTE Energy Company	$	234	$	105	$	198	$	124	$	661
Basic Earnings per Share	$	1.35	$	0.60	$	1.13	$	0.70	$	3.76
Diluted Earnings per Share	$	1.34	$	0.60	$	1.13	$	0.70	$	3.76

2012
Operating Revenues	$	2,239	$	2,013		$	2,190	$	2,349		$	8,791
Operating Income	$	312	$	294		$	406	$	267		$	1,279
Net Income Attributable to DTE Energy Company
Continuing Operations	$	156	$	147		$	226	$	137		$	666
Discontinued Operations	—		(1		)	1		(56		)	(56		)
Net Income Attributable to DTE Energy Company	$	156	$	146		$	227	$	81		$	610
Basic Earnings per Share
Continuing Operations	$	0.91	$	0.87		$	1.31	$	0.79		$	3.89
Discontinued Operations	—		(0.01		)	0.01		(0.32		)	(0.33		)
Total	$	0.91	$	0.86		$	1.32	$	0.47		$	3.56
Diluted Earnings per Share
Continuing Operations	$	0.91	$	0.87		$	1.30	$	0.79		$	3.88
Discontinued Operations	—		(0.01		)	0.01		(0.32		)	(0.33		)
Total	$	0.91	$	0.86		$	1.31	$	0.47		$	3.55

111

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

See Item 8. Financial Statements and Supplementary Data for management’s evaluation of disclosure controls and procedures, its report on internal control over financial reporting, and its conclusion on changes in internal control over financial reporting.

Item 9B. Other Information

None.

Part III

Item 10. Directors, Executive Officers and Corporate Governance

Item 11. Executive Compensation

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13. Certain Relationships and Related Transactions, and Director Independence

Item 14. Principal Accountant Fees and Services

Information required by Part III (Items 10, 11, 12, 13 and 14) of this Form 10-K is incorporated by reference from DTE Energy’s definitive Proxy Statement for its 2014 Annual Meeting of Shareholders to be held May 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.

112

Part IV

Item 15. Exhibits and Financial Statement Schedules

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

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

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

(3) Exhibits.

	(i) Exhibits filed herewith:
4-282	Supplemental Indenture, dated as of December 1, 2013, between DTE Energy Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee. (2013 Series F Senior Notes due 2023)
4-283	Forty-Fourth Supplemental Indenture, dated as of December 1, 2013 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between DTE Gas Company and Citibank, N.A. (2013 Series C, D, and E)
12-56	Computation of Ratio of Earnings to Fixed Charges
21-9	Subsidiaries of the Company
23-27	Consent of PricewaterhouseCoopers LLP
31-87	Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report
31-88	Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report
99-55	First Amendment to the Amendment and Restatement of Master Trust Agreement for the DTE Energy Company Master Plan Trust between DTE Energy Corporate Services, LLC and DTE Energy Investment Committee and JP Morgan Chase Bank, N.A., dated as of March 13, 2013.
99-56	Second Amendment to the Amendment and Restatement of Master Trust Agreement for the DTE Energy Company Master Plan Trust between DTE Energy Corporate Services, LLC and DTE Energy Investment Committee and JP Morgan Chase Bank, N.A., dated as of September 30, 2013.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Database
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

	(ii) Exhibits incorporated herein by reference:
	Certain exhibits listed below refer to "The Detroit Edison Company" and "Michigan Consolidated Gas Company" and were effective prior to the change to DTE Electric Company and DTE Gas Company, respectively, effective January 1, 2013.
3(a)	Amended and Restated Articles of Incorporation of DTE Energy Company, dated December 13, 1995 and as amended from time to time (Exhibit 3-1 to Form 8-K dated May 6, 2010).
3(b)	Amended Bylaws of DTE Energy Company, as amended through May 5, 2011 (Exhibit 3-11 to Form 10-Q for the quarter ended September 30, 2011).
4(a)	Amended and Restated Indenture, dated as of April 9, 2001, between DTE Energy Company and The Bank of New York, as trustee (Exhibit 4.1 to Registration Statement on Form S-3 (File No. 333-58834)) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below:
	Supplemental Indenture, dated as of April 1, 2003, between DTE Energy Company and The Bank of New York, as trustee (Exhibit 4(o) to Form 10-Q for the quarter ended March 31, 2003). (2003 Series A 63/8% Senior Notes due 2033)

113

	Supplemental Indenture, dated as of May 15, 2006, between DTE Energy Company and The Bank of New York, as trustee (Exhibit 4-239 to Form 10-Q for the quarter ended June 30, 2006). (2006 Series B 6.35% Senior Notes due 2016)
	Supplemental Indenture, dated as of May 1, 2009, between DTE Energy Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-1 to Form 8-K dated May 13, 2009). (2009 Series A 7.625% Senior Notes due 2014)
	Supplemental Indenture, dated as of December 1, 2011, between DTE Energy Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-274 to Form 8-K dated December 7, 2011). (2011 Series I 6.50% Junior Subordinated Debentures due 2061)
	Supplemental Indenture, dated as of September 1, 2012, between DTE Energy Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-275 to Form 8-K dated October 1, 2012) (2012 Series C 5.25% Junior Subordinated Debentures due 2062)
4(b)	Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-1 to Detroit Edison's Registration Statement on Form A-2 (File No. 2-1630)) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below:
	Supplemental Indenture, dated as of December 1, 1940, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-14 to Detroit Edison's Registration Statement on Form A-2 (File No. 2-4609)). (amendment)
	Supplemental Indenture, dated as of September 1, 1947, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-20 to Detroit Edison's Registration Statement on Form S-1 (File No. 2-7136)). (amendment)
	Supplemental Indenture, dated as of March 1, 1950, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-22 to Detroit Edison's Registration Statement on Form S-1 (File No. 2-8290)). (amendment)
	Supplemental Indenture, dated as of November 15, 1951, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit B-23 to Detroit Edison's Registration Statement on Form S-1 (File No. 2-9226)). (amendment)
	Supplemental Indenture, dated as of August 15, 1957, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 3-B-30 to Detroit Edison's Form 8-K dated September 11, 1957). (amendment)
	Supplemental Indenture, dated as of December 1, 1966, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 2-B-32 to Detroit Edison's Registration Statement on Form S-9 (File No. 2-25664)). (amendment)
	Supplemental Indenture, dated as of February 15, 1990, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-212 to Detroit Edison's Form 10-K for the year ended December 31, 2000). (1990 Series B and C)
	Supplemental Indenture, dated as of May 1, 1991, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-178 to Detroit Edison's Form 10-K for the year ended December 31, 1996). (1991 Series CP)
	Supplemental Indenture, dated as of May 15, 1991, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-179 to Detroit Edison's Form 10-K for the year ended December 31, 1996). (1991 Series DP)
	Supplemental Indenture, dated as of February 29, 1992, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-187 to Detroit Edison's Form 10-Q for the quarter ended March 31, 1998). (1992 Series AP)

114

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

Supplemental Indenture, dated as of August 1, 2000, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-210 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2000). (2000 Series BP)

Supplemental Indenture, dated as of September 17, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Detroit Edison's Registration Statement on Form S-3 (File No. 333-100000)). (amendment and successor trustee)

Supplemental Indenture, dated as of October 15, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-230 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2002). (2002 Series B)

Supplemental Indenture, dated as of March 15, 2004, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-238 to Detroit Edison's Form 10-Q for the quarter ended March 31, 2004). (2004 Series A and B)

Supplemental Indenture, dated as of July 1, 2004, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-240 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2004). (2004 Series D)

Supplemental Indenture, dated as of April 1, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between Detroit Edison and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.3 to Detroit Edison's Registration Statement on Form S-4 (File No. 333-123926)). (2005 Series AR and BR)

Supplemental Indenture, dated as of September 15, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.2 to Detroit Edison's Form 8-K dated September 29, 2005). (2005 Series C)

Supplemental Indenture, dated as of September 30, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between Detroit Edison and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-248 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2005). (2005 Series E)

Supplemental Indenture, dated as of May 15, 2006, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-250 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2006). (2006 Series A)

Supplemental Indenture, dated as of May 1, 2008 to Mortgage and Deed of Trust, dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-253 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2008). (2008 Series ET)

Supplemental Indenture, dated as of June 1, 2008 to Mortgage and Deed of Trust, dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-255 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2008). (2008 Series G)

Supplemental Indenture, dated as of July 1, 2008 to Mortgage and Deed of Trust, dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-257 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2008). (2008 Series KT)

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

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

115

	Supplemental Indenture, dated as of September 1, 2010, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-271 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2010). (2010 Series A)
	Supplemental Indenture, dated as of December 1, 2010, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-273 to Detroit Edison's Form 10-K for the year ended December 31, 2010). (2010 Series CT)
	Supplemental Indenture, dated as of March 1, 2011, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-274 to Detroit Edison's Form 10-Q for the quarter ended March 31, 2011). (2011 Series AT)
	Supplemental Indenture, dated as of May 15, 2011, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-275 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2011). (2011 Series B)
	Supplemental Indenture, dated as of August 1, 2011, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-276 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2011). (2011 Series GT)
	Supplemental Indenture, dated as of August 15, 2011, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-277 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2011). (2011 Series D, 2011 Series E, 2011 Series F)
	Supplemental Indenture, dated as of September 1, 2011, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-278 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2011). (2011 Series H)
	Supplemental Indenture dated as of June 20, 2012, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-279 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2012). (2012 Series A and B)
	Supplemental Indenture, dated as of March 15, 2013, to the Mortgage and Deed of Trust dated as of October 1, 1924, between DTE Electric Company and The Bank of New York Mellon, N.A., as successor trustee (Exhibit 4-280 to DTE Electric Form 10-Q for the quarter ended March 31, 2013). (2013 Series A)
	Supplemental Indenture, dated as of August 1, 2013, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between DTE Electric Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-281 to DTE Electric Form 10-Q for the quarter ended September 30, 2013). (2013 Series B)
4(c)	Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-152 to Detroit Edison's Registration Statement (File No. 33-50325)) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below:
	Tenth Supplemental Indenture, dated as of October 23, 2002, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-231 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2002). (6.35% Senior Notes due 2032)
	Thirteenth Supplemental Indenture, dated as of April 1, 2004, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-237 to Detroit Edison's Form 10-Q for the quarter ended March 31, 2004). (4.875% Senior Notes Due 2029 and 4.65% Senior Notes due 2028)
	Fourteenth Supplemental Indenture, dated as of July 15, 2004, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-239 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2004). (2004 Series D 5.40% Senior Notes due 2014)

116

	Sixteenth Supplemental Indenture, dated as of April 1, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Detroit Edison's Registration Statement on Form S-4 (File No. 333-123926)). (2005 Series AR 4.80% Senior Notes due 2015 and 2005 Series BR 5.45% Senior Notes due 2035)
	Eighteenth Supplemental Indenture, dated as of September 15, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Detroit Edison's Form 8-K dated September 29, 2005). (2005 Series C 5.19% Senior Notes due October 1, 2023)
	Nineteenth Supplemental Indenture, dated as of September 30, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-247 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2005). (2005 Series E 5.70% Senior Notes due 2037)
	Twentieth Supplemental Indenture, dated as of May 15, 2006, to the Collateral Trust Indenture dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-249 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2006). (2006 Series A Senior Notes due 2036)
	Twenty-second Supplemental Indenture, dated as of December 1, 2007, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Detroit Edison's Form 8-K dated December 18, 2007). (2007 Series A Senior Notes due 2038)
	Twenty-fourth Supplemental Indenture, dated as of May 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-254 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2008). (2008 Series ET Variable Rate Senior Notes due 2029)
	Amendment dated June 1, 2009 to the Twenty-fourth Supplemental Indenture, dated as of May 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-265 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2009) (2008 Series ET Variable Rate Senior Notes due 2029)
	Twenty-fifth Supplemental Indenture, dated as of June 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-256 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2008). (2008 Series G 5.60% Senior Notes due 2018)
	Twenty-sixth Supplemental Indenture, dated as of July 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-258 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2008). (2008 Series KT Variable Rate Senior Notes due 2020)
	Amendment dated June 1, 2009 to the Twenty-sixth Supplemental Indenture, dated as of July 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-266 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2009) (2008 Series KT Variable Rate Senior Notes due 2020)
	Twenty-ninth Supplemental Indenture, dated as of March 15, 2009, to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-264 to Detroit Edison's Form 10-Q for the quarter ended March 31, 2009). (2009 Series BT 6.00% Senior Notes due 2036)
	Thirty-first Supplemental Indenture, dated as of August 1, 2010 to the Collateral Trust Indenture, dated as of June 1, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-270 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2010). (2010 Series B 3.45% Senior Notes due 2020)
	Thirty-second Supplemental Indenture, dated as of September 1, 2010, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-272 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2010). (2010 Series A 4.89% Senior Notes due 2020)
4(d)	Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., as trustee, related to Senior Debt Securities (Exhibit 4-1 to Michigan Consolidated Gas Company Registration Statement on Form S-3 (File No. 333-63370)) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below:

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	Fourth Supplemental Indenture dated as of February 15, 2003, to the Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-3 to Michigan Consolidated Gas Company Form 10-Q for the quarter ended March 31, 2003). (5.70% Senior Notes, 2003 Series A due 2033)
	Fifth Supplemental Indenture dated as of October 1, 2004, to the Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-6 to Michigan Consolidated Gas Company Form 10-Q for the quarter ended September 31, 2004). (5.00% Senior Notes, 2004 Series E due 2019)
	Sixth Supplemental Indenture dated as of April 1, 2008, to the Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-241 to Form 10-Q for the quarter ended March 31, 2008). (5.26% Senior Notes, 2008 Series A due 2013, 6.04% Senior Notes, 2008 Series B due 2018 and 6.44% Senior Notes, 2008 Series C due 2023)
	Seventh Supplemental Indenture, dated as of June 1, 2008 to Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-243 to Form 10-Q for the quarter ended June 30, 2008). (6.78% Senior Notes, 2008 Series F due 2028)
	Eighth Supplemental Indenture, dated as of August 1, 2008 to Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-251 to Form 10-Q for the quarter ended September 30, 2008). (5.94% Senior Notes, 2008 Series H due 2015 and 6.36% Senior Notes, 2008 Series I due 2020)
4(e)	Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 (Exhibit 7-D to Michigan Consolidated Gas Company Registration Statement No. 2-5252) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below:
	Thirty-second Supplemental Indenture dated as of January 5, 1993 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-1 to Michigan Consolidated Gas Company Form 10-K for the year ended December 31, 1992). (First Mortgage Bonds Designated Secured Term Notes, Series B)
	Thirty-seventh Supplemental Indenture dated as of February 15, 2003 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-4 to Michigan Consolidated Gas Company Form 10-Q for the quarter ended March 31, 2003). (5.70% collateral bonds due 2033)
	Thirty-eighth Supplemental Indenture dated as of October 1, 2004 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-5 to Michigan Consolidated Gas Company Form 10-Q for the quarter ended September 31, 2004). (2004 Series E collateral bonds)
	Thirty-ninth Supplemental Indenture, dated as of April 1, 2008 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-240 to Form 10-Q for the quarter ended March 31, 2008). (2008 Series B and C Collateral Bonds)
	Fortieth Supplemental Indenture, dated as of June 1, 2008 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-242 to Form 10-Q for the quarter ended June 30, 2008). (2008 Series F Collateral Bonds)
	Forty-first Supplemental Indenture, dated as of August 1, 2008 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-250 to Form 10-Q for the quarter ended September 30, 2008). (2008 Series H and I Collateral Bonds)
	Forty-third Supplemental Indenture, dated as of December 1, 2012 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee (Exhibit 4-279 to Form 10-K for the year ended December 31, 2012). (2012 Series D Collateral Bonds)
10(a)	Form of Indemnification Agreement between DTE Energy Company and each of Gerard M. Anderson, Steven E. Kurmas, David E. Meador, Gerardo Norcia, Peter B. Oleksiak, Bruce D. Peterson, and non-employee Directors (Exhibit 10-1 to Form 8-K dated December 6, 2007).
10(b)	Certain arrangements pertaining to the employment of Gerard M. Anderson with The Detroit Edison Company, dated October 6, 1993 (Exhibit 10-48 to The Detroit Edison Company's Form 10-K for the year ended December 31, 1993).
10(c)	Certain arrangements pertaining to the employment of David E. Meador with The Detroit Edison Company, dated January 14, 1997 (Exhibit 10-5 to Form 10-K for the year ended December 31, 1996).

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10(d)	Certain arrangements pertaining to the employment of Bruce D. Peterson, dated May 22, 2002 (Exhibit 10-48 to Form 10-Q for the quarter ended June 30, 2002).
10(e)	DTE Energy Company Annual Incentive Plan (Exhibit 10-44 to Form 10-Q for the quarter ended March 31, 2001).
10(f)	Amended and Restated DTE Energy Company 2006 Long-Term Incentive Plan (as Amended and Restated effective as of May 6, 2010 and as Amended May 3, 2012) (Exhibit A to DTE Energy's Definitive Proxy Statement dated March 15, 2012).
10(g)	DTE Energy Company Retirement Plan for Non-Employee Directors' Fees (as Amended and Restated effective as of December 31, 1998) (Exhibit 10-31 to Form 10-K for the year ended December 31, 1998).
10(h)	The Detroit Edison Company Supplemental Long-Term Disability Plan, dated January 27, 1997 (Exhibit 10-4 to Form 10-K for the year ended December 31, 1996).
10(i)	Description of Executive Life Insurance Plan (Exhibit 10-47 to Form 10-Q for the quarter ended June 30, 2002).
10(j)	DTE Energy Affiliates Nonqualified Plans Master Trust, effective as of August 15, 2013 (Exhibit 10-87 to Form 10-Q for the quarter ended September 30, 2013).
10(k)	Form of Director Restricted Stock Agreement (Exhibit 10.1 to Form 8-K dated June 23, 2005).
10(l)	Form of Director Restricted Stock Agreement pursuant to the DTE Energy Company Long-Term Incentive Plan (Exhibit 10.1 to Form 8-K dated June 29, 2006).
10(m)	DTE Energy Company Executive Supplemental Retirement Plan as Amended and Restated, effective as of January 1, 2005 (Exhibit 10.75 to Form 10-K for the year ended December 31, 2008).
	First Amendment to the DTE Energy Company Executive Supplemental Retirement Plan (Amended and Restated Effective January 1, 2005) dated as of December 2, 2009 (Exhibit 10.1 to Form 8-K dated December 8, 2009).
	Second Amendment to the DTE Energy Company Executive Supplemental Retirement Plan (Amended and Restated Effective January 1, 2005) dated as of May 5, 2011 (Exhibit 10.80 to Form 10-Q for the quarter ended March 31, 2012).
10(n)	DTE Energy Company Supplemental Retirement Plan as Amended and Restated, effective as of January 1, 2005 (Exhibit 10.76 to Form 10-K for the year ended December 31, 2008).
10(o)	DTE Energy Company Supplemental Savings Plan as Amended and Restated, effective as of January 1, 2005 (Exhibit 10.77 to Form 10-K for the year ended December 31, 2008).
	Second Amendment to the DTE Energy Supplemental Savings Plan dated as of November 13, 2012 (Exhibit 10.81 to the Form 10-K for the year ended December 31, 2012).
10(p)	DTE Energy Company Executive Deferred Compensation Plan as Amended and Restated, effective as of January 1, 2005 (Exhibit 10.78 to Form 10-K for the year ended December 31, 2008).
10(q)	DTE Energy Company Plan for Deferring the Payment of Directors' Fees as Amended and Restated, effective as of January 1, 2005 (Exhibit 10.79 to Form 10-K for the year ended December 31, 2008).
10(r)	DTE Energy Company Deferred Stock Compensation Plan for Non-Employee Directors as Amended and Restated, effective January 1, 2005 (Exhibit 10.80 to Form 10-K for the year ended December 31, 2008).
10(s)	Form of Second Amended and Restated DTE Energy Company Five-Year Credit Agreement, dated as of October 21, 2011 and amended and restated as of April 5, 2013, by and among DTE Energy Company, the lenders party thereto, Citibank, N.A., as Administrative Agent, and Barclays Bank PLC, The Bank of Nova Scotia and JPMorgan Chase Bank, N.A. as Co-Syndication Agents (Exhibit 10.01 to Form 8-K filed on April 9, 2013).
10(t)	Form of Second Amended and Restated DTE Gas Company Five-Year Credit Agreement, dated as of October 21, 2011 and amended and restated as of April 5, 2013, by and among DTE Gas Company, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Barclays Bank PLC, Citibank, N.A., and Bank of America, N.A., as Co-Syndication Agents (Exhibit 10.02 to Form 8-K filed on April 9, 2013).
10(u)	Form of Second Amended and Restated DTE Electric Company Five-Year Credit Agreement, dated as of October 21, 2011 and amended and restated as of April 5, 2013, by and among DTE Electric Company, the lenders party thereto, Barclays Bank PLC, as Administrative Agent, and Citibank, N.A., JPMorgan Chase Bank, N.A., and The Royal Bank of Scotland plc as Co-Syndication Agents (Exhibit 10.01 to DTE Energy Company's and DTE Electric Company's Form 8-K filed on April 9, 2013).
10(v)	Form of Change-in-Control Agreement, dated as of November 8, 2007, between DTE Energy Company and each of Gerard M. Anderson, Steven E. Kurmas, David E. Meador, Gerardo Norcia and Bruce D. Peterson (Exhibit 10-71 to Form 10-Q for the quarter ended September 30, 2007).

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99(a)	Amendment and Restatement of Master Trust Agreement for the DTE Energy Company Master Plan Trust between DTE Energy Corporate Services, LLC and DTE Energy Investment Committee and JP Morgan Chase Bank, N.A., dated as of October 15, 2010.
	(iii) Exhibits furnished herewith:
32-87	Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report
32-88	Chief Financial Officer Section 906 Form 10-K Certification of Periodic Report

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DTE Energy Company

Schedule II — Valuation and Qualifying Accounts

	Year Ending December 31,
	2013			2012			2011
	(In millions)
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statements of Financial Position)
Balance at Beginning of Period	$	62		$	162		$	196
Additions:
Charged to costs and expenses	94			79			94
Charged to other accounts (a)	23			16			18
Deductions (b)	(124		)	(195		)	(146		)
Balance at End of Period	$	55		$	62		$	162

_______________________________________

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

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Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	DTE ENERGY COMPANY
	(Registrant)
By	/s/  GERARD M. ANDERSON
	Gerard M. Anderson Chairman of the Board and Chief Executive Officer

Date: February 14, 2014

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

By	/s/  GERARD M. ANDERSON	By	/s/  PETER B. OLEKSIAK
	Gerard M. Anderson Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer)		Peter B. Oleksiak Senior Vice President and Chief Financial Officer (Principal Financial Officer)
By	/s/  DONNA M. ENGLAND	By	/s/  JAMES B. NICHOLSON
	Donna M. England Chief Accounting Officer (Principal Accounting Officer)		James B. Nicholson, Director
By	/s/  LILLIAN BAUDER	By	/s/  CHARLES W. PRYOR, JR.
	Lillian Bauder, Director		Charles W. Pryor, Jr., Director
By	/s/  DAVID A. BRANDON	By	/s/  JOSUE ROBLES, JR.
	David A. Brandon, Director		Josue Robles, Jr., Director
By	/s/  W. FRANK FOUNTAIN, JR.	By	/s/  RUTH G. SHAW
	W. Frank Fountain, Jr., Director		Ruth G. Shaw, Director
By	/s/  CHARLES G. MCCLURE JR.	By	/s/  DAVID A. THOMAS
	Charles G. McClure Jr., Director		David A. Thomas, Director
By	/s/  GAIL J. MCGOVERN	By	/s/  JAMES H. VANDENBERGHE
	Gail J. McGovern, Director		James H. Vandenberghe, Director
By	/s/  MARK A. MURRAY
	Mark A. Murray, Director

Date: February 14, 2014

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EX-4.282

EXHIBIT 4-282

DTE ENERGY COMPANY
ANDTHE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.,
TRUSTEE

__________________________

SUPPLEMENTAL INDENTURE
DATED AS OF NOVEMBER 1, 2013

__________________________

SUPPLEMENTING THE AMENDED AND RESTATED INDENTURE
DATED AS OF APRIL 9, 2001

PROVIDING FOR

2013 SERIES F 3.85% SENIOR NOTES DUE 2023

1

SUPPLEMENTAL INDENTURE, dated as of the 1st day of November, 2013, between DTE ENERGY COMPANY, a corporation organized and existing under the laws of the State of Michigan (the “Company”), and The Bank of New York Mellon Trust Company, N.A., as successor trustee (the “Trustee”);

WHEREAS, the Company has heretofore executed and delivered to the Trustee an Amended and Restated Indenture, dated as of April 9, 2001 (the “Original Indenture”), as amended, supplemented or modified (as so amended, supplemented or modified, the “Indenture”) providing for the issuance by the Company from time to time of its debt securities; and

WHEREAS, the Company now desires to provide for the issuance of a series of its unsecured, senior debt securities pursuant to the Original Indenture; and

WHEREAS, the Company, in the exercise of the power and authority conferred upon and reserved to it under the provisions of the Original Indenture, including Section 901 thereof, and pursuant to appropriate resolutions of the Board of Directors, has duly determined to make, execute and deliver to the Trustee this Supplemental Indenture to the Original Indenture as permitted by Section 201 and Section 301 of the Original Indenture in order to establish the form or terms of, and to provide for the creation and issue of, a series of its debt securities under the Original Indenture, which shall be known as the “2013 Series F 3.85% Senior Notes due 2023”; and

WHEREAS, all things necessary to make such debt securities, when executed by the Company and authenticated and delivered by the Trustee or any Authenticating Agent and issued upon the terms and subject to the conditions hereinafter and in the Original Indenture set forth against payment therefor, the valid, binding and legal obligations of the Company and to make this Supplemental Indenture a valid, binding and legal agreement of the Company, have been done;

NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE WITNESSETH that, in order to establish the terms of a series of debt securities, and for and in consideration of the premises and of the covenants contained in the Original Indenture and in this Supplemental Indenture and for other good and valuable consideration the receipt and sufficiency of which are hereby acknowledged, it is mutually covenanted and agreed as follows:

article 1
DEFINITIONS AND OTHER
PROVISIONS OF GENERAL APPLICATION

SECTION 101.Definitions. Each capitalized term that is used herein and is defined in the Original Indenture shall have the meaning specified in the Original Indenture unless such term is otherwise defined herein. The following terms shall have the respective meanings set forth below:

“Business Day” means any day other than a Saturday or Sunday or a day on which commercial banks in the

1

state of New York or the state of Michigan are required or authorized by law or executive order to be closed.

SECTION 102.Section References. Each reference to a particular section set forth in this Supplemental Indenture shall, unless the context otherwise requires, refer to this Supplemental Indenture.

ARTICLE 2
TITLE AND TERMS OF THE SECURITIES

SECTION 201.Title of the Securities; Stated Maturity. This Supplemental Indenture hereby establishes a series of Securities, which shall be known as the Company's “2013 Series F 3.85% Senior Notes due 2023” (the “Notes”). The Stated Maturity on which the principal of the Notes shall be due and payable will be December 1, 2023.

SECTION 202.Rank. The Notes shall rank equally with all other unsecured and unsubordinated indebtedness of the Company from time to time outstanding.

SECTION 203.Variations from the Original Indenture. Section 1009 of the Original Indenture shall be applicable to the Notes. Section 403(2) and Section 403(3) shall be applicable to the Notes; the Company's obligations under Section 1009, without limitation, shall be subject to defeasance in accordance with Section 403(3).

SECTION 204.Amount and Denominations; DTC. (a)  The aggregate principal amount of the Notes that may be issued under this Supplemental Indenture is limited initially to $300,000,000 (except as provided in Section 301(2) of the Original Indenture); provided that the Company may, without the consent of the Holders of the Outstanding Notes, “reopen” the Notes so as to increase the aggregate principal amount of the Notes Outstanding in compliance with the procedures set forth in the Original Indenture, including Section 301 and Section 303 thereof, so long as any such additional Notes have the same tenor and terms (including, without limitation, rights to receive accrued and unpaid interest) as the Notes then Outstanding. No additional Notes may be issued if an Event of Default has occurred. The Notes shall be issuable only in fully registered form and, as permitted by Section 301 and Section 302 of the Original Indenture, in denominations of $1,000 and integral multiples thereof. The Notes will initially be issued in global form (the “Global Notes”) under a book-entry system, registered in the name of The Depository Trust Company, as depository (“DTC”), or its nominee, which is hereby designated as “Depositary” under the Indenture.

(b)Further to Section 305 of the Original Indenture, any Global Note shall be exchangeable for Notes registered in the name of, and a transfer of a Global Note may be registered to, any Person other than the Depositary for such Note or its nominee only if (i) such Depositary notifies the Company that it is unwilling or unable to continue as Depositary for such Global Note or if at any time such Depositary ceases to be a clearing agency registered under the Exchange Act, and, in either such case, the Company does not appoint a successor Depositary within 90 days thereafter, (ii) the Company executes and delivers to the Trustee a Company Order that such Global

2

Note shall be so exchangeable and the transfer thereof so registrable or (iii) there shall have occurred and be continuing an Event of Default or an event which, with the giving of notice or lapse of time, or both, would constitute an Event of Default with respect to the Notes. Upon the occurrence in respect of a Global Note of any or more of the conditions specified in clause (i), (ii) or (iii) of the preceding sentence, such Global Note may be exchanged for Notes registered in the name of, and the transfer of such Global Note may be registered to, such Persons (including Persons other than the Depositary and its nominees) as such Depositary, in the case of an exchange, and the Company, in the case of a transfer, shall direct.

SECTION 205.Terms of the Notes.

(a)    The Notes shall bear interest at the rate of 3.85% per annum on the principal amount thereof from November 25, 2013, or from the most recent Interest Payment Date to which interest has been paid or duly provided for, until the principal of the Notes becomes due and payable, and on any overdue principal and premium and (to the extent that payment of such interest is enforceable under applicable law) on any overdue installment of interest at the same rate per annum during such overdue period. Interest on the Notes will be payable semiannually in arrears on June 1 and December 1 of each year (each such date, an “Interest Payment Date”), commencing June 1, 2014. The amount of interest payable for any period shall be computed on the basis of twelve 30-day months and a 360-day year.

(b)    In the event that any Interest Payment Date, redemption date or other date of Maturity of the Notes is not a Business Day, then payment of the amount payable on such date will be made on the next succeeding day which is a Business Day (and without any interest or other payment in respect of any such delay), in each case with the same force and effect as if made on such date. The interest installment so payable, and punctually paid or duly provided for, on any Interest Payment Date with respect to any Note will, as provided in the Original Indenture, be paid to the person in whose name the Note (or one or more Predecessor Securities, as defined in said Indenture) is registered at the close of business on the relevant record date for such interest installment, which shall be the fifteenth calendar day (whether or not a Business Day) prior to the relevant Interest Payment Date (the “Regular Record Date”). Any such interest installment not punctually paid or duly provided for shall forthwith cease to be payable to the registered Holders on such Regular Record Date, and may either be paid to the person in whose name the Note (or one or more Predecessor Securities) is registered at the close of business on a Special Record Date to be fixed by the Trustee for the payment of such defaulted interest, notice whereof shall be given to the registered Holders of the Notes not less than ten days prior to such Special Record Date, or may be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange on which the Notes may be listed, and upon such notice as may be required by such exchange, all as more fully provided in the Original Indenture. The principal of, and premium, if any, and the interest on the Notes shall be payable at the office or agency of the Company maintained for that purpose in the Borough of Manhattan, The City of New York, in any coin or currency of the United States of America which at the time of payment is legal tender for payment of public and private debts; provided, however, that payment of interest may be made at the option of the Company by check mailed to the registered Holder at the close of business on the Regular Record Date at such address as shall appear in the Security Register.

3

(c)    The Notes are not subject to repayment at the option of the Holders thereof and are not subject to any sinking fund. As provided in the form of Note attached hereto as Exhibit A, the Notes are subject to optional redemption, as a whole or in part, by the Company prior to Stated Maturity of the principal thereof on the terms set forth therein. Except as modified in the form of the Note, redemption shall be effected in accordance with Article Eleven of the Original Indenture.

(a)The Notes shall have such other terms and provisions as are set forth in the form of Note attached hereto as Exhibit A (which is incorporated by reference in and made a part of this Supplemental Indenture as if set forth in full at this place).

SECTION 206. Form of Notes. Attached hereto as Exhibit A is the form of the Notes.

ARTICLE 3
MISCELLANEOUS PROVISIONS

The Trustee makes no undertaking or representations in respect of, and shall not be responsible in any manner whatsoever for and in respect of, the validity or sufficiency of this Supplemental Indenture or the proper authorization or the due execution hereof by the Company or for or in respect of the recitals and statements contained herein, all of which recitals and statements are made solely by the Company.

Except as expressly amended hereby, the Original Indenture shall continue in full force and effect in accordance with the provisions thereof and the Original Indenture is in all respects hereby ratified and confirmed. This Supplemental Indenture and all its provisions shall be deemed a part of the Original Indenture in the manner and to the extent herein and therein provided.

This Supplemental Indenture and the Notes shall be governed by, and construed in accordance with, the laws of the State of New York.

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

4

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed, all as of the day and year first above written.

DTE ENERGY COMPANY

By: /d/Daniel G.. Brudzynski

Name:     Daniel G. Brudzynski

Title:     Vice President and Treasurer

ATTEST:

By:/s/Lisa A. Muschong

Name: Lisa A. Muschong

Title: Corporate Secretary

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.

By: /s/Richard Tarnas

Name:     Richard Tarnas

Title:     Vice President

5

EXHIBIT A

FORM OF NOTE

THIS NOTE IS A GLOBAL NOTE WITHIN THE MEANING OF THE INDENTURE HEREINAFTER REFERRED TO AND IS REGISTERED IN THE NAME OF A DEPOSITARY OR A NOMINEE OF A DEPOSITARY. UNLESS AND UNTIL IT IS EXCHANGED IN WHOLE OR IN PART FOR NOTES IN CERTIFICATED FORM, THIS NOTE MAY NOT BE TRANSFERRED EXCEPT AS A WHOLE BY THE DEPOSITORY TRUST COMPANY (“DTC”), TO A NOMINEE OF DTC OR BY DTC OR ANY SUCH NOMINEE TO A SUCCESSOR OF DTC OR A NOMINEE OF SUCH SUCCESSOR. UNLESS THIS NOTE IS PRESENTED BY AN AUTHORIZED REPRESENTATIVE OF DTC TO THE ISSUER OR ITS AGENT FOR REGISTRATION OF TRANSFER, EXCHANGE OR PAYMENT, AND ANY NOTE ISSUED IS REGISTERED IN THE NAME OF CEDE & CO., OR IN SUCH OTHER NAME AS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF DTC (AND ANY PAYMENT HEREON IS MADE TO CEDE & CO., OR TO SUCH OTHER ENTITY AS IS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF DTC), ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY A PERSON IS WRONGFUL, INASMUCH AS THE REGISTERED OWNER HEREOF, CEDE & CO., HAS AN INTEREST HEREIN.

CUSIP NO.____________                                 $________
NO. ____

DTE ENERGY COMPANY
2013 SERIES F 3.85% SENIOR NOTES DUE 2023

DTE ENERGY COMPANY, a corporation duly organized and existing under the laws of the State of Michigan (herein referred to as the “Company”, which term includes any successor Person under the Indenture hereinafter referred to), for value received, hereby promises to pay to CEDE & CO., or registered assigns, the principal sum of $_________ on December 1, 2023 (“Stated Maturity” with respect to the principal of this Note), unless previously redeemed, and to pay interest at the rate of 3.85% per annum on said principal sum from November 25, 2013, or from the most recent Interest Payment Date to which interest has been paid or duly provided for, until the principal of this Note becomes due and payable, and on any overdue principal and premium and (to the extent that payment of such interest is enforceable under applicable law) on any overdue installment of interest at the same rate per annum during such overdue period. Interest on this Note will be payable semiannually in arrears on June 1 and December 1 of each year (each such date, an “Interest Payment Date”), commencing June 1, 2014. The amount of interest payable for any period shall be computed on the basis of twelve 30-day months and a 360-day year.

In the event that any Interest Payment Date, redemption date or other date of Maturity of the Notes is not a Business Day, then payment of the amount payable on such date will be made on the next succeeding day which is a Business Day (and without any interest or other payment in respect of any such delay), in each case with the same force and effect as if made on such date. A “Business Day” means any day other than a Saturday or Sunday or a day on which commercial

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banks in the state of New York or the state of Michigan are required or authorized by law or executive order to be closed. The interest installment so payable, and punctually paid or duly provided for, on any Interest Payment Date with respect to this Note will, as provided in the Indenture, be paid to the person in whose name this Note is registered at the close of business on the relevant record date for such interest installment, which shall be the fifteenth calendar day (whether or not a Business Day) prior to the relevant Interest Payment Date (the “Regular Record Date”). Any such interest installment not punctually paid or duly provided for shall forthwith cease to be payable to the registered Holders on such Regular Record Date, and may either be paid to the person in whose name this Note is registered at the close of business on a Special Record Date to be fixed by the Trustee for the payment of such defaulted interest, notice whereof shall be given to the registered Holders of the Notes not less than ten days prior to such Special Record Date, or may be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange on which the Notes may be listed, and upon such notice as may be required by such exchange, all as more fully provided in the Indenture. The principal of, and premium, if any, and the interest on the Notes shall be payable at the office or agency of the Company maintained for that purpose in the Borough of Manhattan, The City of New York, in any coin or currency of the United States of America which at the time of payment is legal tender for payment of public and private debts; provided, however, that payment of interest may be made at the option of the Company by check mailed to the registered Holder at the close of business on the Regular Record Date at such address as shall appear in the Security Register. Notwithstanding anything else contained herein, if this Note is a Global Note and is held in book-entry form through the facilities of the Depositary, payments on this Note will be made to the Depositary or its nominee in accordance with arrangements then in effect between the Trustee and the Depositary.

This Note is one of a duly authorized series of Securities of the Company, designated as the “2013 Series F 3.85% Senior Notes due 2023” (the “Notes”), initially limited to an aggregate principal amount of $300,000,000 (except for Notes authenticated and delivered upon transfer of, or in exchange for, or in lieu of other Notes, and except as further provided in the Indenture), all issued or to be issued under and pursuant to an Amended and Restated Indenture, dated as of April 9, 2001, as supplemented through and including the Supplemental Indenture dated as of November 1, 2013 (together, as amended, supplemented or modified, the “Indenture”), duly executed and delivered between the Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (herein referred to as the “Trustee”, which term includes any successor trustee under the Indenture), to which Indenture reference is hereby made for a description of the respective rights, limitations of rights, obligations, duties and immunities thereunder of the Trustee, the Company and the registered Holders of the Notes and of the terms upon which the Notes are, and are to be, authenticated and delivered.

This Note is not subject to repayment at the option of the Holder hereof. This Note is not subject to any sinking fund.

This Note will be redeemable at the option of the Company, in whole at any time or in part from time to time (any such date of optional redemption, an “Optional Redemption Date,” which shall be a “Redemption Date” for purposes of the Indenture) at the redemption prices set forth below. At any time prior to September 1, 2023 the optional redemption price (which shall be a “Redemption

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Price” for purposes of the Indenture) will be equal to the greater of (i) 100% of the principal amount of this Note to be redeemed and (ii) the sum of the present values of the principal amount of this Note to be redeemed and the remaining scheduled payments of interest on the principal amount of this Note to be redeemed (exclusive of interest accrued to the related Optional Redemption Date) until Stated Maturity, in each case discounted from their respective scheduled payment dates to such Optional Redemption Date on a semiannual basis (assuming a 360-day year consisting of 30-day months) at the Adjusted Treasury Rate (as defined below) plus 20 basis points, plus in either case, accrued interest thereon to the date of redemption. At any time on or after September 1, 2023, the optional redemption price will be equal to 100% of the principal amount of this bond to be redeemed plus accrued and unpaid interest thereon to the redemption date.

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

“Adjusted Treasury Rate” means, with respect to any Optional Redemption Date, the rate per annum equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, calculated on the third Business Day preceding such Optional Redemption Date, using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such Optional Redemption Date.

“Comparable Treasury Issue” means the United States Treasury security determined by the Reference Treasury Dealer as having a maturity comparable to the remaining term of this Note that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity with the remaining term of this Note.

“Comparable Treasury Price” means, with respect to any Optional Redemption Date, (i) the average of the Reference Treasury Dealer Quotations for such Optional Redemption Date, after excluding the highest and lowest such Reference Treasury Dealer Quotations, or (ii) if the Trustee obtains fewer than three such Reference Treasury Dealer Quotations, the average of all such quotations, or (iii) if only one Reference Treasury Dealer Quotation is received, such quotation.

“Reference Treasury Dealer” means each of: (i) Barclays Capital Inc., Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated and RBS Securities Inc. (or their respective affiliates which are Primary Treasury Dealers), and their respective successors; provided, however, that if any of the foregoing cease to be a primary U.S. Government securities dealer in the United States (a “Primary Treasury Dealer”), the Company shall substitute therefor another Primary Treasury Dealer; and (ii) any other Primary Treasury Dealer(s) selected by the Trustee after consultation with the Company.

“Reference Treasury Dealer Quotation” means, with respect to each Reference Treasury Dealer and any Optional Redemption Date, the average, as determined by the Trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Trustee by such Reference Treasury Dealer at 5:00 p.m., New York City time, on the third Business Day preceding such Optional Redemption Date.

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Notice of any optional redemption will be mailed at least 30 days but not more than 60 days before the Optional Redemption Date to the Holder hereof at its registered address.

If money sufficient to pay the applicable Redemption Price with respect to the principal amount of and accrued interest on the principal amount of this Note to be redeemed on the applicable Redemption Date is deposited with the Trustee or Paying Agent on or before the related Redemption Date and certain other conditions are satisfied, then on or after such Redemption Date, interest will cease to accrue on the principal amount of this Note called for redemption. If the Notes are only partially redeemed by the Company, the Trustee shall select which Notes are to be redeemed by lot or in a manner it deems fair and appropriate in accordance with the terms of the Indenture.

In the event of redemption of this Note in part only, a new Note or Notes for the unredeemed portion hereof will be issued in the name of the registered Holder hereof upon the cancellation hereof.

In case an Event of Default, as defined in the Indenture, shall have occurred and be continuing, the principal hereof may be declared, and upon such declaration shall become, due and payable, in the manner, with the effect and subject to the conditions provided in the Indenture.

The Indenture contains provisions for defeasance at any time of the entire indebtedness of this Note upon compliance by the Company with certain conditions set forth therein.

The Indenture permits, with certain exceptions as therein provided, the amendment thereof and the modification of the rights and obligations of the Company and the rights of the Holders of the Notes under the Indenture at any time by the Company and the Trustee with the consent of the Holders of a majority of the aggregate principal amount of all Notes issued under the Indenture at the time outstanding and affected thereby; provided, however, that no such amendment shall without the consent of the Holder of each Note so affected, among other things (i) change the stated maturity of the principal of, or any installment of principal of or interest on any Notes, or reduce the principal amount thereof, or reduce the rate of interest thereon, or reduce any premium payable upon the redemption thereof or (ii) reduce the percentage of Notes, the Holders of which are required to consent to any amendment or waiver or for certain other matters as set forth in the Indenture. The Indenture also contains provisions permitting (i) the registered Holders of 66 2/3% in aggregate principal amount of the Securities at the time outstanding affected thereby, on behalf of the registered Holders of the Securities, to waive compliance by the Company with certain provisions of the Indenture and (ii) the registered Holders of not less than a majority in aggregate principal amount of the Securities at the time outstanding affected thereby, on behalf of the registered Holders of the Securities, to waive certain past defaults under the Indenture and their consequences. Any such consent or waiver by the registered Holder of this Note (unless revoked as provided in the Indenture) shall be conclusive and binding upon such registered Holder and upon all future registered Holders and owners of this Note and of any Note issued in exchange hereof or in place hereof (whether by registration of transfer or otherwise), irrespective of whether or not any notation of such consent or waiver is made upon this Note.

No reference herein to the Indenture and no provision of this Note or of the Indenture shall alter or impair the obligation of the Company, which is absolute and unconditional, to pay the

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principal of and premium, if any, and interest on this Note at the time and place and at the rate and in the coin or currency herein prescribed.

As provided in the Indenture and subject to certain limitations therein set forth, the transfer of this Note is registrable in the Security Register of the Company, upon surrender of this Note for registration of transfer at the office or agency of the Company in any place where the principal of and any interest on this Note are payable or at such other offices or agencies as the Company may designate, duly endorsed by or accompanied by a written instrument or instruments of transfer in form satisfactory to the Company and the Security Registrar or any transfer agent duly executed by the registered Holder hereof or his or her attorney duly authorized in writing, and thereupon one or more new Notes of this series and of like tenor, of authorized denominations and for the same aggregate principal amount will be issued to the designated transferee or transferees. No service charge will be made for any such transfer, but the Company may require payment of a sum sufficient to cover any tax or other governmental charge payable in relation thereto.

Prior to due presentment for registration of transfer of this Note, the Company, the Trustee, any paying agent and any Security Registrar may deem and treat the registered Holder hereof as the absolute owner hereof (whether or not this Note shall be overdue and notwithstanding any notice of ownership or writing hereon made by anyone other than the Security Registrar) for the purpose of receiving payment of or on account of the principal hereof and interest due hereon and for all other purposes, and neither the Company nor the Trustee nor any paying agent nor any Security Registrar shall be affected by any notice to the contrary.

The Notes are issuable only in fully registered form without coupons in denominations of $1,000 and any integral multiple thereof. This Global Note is exchangeable for Notes in definitive form only under certain limited circumstances set forth in the Indenture. The Notes so issued are issuable only in registered form without coupons in denominations of $1,000 and any integral multiple thereof. As provided in the Indenture and subject to certain limitations therein set forth, the Notes are exchangeable for a like aggregate principal amount of the Notes of a different authorized denomination, as requested by the registered Holder surrendering the same.

As set forth in, and subject to the provisions of, the Indenture, no registered owner of any Note will have any right to institute any proceeding with respect to the Indenture or for any remedy thereunder, unless (i) such registered owner shall have previously given to the Trustee written notice of a continuing Event of Default with respect to the Notes, (ii) the registered owners of not less than 25% in principal amount of the outstanding Notes shall have made written request, and offered reasonable indemnity, to the Trustee to institute such proceeding as trustee, (iii) the Trustee shall have failed to institute such proceeding within 60 days and (iv) the Trustee shall not have received from the registered owners of a majority in principal amount of the outstanding Notes a direction inconsistent with such request within such 60-day period; provided, however, that such limitations do not apply to a suit instituted by the registered owner hereof for the enforcement of payment of the principal of or premium, if any, or any interest on this Note on or after the respective due dates expressed herein.

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Unless the Certificate of Authentication hereon has been executed by the Trustee or a duly appointed Authentication Agent referred to herein, this Note shall not be entitled to any benefit under the Indenture or be valid or obligatory for any purpose.

The Indenture and this Note shall be governed by and construed in accordance with the laws of the State of New York.

All terms used in this Note which are defined in the Indenture shall have the meanings assigned to them in the Indenture.

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IN WITNESS WHEREOF, the Company has caused this Instrument to be duly executed.

DTE ENERGY COMPANY

By: ______________________________________

Name: 

Title:     

Date:

Attest:

By: _________________________________

Name: 

Title: 

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CERTIFICATE OF AUTHENTICATION

This is one of the Notes described in the within mentioned Indenture.

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.
as Trustee

By ______________________________________
Authorized Signatory

Date:

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FOR VALUE RECEIVED, the undersigned hereby sell(s), assign(s) and transfer(s) unto

(Please insert Social Security or Other Identifying Number of Assignee)

(Please print or type name and address, including zip code of assignee)

the within Note and all rights thereunder, hereby irrevocably constituting and appointing such person attorneys to transfer the within Note on the books of the Issuer, with full power of substitution in the premises.

Dated:________________________

NOTICE: The signature of this assignment must correspond with the name as written upon the face of the within Note in every particular, without alteration or enlargement or any change whatever and NOTICE: Signature(s) must be guaranteed by a financial institution that is a member of the Securities Transfer Agents Medallion Program (“STAMP”), the Stock Exchange, Inc. Medallion Signature Program (“MSP”). When assignment is made by a guardian, trustee, executor or administrator, an officer of a corporation, or anyone in a representative capacity, proof of his or her authority to act must accompany this Note.

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EX-4.283

EXHIBIT 4-283

FORTY-FOURTH

SUPPLEMENTAL INDENTURE

TO

INDENTURE OF MORTGAGE AND

DEED OF TRUST

DATED AS OF MARCH 1, 1944

AS RESTATED IN

PART II OF THE TWENTY-NINTH

SUPPLEMENTAL INDENTURE DATED AS OF JULY 15, 1989

WHICH BECAME EFFECTIVE ON APRIL 1, 1994

DTE GAS COMPANY

formerly known as

Michigan Consolidated Gas Company

TO

CITIBANK, N.A.,

TRUSTEE

DATED AS OF DECEMBER 1, 2013

CREATING THREE ISSUES OF FIRST MORTGAGE BONDS,

DESIGNATED AS

2013 SERIES C BONDS

2013 SERIES D BONDS

2013 SERIES E BONDS

DTE GAS COMPANY

FORTY-FOURTH SUPPLEMENTAL INDENTURE

DATED AS OF DECEMBER 1, 2013

SUPPLEMENTAL TO INDENTURE OF MORTGAGE

AND DEED OF TRUST

DATED AS OF MARCH 1, 1944

TABLE OF CONTENTS

PAGE

ARTICLE I ESTABLISHMENT OF AN ISSUE OF FIRST MORTGAGE BONDS, OF THE SERIES DESIGNATED AND DISTINGUISHED AS “2013 SERIES C BONDS”5

SECTION 15

SECTION 25

SECTION 37

SECTION 414

SECTION 516

ARTICLE II ESTABLISHMENT OF AN ISSUE OF FIRST MORTGAGE BONDS, OF THE SERIES DESIGNATED AND DISTINGUISHED AS “2013 SERIES D BONDS”16

SECTION 116

SECTION 217

SECTION 318

SECTION 426

SECTION 527

ARTICLE III ESTABLISHMENT OF AN ISSUE OF FIRST MORTGAGE BONDS, OF THE SERIES DESIGNATED AND DISTINGUISHED AS “2013 SERIES E BONDS”28

SECTION 128

SECTION 228

SECTION 330

SECTION 437

SECTION 539

ARTICLE IV ISSUE OF BONDS39

ARTICLE V THE TRUSTEE40

ARTICLE VI RECORDING AND FILING OF SUPPLEMENTAL INDENTURE DATED AS OF DECEMBER 1, 201340

ARTICLE VII RECORDING OF AFFIDAVIT OF FACTS AFFECTING REAL PROPERTY42

ARTICLE VIII MISCELLANEOUS PROVISIONS42

THIS FORTY-FOURTH SUPPLEMENTAL INDENTURE, dated as of the 1st day of December, 2013, between DTE GAS COMPANY, formerly known as Michigan Consolidated Gas Company, a corporation duly organized and existing under and by virtue of the laws of the State of Michigan (hereinafter called the “Company”), having its principal place of business at One Energy Plaza, Detroit, Michigan, and CITIBANK, N.A., a national banking association incorporated and existing under and by virtue of the laws of the United States of America, having an office at 388 Greenwich Street in the Borough of Manhattan, the City of New York, New York, as successor trustee (hereinafter with its predecessors as trustee called the “Mortgage Trustee” or the “Trustee”):

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Forty-third Supplemental Indenture, dated as of December 1, 2012;

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

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Designation of Series	Amount Initially Issued		AmountOutstanding
First Mortgage Bonds
(Secured Term Notes, Series B)
8¼% Bonds due 2014	$	80,000,000	$	80,000,000
2012 Series D First Mortgage Bonds	$	70,000,000	$	70,000,000
Collateral Bonds
(Senior Notes)
5.70% Collateral Bonds due 2033	$	200,000,000	$	200,000,000
2004 Series E Collateral Bonds	$	120,000,000	$	120,000,000
2008 Series B Collateral Bonds	$	100,000,000	$	100,000,000
2008 Series C Collateral Bonds	$	25,000,000	$	25,000,000
2008 Series F Collateral Bonds	$	75,000,000	$	75,000,000
2008 Series H Collateral Bonds	$	140,000,000	$	140,000,000
2008 Series I Collateral Bonds	$	50,000,000	$	50,000,000
2012 Series D Collateral Bonds	$	70,000,000	$	70,000,000

WHEREAS, the Company desires in and by this Supplemental Indenture to establish three series of bonds to be issued under the Indenture designated and distinguished as 2013 Series C Bonds, 2013 Series D Bonds and 2013 Series E Bonds (herein collectively sometimes called the “Bonds”), to designate the terms thereof, to specify the particulars necessary to describe and define the same and to specify such other provisions and agreements in respect thereof as are in the Indenture provided or permitted; and

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

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

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ARTICLE I ESTABLISHMENT OF AN ISSUE OF
FIRST MORTGAGE BONDS, OF THE SERIES
DESIGNATED AND DISTINGUISHED AS “2013 SERIES C BONDS”

SECTION 1

There is hereby established a series of bonds to be issued under and secured by the Indenture, to be known as “First Mortgage Bonds,” designated and distinguished as “2013 Series C Bonds” of the Company. The 2013 Series C Bonds shall be limited in aggregate principal amount to $50,000,000 except as provided in Article IV of the Indenture and in this Supplemental Indenture with respect to transfers, exchanges and replacements of the 2013 Series C Bonds. The 2013 Series C Bonds shall be registered bonds without coupons and shall be dated as of the date of the authentication thereof by the Trustee.

The 2013 Series C Bonds shall mature on the 15th day of December, 2023 (subject to earlier redemption, as provided herein), shall bear interest at the rate of 3.64% per annum, payable semi-annually on the 15th day of June and December of each year and at maturity (each an “2013 Series C Interest Payment Date”), beginning on June 15, 2014. The principal, Make-Whole Amount (as defined below), if any, and interest on the 2013 Series C Bonds shall be payable in lawful money of the United States of America; the place where such principal and Make-Whole Amount, if any, shall be payable shall be the corporate trust office of the Trustee in the Borough of Manhattan, the City of New York, New York, and the place where such interest shall be payable shall be the office or agency of the Company in said Borough of Manhattan, the City of New York, New York. The 2013 Series C Bonds shall have such other terms as set forth in the form of 2013 Series C Bond provided in Section 3.

SECTION 2

The 2013 Series C Bonds shall be subject to redemption at the option of the Company, in whole at any time or in part from time to time (any such date of redemption, a “2013 Series C Redemption Date”), at the applicable redemption price (“2013 Series C Redemption Price”) set forth below.

At any time prior to September 15, 2023, the 2013 Series C Redemption Price will be equal to 100% of the principal amount of the 2013 Series C Bonds to be redeemed on the 2013 Series C Redemption Date together with the Make-Whole Amount (as defined in the form of 2013 Series C Bond provided in Section 3), if any, plus, in each case, accrued and unpaid interest thereon to the 2013 Series C Redemption Date.

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At any time on or after September 15, 2023, the 2013 Series C Redemption Price will be equal to 100% of the principal amount of the bonds of 2013 Series C to be redeemed plus accrued and unpaid interest thereon to the redemption date.

Notwithstanding the foregoing, installments of interest on the 2013 Series C Bonds that are due and payable on 2013 Series C Interest Payment Dates falling on or prior to the 2013 Series C Redemption Date will be payable on the 2013 Series C Interest Payment Date to the registered holders as of the close of business on the relevant record date.

Notice of redemption shall be given to the holders of the 2013 Series C Bonds to be redeemed not more than 60 nor less than 30 days prior to the 2013 Series C Redemption Date, as provided in Section 4.05 of the Indenture. Each such notice shall specify such optional 2013 Series C Redemption Date, the aggregate principal amount of the 2013 Series C Bonds to be redeemed on such date, the principal amount of each 2013 Series C Bond held by such holder to be redeemed, and the interest to be paid on the 2013 Series C Redemption Date with respect to such principal amount being prepaid, and shall be accompanied by a certificate of a senior financial officer of the Company as to the estimated Make-Whole Amount due in connection with such redemption (calculated as if the date of such notice were the date of the redemption), setting forth the details of such computation. The Make-Whole Amount shall be determined by the Company two Business Days prior to the applicable 2013 Series C Redemption Date and the Company shall deliver to holders of the 2013 Series C Bonds and to the Trustee a certificate of a senior financial officer specifying the calculation of such Make-Whole Amount as of the 2013 Series C Redemption Date.

Subject to the limitations of Section 4.07 of the Indenture, the notice of redemption may state that it is subject to the receipt of the redemption moneys by the Trustee on or before the 2013 Series C Redemption Date, and that such notice shall be of no effect unless such moneys are so received on or before such date.

If the 2013 Series C Bonds are only partially redeemed by the Company, the Trustee shall select which 2013 Series C Bonds are to be redeemed pro rata among all of the 2013 Series C Bonds at the time outstanding in proportion, as nearly as practicable, to the respective unpaid principal amounts thereof and otherwise in accordance with the terms of the Indenture. In the event of redemption of the 2013 Series C Bonds in part only, a new 2013 Series C Bond or 2013 Series C Bonds for the unredeemed portion will be issued in the name or names of the holders thereof upon the surrender or cancellation thereof.

If money sufficient to pay the applicable the 2013 Series C Redemption Price with respect to the 2013 Series C Bonds to be redeemed on the applicable 2013 Series C Redemption Date, together with accrued interest to the 2013 Series C Redemption Date, is deposited with the Trustee on or before the related 2013 Series C Redemption Date and certain other conditions are satisfied, then the 2013 Series C Bonds to be redeemed shall no longer be secured by, or entitled to any lien or benefit of, the Indenture as provided by Section 4.04 of the Indenture.

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The 2013 Series C Bonds will not be entitled to any sinking fund and will not be redeemable other than as provided in this Section 2 and the form of 2013 Series C Bond provided in Section 3.

SECTION 3

The 2013 Series C Bonds shall be registered bonds without coupons. The Trustee shall be the registrar and paying agent for the 2013 Series C Bonds, which duties it hereby accepts. The 2013 Series C Bonds may be issued in minimum denominations of $100,000 or any integral multiple of $1,000 in excess thereof.

The forms of 2013 Series C Bonds shall be substantially as follows:

[FORM OF DTE GAS COMPANY 3.64% FIRST MORTGAGE BONDS 2013 SERIES C DUE 2023]

PPN:

No. R-___                        $_________________

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

DTE GAS COMPANY

3.64% MORTGAGE BONDS

2013 SERIES C DUE 2023

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Principal Amount: $____________

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

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

Original Issue Date: December 12, 2013

Stated Maturity: December 15, 2023

Interest Payment Dates: June 15 and December 15 of each year, beginning June 15, 2014.

Interest Rate: 3.64% per annum

DTE GAS COMPANY (hereinafter called the “Company”), a corporation of the State of Michigan, for value received, hereby promises to pay to ___________, or registered assigns, the sum of _________ Dollars ($_________) on the Stated Maturity specified above, in the coin or currency of the United States of America, and to pay interest thereon from the Original Issue Date specified above, or from the most recent Interest Payment Date to which interest has been paid or duly provided for, semi-annually in arrears on each Interest Payment Date as specified above, commencing on June 15, 2014 and on the Stated Maturity at the Interest Rate per annum specified above until the principal hereof is paid or made available for payment, and on any overdue principal and Make-Whole Amount (defined below) and, to the extent lawful, on any overdue installment of interest. The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will, as provided in the Indenture, be paid to the person in whose name this bond is registered at the close of business on the Regular Record Date as specified above next preceding such Interest Payment Date; provided that any interest payable at Stated Maturity or on a Redemption Date (defined below) will be paid to the person to whom principal is payable. Except as otherwise provided in the Indenture, any such interest not so punctually paid or duly provided for will forthwith cease to be payable to the holder on such Regular Record Date and may either be paid to the person in whose name this bond is registered at the close of business on a special record date for the payment of such defaulted interest to be fixed by the Trustee, notice whereof shall be given to holders of bonds of this series not less than 10 days prior to such special record date, or be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange, if any, on which the bonds of this series shall be listed, and upon such notice as may be required by any such exchange, all as more fully provided in the Indenture.

Payments of interest on this bond will include interest accrued to but excluding the respective Interest Payment Dates. Interest payments for this bond shall be computed and paid on the basis of a 360-day year consisting of twelve 30-day months. The Company shall pay interest on overdue principal and Make-Whole Amount, if any, and, to the extent lawful, on overdue installments of interest at the rate per annum borne by this bond. In the event that any Interest Payment Date,

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Redemption Date or Stated Maturity is not a Business Day, then the required payment of principal, Make-Whole Amount, if any, and interest will be made on the next succeeding day that is a Business Day (and without any interest or other payment in respect of any such delay). “Business Day” means any day other than a day on which banking institutions in the State of New York or the State of Michigan are authorized or obligated pursuant to law or executive order to close.

Payment of principal of, Make-Whole Amount, if any, and interest on the bonds of this series shall be made in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts. Payments of principal, Make-Whole Amount, if any, and interest due at the Stated Maturity or earlier redemption of such bonds shall be made at the office of the Trustee upon surrender of such bonds to the Trustee, and (ii) payments of interest shall be made, at the option of the Company, subject to such surrender where applicable, (A) by check mailed to the address of the person entitled thereto as such address shall appear in the bond register of the Trustee maintained for such purpose or (B) by wire transfer at such place and to such account at a banking institution in the United States as may be designated in writing to the Trustee at least fourteen (14) days prior to the date for payment by the person entitled thereto. Notwithstanding the foregoing, so long as any bond is held by an Institutional Investor (as defined in the Bond Purchase Agreement referenced below), payment of principal, Make-Whole Amount, if any, and interest on the bonds held by such holder shall be made in the manner specified in the Bond Purchase Agreement dated as of December 12, 2013 among the Company and the purchasers party thereto.

The bonds represented by this certificate, of the series hereinafter specified, are bonds of the Company (herein called the “bonds”) known as its “First Mortgage Bonds,” issued and to be issued in one or more series under, and all equally and ratably secured by, an Indenture of Mortgage and Deed of Trust dated as of March 1, 1944, duly executed by the Company to Citibank, N.A., successor trustee (“Trustee”) as restated in Part II of the Twenty-ninth Supplemental Indenture dated as of July 15, 1989, which became effective on April 1, 1994, to which indenture and all indentures supplemental thereto executed on and after July 15, 1989 reference is hereby made for a description of the property mortgaged and pledged, the nature and extent of the security, the terms and conditions upon which the bonds are, and are to be, issued and secured, and the rights of the holders of the bonds and of the Trustee in respect of such security (which indenture and all indentures supplemental thereto, including the Forty-fourth Supplemental Indenture dated as of December 1, 2013 referred to below, are hereinafter collectively called the “Indenture”). As provided in the Indenture, the bonds may be issued thereunder for various principal sums and are issuable in series, which may mature at different times, may bear interest at different rates and may otherwise vary as therein provided. The bonds represented by this certificate are part of a series designated “3.64% First Mortgage Bonds 2013 Series C,” (herein called the “Bonds”) created by the Forty-fourth Supplemental Indenture dated as of December 1, 2013 as provided for in said Indenture.

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

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

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

This Bond shall be subject to redemption at the option of the Company, in whole at any time or in part from time to time (any such date of optional redemption, a “Redemption Date”), at the applicable redemption price (“Redemption Price”) set forth below.

At any time prior to September 15, 2023, the Redemption Price will be equal to 100% of the principal amount of the Bonds to be redeemed on the Redemption Date together with the Make-Whole Amount (as defined below), if any, plus, in each case, accrued and unpaid interest thereon to the Redemption Date.

At any time on or after September 15, 2023, the Redemption Price will be equal to 100% of the principal amount of the bonds of 2013 Series C to be redeemed plus accrued and unpaid interest thereon to the redemption date.

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

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

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

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

“Reinvestment Yield” means, with respect to the Called Principal of a Bond, 0.5% (50 basis points) plus the yield to maturity implied by (i) the yields reported, as of 10:00 a.m. (New York City time) on the second Business Day preceding the Settlement Date with respect to such Called Principal, on the display designated as “PX-1” (or such other display as may replace Page PX-1), on Bloomberg Financial Markets for the most recently issued, actively traded on-the-run, benchmark U.S. Treasury securities having a maturity equal to the Remaining Average Life of such Called Principal as of such Settlement Date, or (ii) if such yields are not reported as of such time or the yields reported as of such time are not ascertainable (including by way of interpolation), the Treasury Constant Maturity Series Yields reported, for the latest day for which such yields have been so reported as of the second Business Day preceding the Settlement Date with respect to such Called Principal, in Federal Reserve Statistical Release H.15 (519) (or any comparable successor publication) for actively traded U.S. Treasury securities having a constant maturity equal to the Remaining Average Life of such Called Principal as of such Settlement Date. Such implied yield will be determined, if necessary, by (a) converting U.S. Treasury bill quotations to bond-equivalent yields in accordance with accepted financial practice and (b) interpolating linearly on a straight line basis between (1) the most recently issued, actively traded on-the-run, benchmark U.S. Treasury security with the maturity closest to and greater than the Remaining Average Life and (2) the most recently issued, actively traded on-the-run, benchmark U.S. Treasury security with the maturity closest to and less than the Remaining Average Life. The Reinvestment Yield shall be rounded to the number of decimal places as appears in the interest rate of the applicable Bond.

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“Remaining Average Life” means, with respect to any Called Principal, the number of years obtained by dividing (i) such Called Principal into (ii) the sum of the products obtained by multiplying (a) the principal component of each Remaining Scheduled Payment with respect to such Called Principal by (b) the number of years, computed on the basis of a 360-day year composed of twelve 30-day months and calculated to two decimal places, that will elapse between the Settlement Date with respect to such Called Principal and the Stated Maturity of such Remaining Scheduled Payment.

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

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

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

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

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

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

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

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

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

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

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Dated:

DTE GAS COMPANY

By:______________________________

Attest:

By:______________________________________

CERTIFICATE OF AUTHENTICATION

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

CITIBANK, N.A., as Trustee

By:_________________________________

Authorized Officer

Dated:

[End of 2013 Series C Bond Form]

SECTION 4

Each certificate evidencing the 2013 Series C Bonds (and all 2013 Series C Bonds issued in exchange therefor or in substitution thereof) shall bear a legend in substantially the following form (each defined term in the legend being defined as such for purposes of the legend only):

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

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The 2013 Series C Bonds shall be exchangeable upon surrender thereof at the corporate trust office of the Trustee in the Borough of Manhattan, the City of New York, New York, for registered bonds of the same aggregate principal amount and other terms, but of different authorized denomination or denominations, such exchanges to be made without service charge (except for any stamp tax or other governmental charge).

When 2013 Series C Bonds are presented to the Trustee with a request (i) to register the transfer of such 2013 Series C Bonds; or (ii) to exchange such 2013 Series C Bonds for 2013 Series C Bonds of the same series of any authorized denominations of the same aggregate principal amount and Stated Maturity, the Trustee shall register the transfer or make the exchange as requested if its reasonable requirements for such transaction are met; provided, however, that the 2013 Series C Bonds surrendered for transfer or exchange: (A) shall be duly endorsed or be accompanied by a written instrument of transfer in form reasonably satisfactory to the Company and the Trustee, duly executed by the holder thereof or his attorney duly authorized in writing; and (B) are accompanied by the following additional information and documents, as applicable: (x) if such 2013 Series C Bonds are being delivered to the Company by a holder for registration in the name of such holder, without transfer, a certification from such holder to that effect; or (y) if such 2013 Series C Bonds are being transferred to the Company, a certification to that effect; or (z) if such 2013 Series C Bonds are being transferred pursuant to an exemption from registration in accordance with Rule 144 under the Securities Act or in reliance upon another exemption from the registration requirements of the Securities Act, (i) a certification to that effect and (ii) if the Company so requests, other evidence reasonably satisfactory to it as to the compliance with the restrictions set forth in the legend set forth above.

Every 2013 Series C Bond so surrendered shall be accompanied by a proper transfer power duly executed by the registered owner or by a duly authorized attorney transferring such 2013 Series C Bond to the Company, and the signature to such transfer power shall be guaranteed to the satisfaction of the Trustee. All 2013 Series C Bonds so surrendered shall be forthwith canceled and delivered to or upon the order of the Company. All 2013 Series C Bonds executed, authenticated and delivered in exchange for 2013 Series C Bonds so surrendered shall be valid obligations of the Company, evidencing the same debt as the 2013 Series C Bonds surrendered, and shall be secured by the same lien and be entitled to the same benefits and protection as the 2013 Series C Bonds in exchange for which they are executed, authenticated and delivered.

The Company shall not be required to make any such exchange or any registration of transfer after the 2013 Series C Bond so presented for exchange or registration of transfer, or any portion thereof, has been called for redemption and notice thereof given to the registered owner.

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SECTION 5

Pending the preparation of definitive 2013 Series C Bonds, the Company may from time to time execute, and upon its written order, the Trustee shall authenticate and deliver, in lieu of such definitive 2013 Series C Bonds and subject to the same provisions, limitations and conditions, one or more temporary 2013 Series C Bonds, in registered form, of any denomination specified in the written order of the Company for the authentication and delivery thereof, and with such omissions, insertions and variations as may be determined by the Board of Directors of the Company. Such temporary 2013 Series C Bonds shall be substantially of the tenor of the 2013 Series C Bonds to be issued as herein before recited.

If any such temporary 2013 Series C Bonds shall at any time be so authenticated and delivered in lieu of definitive 2013 Series C Bonds, the Company shall upon request at its own expense prepare, execute and deliver to the Trustee and thereupon, upon the presentation and surrender of temporary 2013 Series C Bonds, the Trustee shall authenticate and deliver in exchange therefor, without charge to the holder, definitive Bonds of the same series and other terms, if any, and for the same principal sum in the aggregate as the temporary 2013 Series C Bonds surrendered. All temporary 2013 Series C Bonds so surrendered shall be forthwith canceled by the Trustee and delivered to or upon the order of the Company. Until exchanged for definitive 2013 Series C Bonds the temporary 2013 Series C Bonds shall in all respects be entitled to the lien and security of the Indenture and all supplemental indentures.

ARTICLE II
ESTABLISHMENT OF AN ISSUE OF
FIRST MORTGAGE BONDS, OF THE SERIES
DESIGNATED AND DISTINGUISHED AS “2013 SERIES D BONDS”

SECTION 1

There is hereby established a series of bonds to be issued under and secured by the Indenture, to be known as “First Mortgage Bonds,” designated and distinguished as “2013 Series D Bonds” of the Company. The 2013 Series D Bonds shall be limited in aggregate principal amount to $70,000,000 except as provided in Article IV of the Indenture and in this Supplemental Indenture with respect to transfers, exchanges and replacements of 2013 Series D Bonds. The 2013 Series D Bonds shall be registered bonds without coupons and shall be dated as of the date of the authentication thereof by the Trustee.

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The 2013 Series D Bonds shall mature on the 15th day of December, 2025 (subject to earlier redemption, as provided herein), shall bear interest at the rate of 3.74% per annum, payable semi-annually on the 15th day of June and December of each year and at maturity (each an “2013 Series D Interest Payment Date”), beginning on June 15, 2014. The principal, Make-Whole Amount (as defined below), if any, and interest on the 2013 Series D Bonds shall be payable in lawful money of the United States of America; the place where such principal and Make-Whole Amount, if any, shall be payable shall be the corporate trust office of the Trustee in the Borough of Manhattan, the City of New York, New York, and the place where such interest shall be payable shall be the office or agency of the Company in said Borough of Manhattan, the City of New York, New York. The 2013 Series D Bonds shall have such other terms as set forth in the form of 2013 Series D Bond provided in Section 3.

SECTION 2

The 2013 Series D Bonds shall be subject to redemption at the option of the Company, in whole at any time or in part from time to time (any such date of redemption, a “2013 Series D Redemption Date”), at the applicable redemption price (“2013 Series D Redemption Price”) set forth below.

At any time prior to September 15, 2025, the 2013 Series D Redemption Price will be equal to 100% of the principal amount of the 2013 Series D Bonds to be redeemed on the 2013 Series D Redemption Date together with the Make-Whole Amount (as defined in the form of 2013 Series D Bond provided in Section 3), if any, plus, in each case, accrued and unpaid interest thereon to the 2013 Series D Redemption Date.

At any time on or after September 15, 2025, the 2013 Series D Redemption Price will be equal to 100% of the principal amount of the bonds of 2013 Series D to be redeemed plus accrued and unpaid interest thereon to the 2013 Series D Redemption date.

Notwithstanding the foregoing, installments of interest on the 2013 Series D Bonds that are due and payable on 2013 Series D Interest Payment Dates falling on or prior to a 2013 Series D Redemption Date will be payable on the 2013 Series D Interest Payment Date to the registered holders as of the close of business on the relevant record date.

Notice of redemption shall be given to the holders of the 2013 Series D Bonds to be redeemed not more than 60 nor less than 30 days prior to the 2013 Series D Redemption Date, as provided in Section 4.05 of the Indenture. Each such notice shall specify such optional 2013 Series D Redemption Date, the aggregate principal amount of the 2013 Series D Bonds to be redeemed on such date, the principal amount of each 2013 Series D Bond held by such holder to be redeemed, and the interest to be paid on the 2013 Series D Redemption Date with respect to such principal amount being prepaid, and shall be accompanied by a certificate of a senior financial officer of the Company as to the estimated Make-Whole Amount due in connection with such redemption (calculated as if the date of such notice were the date of the redemption), setting forth the details of such computation. The Make-Whole Amount shall be determined by the Company two Business Days prior to the applicable 2013

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Series D Redemption Date and the Company shall deliver to holders of the 2013 Series D Bonds and to the Trustee a certificate of a senior financial officer specifying the calculation of such Make-Whole Amount as of the Redemption Date.

Subject to the limitations of Section 4.07 of the Indenture, the notice of redemption may state that it is subject to the receipt of the redemption moneys by the Trustee on or before the 2013 Series D Redemption Date, and that such notice shall be of no effect unless such moneys are so received on or before such date.

If the 2013 Series D Bonds are only partially redeemed by the Company, the Trustee shall select which 2013 Series D Bonds are to be redeemed pro rata among all of the 2013 Series D Bonds at the time outstanding in proportion, as nearly as practicable, to the respective unpaid principal amounts thereof and otherwise in accordance with the terms of the Indenture. In the event of redemption of the 2013 Series D Bonds in part only, a new 2013 Series D Bond or 2013 Series D Bonds for the unredeemed portion will be issued in the name or names of the holders thereof upon the surrender or cancellation thereof.

If money sufficient to pay the applicable the 2013 Series D Redemption Price with respect to the 2013 Series D Bonds to be redeemed on the applicable 2013 Series D Redemption Date, together with accrued interest to the 2013 Series D Redemption Date, is deposited with the Trustee on or before the related 2013 Series D Redemption Date and certain other conditions are satisfied, then the 2013 Series D Bonds to be redeemed shall no longer be secured by, or entitled to any lien or benefit of, the Indenture as provided by Section 4.04 of the Indenture.

The 2013 Series D Bonds will not be entitled to any sinking fund and will not be redeemable other than as provided in this Section 2 and the form of the 2013 Series D Bond provided in Section 3.

SECTION 3

The 2013 Series D Bonds shall be registered bonds without coupons. The Trustee shall be the registrar and paying agent for the 2013 Series D Bonds, which duties it hereby accepts. The 2013 Series D Bonds may be issued in minimum denominations of $100,000 or any integral multiple of $1,000 in excess thereof.

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The forms of the 2013 Series D Bonds shall be substantially as follows:

[FORM OF DTE GAS COMPANY 3.74% FIRST MORTGAGE BONDS 2013 SERIES D DUE 2025]

PPN:

No. R-___                        $_________________

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

DTE GAS COMPANY

3.74% MORTGAGE BONDS

2013 SERIES D DUE 2025

Principal Amount: $____________

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

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

Original Issue Date: December 12, 2013

Stated Maturity: December 15, 2025

Interest Payment Dates: June 15th and December 15th of each year, beginning June 15, 2014.

Interest Rate: 3.74% per annum

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DTE GAS COMPANY (hereinafter called the “Company”), a corporation of the State of Michigan, for value received, hereby promises to pay to ___________, or registered assigns, the sum of _________ Dollars ($_________) on the Stated Maturity specified above, in the coin or currency of the United States of America, and to pay interest thereon from the Original Issue Date specified above, or from the most recent Interest Payment Date to which interest has been paid or duly provided for, semi-annually in arrears on each Interest Payment Date as specified above, commencing on June 15, 2014 and on the Stated Maturity at the Interest Rate per annum specified above until the principal hereof is paid or made available for payment, and on any overdue principal and Make-Whole Amount (defined below) and, to the extent lawful, on any overdue installment of interest. The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will, as provided in the Indenture, be paid to the person in whose name this bond is registered at the close of business on the Regular Record Date as specified above next preceding such Interest Payment Date; provided that any interest payable at Stated Maturity or on a Redemption Date (defined below) will be paid to the person to whom principal is payable. Except as otherwise provided in the Indenture, any such interest not so punctually paid or duly provided for will forthwith cease to be payable to the holder on such Regular Record Date and may either be paid to the person in whose name this bond is registered at the close of business on a special record date for the payment of such defaulted interest to be fixed by the Trustee, notice whereof shall be given to holders of bonds of this series not less than 10 days prior to such special record date, or be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange, if any, on which the bonds of this series shall be listed, and upon such notice as may be required by any such exchange, all as more fully provided in the Indenture.

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

Payment of principal of, Make-Whole Amount, if any, and interest on the bonds of this series shall be made in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts. Payments of principal, Make-Whole Amount, if any, and interest due at the Stated Maturity or earlier redemption of such bonds shall be made at the office of the Trustee upon surrender of such bonds to the Trustee, and (ii) payments of interest shall be made, at the option of the Company, subject to such surrender where applicable, (A) by check

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mailed to the address of the person entitled thereto as such address shall appear in the bond register of the Trustee maintained for such purpose or (B) by wire transfer at such place and to such account at a banking institution in the United States as may be designated in writing to the Trustee at least fourteen (14) days prior to the date for payment by the person entitled thereto. Notwithstanding the foregoing, so long as any bond is held by an Institutional Investor (as defined in the Bond Purchase Agreement referenced below), payment of principal, Make-Whole Amount, if any, and interest on the bonds held by such holder shall be made in the manner specified in the Bond Purchase Agreement dated as of December 12, 2013 among the Company and the purchasers party thereto.

The bonds represented by this certificate, of the series hereinafter specified, are bonds of the Company (herein called the “bonds”) known as its “First Mortgage Bonds,” issued and to be issued in one or more series under, and all equally and ratably secured by, an Indenture of Mortgage and Deed of Trust dated as of March 1, 1944, duly executed by the Company to Citibank, N.A., successor trustee (“Trustee”) as restated in Part II of the Twenty-ninth Supplemental Indenture dated as of July 15, 1989, which became effective on April 1, 1994, to which indenture and all indentures supplemental thereto executed on and after July 15, 1989 reference is hereby made for a description of the property mortgaged and pledged, the nature and extent of the security, the terms and conditions upon which the bonds are, and are to be, issued and secured, and the rights of the holders of the bonds and of the Trustee in respect of such security (which indenture and all indentures supplemental thereto, including the Forty-fourth Supplemental Indenture dated as of December 1, 2013 referred to below, are hereinafter collectively called the “Indenture”). As provided in the Indenture, the bonds may be issued thereunder for various principal sums and are issuable in series, which may mature at different times, may bear interest at different rates and may otherwise vary as therein provided. The bonds represented by this certificate are part of a series designated “3.74% First Mortgage Bonds 2013 Series D,” (herein called the “Bonds”) created by the Forty-fourth Supplemental Indenture dated as of December 1, 2013 as provided for in said Indenture.

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

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

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

This Bond shall be subject to redemption at the option of the Company, in whole at any time or in part from time to time (any such date of optional redemption, a “Redemption Date”), at the applicable redemption price (“Redemption Price”) set forth below.

At any time prior to September 15, 2025, the Redemption Price will be equal to 100% of the principal amount of the Bonds to be redeemed on the Redemption Date together with the Make-Whole Amount (as defined below), if any, plus, in each case, accrued and unpaid interest thereon to the Redemption Date.

At any time on or after September 15, 2025, the Redemption Price will be equal to 100% of the principal amount of the bonds of 2013 Series D to be redeemed plus accrued and unpaid interest thereon to the redemption date.

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

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

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

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

“Reinvestment Yield” means, with respect to the Called Principal of a Bond, 0.5% (50 basis points) plus the yield to maturity implied by (i) the yields reported, as of 10:00 a.m. (New York City time) on the second Business Day preceding the Settlement Date with respect to such Called Principal, on the display designated as “PX-1” (or such other display as may replace Page PX-1), on Bloomberg Financial Markets for the most recently issued, actively traded on-the-run, benchmark U.S. Treasury securities having a maturity equal to the Remaining Average Life of such Called Principal as of such Settlement Date, or (ii) if such yields are not reported as of such time or the yields reported as of such time are not ascertainable (including by way of interpolation), the Treasury Constant Maturity Series Yields reported, for the latest day for which such yields have been so reported as of the second Business Day preceding the Settlement Date with respect to such Called Principal, in Federal Reserve Statistical Release H.15 (519) (or any comparable successor publication) for actively traded U.S. Treasury securities having a constant maturity equal to the Remaining Average Life of such Called Principal as of such Settlement Date. Such implied yield will be determined, if necessary, by (a) converting U.S. Treasury bill quotations to bond-equivalent yields in accordance with accepted financial practice and (b) interpolating linearly on a straight line basis between (1) the most recently issued, actively traded on-the-run, benchmark U.S. Treasury security with the maturity closest to and greater than the Remaining Average Life and (2) the most recently issued, actively traded on-the-run, benchmark U.S. Treasury security with the maturity closest to and less than the Remaining Average Life. The Reinvestment Yield shall be rounded to the number of decimal places as appears in the interest rate of the applicable Bond.

“Remaining Average Life” means, with respect to any Called Principal, the number of years obtained by dividing (i) such Called Principal into (ii) the sum of the products obtained by multiplying (a) the principal component of each Remaining Scheduled Payment with respect to such Called Principal by (b) the number of years, computed on the basis of a 360-day year composed of twelve 30-day months and calculated to two decimal places, that will elapse between the Settlement Date with respect to such Called Principal and the Stated Maturity of such Remaining Scheduled Payment.

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

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payment will be reduced by the amount of interest accrued to such Settlement Date and required to be paid on such Settlement Date.

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

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

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

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

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

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

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

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

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

Dated:

DTE GAS COMPANY

By:______________________________

Attest:

By:______________________________________

CERTIFICATE OF AUTHENTICATION

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

CITIBANK, N.A., as Trustee

By:_________________________________

Authorized Officer

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Dated:

[End of 2013 Series D Bond Form]

SECTION 4

Each certificate evidencing the 2013 Series D Bonds (and all 2013 Series D Bonds issued in exchange therefor or in substitution thereof) shall bear a legend in substantially the following form (each defined term in the legend being defined as such for purposes of the legend only):

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

The 2013 Series D Bonds shall be exchangeable upon surrender thereof at the corporate trust office of the Trustee in the Borough of Manhattan, the City of New York, New York, for registered bonds of the same aggregate principal amount and other terms, but of different authorized denomination or denominations, such exchanges to be made without service charge (except for any stamp tax or other governmental charge).

When 2013 Series D Bonds are presented to the Trustee with a request (i) to register the transfer of such Bonds; or (ii) to exchange such 2013 Series D Bonds for 2013 Series D Bonds of the same series of any authorized denominations of the same aggregate principal amount and Stated Maturity, the Trustee shall register the transfer or make the exchange as requested if its reasonable requirements for such transaction are met; provided, however, that the 2013 Series D Bonds surrendered for transfer or exchange: (A) shall be duly endorsed or be accompanied by a written instrument of transfer in form reasonably satisfactory to the Company and the Trustee, duly executed by the holder thereof or his attorney duly authorized in writing; and (B) are accompanied by the following additional information and documents, as applicable: (x) if such 2013 Series D Bonds are being delivered to the Company by a holder for registration in the name of such holder, without

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transfer, a certification from such holder to that effect; or (y) if such 2013 Series D Bonds are being transferred to the Company, a certification to that effect; or (z) if such 2013 Series D Bonds are being transferred pursuant to an exemption from registration in accordance with Rule 144 under the Securities Act or in reliance upon another exemption from the registration requirements of the Securities Act, (i) a certification to that effect and (ii) if the Company so requests, other evidence reasonably satisfactory to it as to the compliance with the restrictions set forth in the legend set forth above.

Every 2013 Series D Bond so surrendered shall be accompanied by a proper transfer power duly executed by the registered owner or by a duly authorized attorney transferring such 2013 Series D Bond to the Company, and the signature to such transfer power shall be guaranteed to the satisfaction of the Trustee. All 2013 Series D Bonds so surrendered shall be forthwith canceled and delivered to or upon the order of the Company. All 2013 Series D Bonds executed, authenticated and delivered in exchange for 2013 Series D Bonds so surrendered shall be valid obligations of the Company, evidencing the same debt as the 2013 Series D Bonds surrendered, and shall be secured by the same lien and be entitled to the same benefits and protection as the 2013 Series D Bonds in exchange for which they are executed, authenticated and delivered.

The Company shall not be required to make any such exchange or any registration of transfer after the 2013 Series D Bond so presented for exchange or registration of transfer, or any portion thereof, has been called for redemption and notice thereof given to the registered owner.

SECTION 5

Pending the preparation of definitive 2013 Series D Bonds, the Company may from time to time execute, and upon its written order, the Trustee shall authenticate and deliver, in lieu of such definitive 2013 Series D Bonds and subject to the same provisions, limitations and conditions, one or more temporary 2013 Series D Bonds, in registered form, of any denomination specified in the written order of the Company for the authentication and delivery thereof, and with such omissions, insertions and variations as may be determined by the Board of Directors of the Company. Such temporary 2013 Series D Bonds shall be substantially of the tenor of the 2013 Series D Bonds to be issued as herein before recited.

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If any such temporary 2013 Series D Bonds shall at any time be so authenticated and delivered in lieu of definitive 2013 Series D Bonds, the Company shall upon request at its own expense prepare, execute and deliver to the Trustee and thereupon, upon the presentation and surrender of temporary 2013 Series D Bonds, the Trustee shall authenticate and deliver in exchange therefor, without charge to the holder, definitive 2013 Series D Bonds of the same series and other terms, if any, and for the same principal sum in the aggregate as the temporary 2013 Series D Bonds surrendered. All temporary 2013 Series D Bonds so surrendered shall be forthwith canceled by the Trustee and delivered to or upon the order of the Company. Until exchanged for definitive 2013 Series D Bonds the temporary 2013 Series D Bonds shall in all respects be entitled to the lien and security of the Indenture and all supplemental indentures.

ARTICLE III
ESTABLISHMENT OF AN ISSUE OF
FIRST MORTGAGE BONDS, OF THE SERIES
DESIGNATED AND DISTINGUISHED AS “2013 SERIES E BONDS”

SECTION 1

There is hereby established a series of bonds to be issued under and secured by the Indenture, to be known as “First Mortgage Bonds,” designated and distinguished as “2013 Series E Bonds” of the Company. The 2013 Series E Bonds shall be limited in aggregate principal amount to $50,000,000 except as provided in Article IV of the Indenture and in this Supplemental Indenture with respect to transfers, exchanges and replacements of 2013 Series E Bonds. The 2013 Series E Bonds shall be registered bonds without coupons and shall be dated as of the date of the authentication thereof by the Trustee.

The 2013 Series E Bonds shall mature on the 15th day of December, 2028 (subject to earlier redemption, as provided herein), shall bear interest at the rate of 3.94% per annum, payable semi-annually on the 15th day of June and December of each year and at maturity (each an “2013 Series E Interest Payment Date”), beginning on June 15, 2014. The principal, Make-Whole Amount (as defined below), if any, and interest on the 2013 Series E Bonds shall be payable in lawful money of the United States of America; the place where such principal and Make-Whole Amount, if any, shall be payable shall be the corporate trust office of the Trustee in the Borough of Manhattan, the City of New York, New York, and the place where such interest shall be payable shall be the office or agency of the Company in said Borough of Manhattan, the City of New York, New York. The 2013 Series E Bonds shall have such other terms as set forth in the form of 2013 Series E Bond provided in Section 3.

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SECTION 2

The 2013 Series E Bonds shall be subject to redemption at the option of the Company, in whole at any time or in part from time to time (any such date of redemption, a “2013 Series E Redemption Date”), at the applicable redemption price (“2013 Series E Redemption Price”) set forth below.

At any time prior to September 15, 2028, the 2013 Series E Redemption Price will be equal to 100% of the principal amount of the Bonds to be redeemed on the 2013 Series E Redemption Date together with the Make-Whole Amount (as defined in the form of 2013 Series E Bond provided in Section 3), if any, plus, in each case, accrued and unpaid interest thereon to the 2013 Series E Redemption Date.

At any time on or after September 15, 2028, the 2013 Series E Redemption Price will be equal to 100% of the principal amount of the bonds of 2013 Series E to be redeemed plus accrued and unpaid interest thereon to the redemption date.

Notwithstanding the foregoing, installments of interest on the 2013 Series E Bonds that are due and payable on 2013 Series E Interest Payment Dates falling on or prior to a 2013 Series E Redemption Date will be payable on the 2013 Series E Interest Payment Date to the registered holders as of the close of business on the relevant record date.

Notice of redemption shall be given to the holders of the 2013 Series E Bonds to be redeemed not more than 60 nor less than 30 days prior to the 2013 Series E Redemption Date, as provided in Section 4.05 of the Indenture. Each such notice shall specify such optional 2013 Series E Redemption Date, the aggregate principal amount of the 2013 Series E Bonds to be redeemed on such date, the principal amount of each 2013 Series E Bond held by such holder to be redeemed, and the interest to be paid on the 2013 Series E Redemption Date with respect to such principal amount being prepaid, and shall be accompanied by a certificate of a senior financial officer of the Company as to the estimated Make-Whole Amount due in connection with such redemption (calculated as if the date of such notice were the date of the redemption), setting forth the details of such computation. The Make-Whole Amount shall be determined by the Company two Business Days prior to the applicable 2013 Series E Redemption Date and the Company shall deliver to holders of the 2013 Series E Bonds and to the Trustee a certificate of a senior financial officer specifying the calculation of such Make-Whole Amount as of the 2013 Series E Redemption Date.

Subject to the limitations of Section 4.07 of the Indenture, the notice of redemption may state that it is subject to the receipt of the redemption moneys by the Trustee on or before the 2013 Series E Redemption Date, and that such notice shall be of no effect unless such moneys are so received on or before such date.

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If the 2013 Series E Bonds are only partially redeemed by the Company, the Trustee shall select which 2013 Series E Bonds are to be redeemed pro rata among all of the Bonds at the time outstanding in proportion, as nearly as practicable, to the respective unpaid principal amounts thereof and otherwise in accordance with the terms of the Indenture. In the event of redemption of the 2013 Series E Bonds in part only, a new 2013 Series E Bond or 2013 Series E Bonds for the unredeemed portion will be issued in the name or names of the holders thereof upon the surrender or cancellation thereof.

If money sufficient to pay the applicable the 2013 Series E Redemption Price with respect to the 2013 Series E Bonds to be redeemed on the applicable 2013 Series E Redemption Date, together with accrued interest to the 2013 Series E Redemption Date, is deposited with the Trustee on or before the related 2013 Series E Redemption Date and certain other conditions are satisfied, then the 2013 Series E Bonds to be redeemed shall no longer be secured by, or entitled to any lien or benefit of, the Indenture as provided by Section 4.04 of the Indenture.

The 2013 Series E Bonds will not be entitled to any sinking fund and will not be redeemable other than as provided in this Section 2 and the form of 2013 Series E Bond provided in Section 3.

SECTION 3

The 2013 Series E Bonds shall be registered bonds without coupons. The Trustee shall be the registrar and paying agent for the 2013 Series E Bonds, which duties it hereby accepts. The 2013 Series E Bonds may be issued in minimum denominations of $100,000 or any integral multiple of $1,000 in excess thereof.

The forms of 2013 Series E Bonds shall be substantially as follows:

[FORM OF DTE GAS COMPANY 3.94% FIRST MORTGAGE BONDS 2013 SERIES E DUE 2028]

PPN:

No. R-___                        $_________________

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

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AS THE TRUSTEE MAY REASONABLY REQUIRE TO CONFIRM THAT THE TRANSFER COMPLIES WITH THE FOREGOING RESTRICTIONS.

DTE GAS COMPANY

3.94% MORTGAGE BONDS

2013 SERIES E DUE 2028

Principal Amount: $____________

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

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

Original Issue Date: December 12, 2013

Stated Maturity: December 15, 2028

Interest Payment Dates: June 15th and December 15 of each year, beginning June 15, 2014.

Interest Rate: 3.94% per annum

DTE GAS COMPANY (hereinafter called the “Company”), a corporation of the State of Michigan, for value received, hereby promises to pay to ___________, or registered assigns, the sum of _________ Dollars ($_________) on the Stated Maturity specified above, in the coin or currency of the United States of America, and to pay interest thereon from the Original Issue Date specified above, or from the most recent Interest Payment Date to which interest has been paid or duly provided for, semi-annually in arrears on each Interest Payment Date as specified above, commencing on June 15, 2014 and on the Stated Maturity at the Interest Rate per annum specified above until the principal hereof is paid or made available for payment, and on any overdue principal and Make-Whole Amount (defined below) and, to the extent lawful, on any overdue installment of interest. The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will, as provided in the Indenture, be paid to the person in whose name this bond is registered at the close of business on the Regular Record Date as specified above next preceding such Interest Payment Date; provided that any interest payable at Stated Maturity or on a Redemption Date (defined below) will be paid to the person to whom principal is payable. Except as otherwise provided in the Indenture, any such interest not so punctually paid or duly provided for will forthwith cease to be payable to the holder on such Regular Record Date and may either be paid to the person in whose name this bond is registered at the close of business on a special record date for the payment of such defaulted interest to be fixed by the Trustee, notice whereof shall be given to holders of bonds of this series not less than 10 days prior to such special record date, or be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange, if any, on which the bonds of this series shall be listed, and upon such notice as may be required by any such exchange, all as more fully provided in the Indenture.

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

Payment of principal of, Make-Whole Amount, if any, and interest on the bonds of this series shall be made in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts. Payments of principal, Make-Whole Amount, if any, and interest due at the Stated Maturity or earlier redemption of such bonds shall be made at the office of the Trustee upon surrender of such bonds to the Trustee, and (ii) payments of interest shall be made, at the option of the Company, subject to such surrender where applicable, (A) by check mailed to the address of the person entitled thereto as such address shall appear in the bond register of the Trustee maintained for such purpose or (B) by wire transfer at such place and to such account at a banking institution in the United States as may be designated in writing to the Trustee at least fourteen (14) days prior to the date for payment by the person entitled thereto. Notwithstanding the foregoing, so long as any bond is held by an Institutional Investor (as defined in the Bond Purchase Agreement referenced below), payment of principal, Make-Whole Amount, if any, and interest on the bonds held by such holder shall be made in the manner specified in the Bond Purchase Agreement dated as of December 12, 2013 among the Company and the purchasers party thereto.

The bonds represented by this certificate, of the series hereinafter specified, are bonds of the Company (herein called the “bonds”) known as its “First Mortgage Bonds,” issued and to be issued in one or more series under, and all equally and ratably secured by, an Indenture of Mortgage and Deed of Trust dated as of March 1, 1944, duly executed by the Company to Citibank, N.A., successor trustee (“Trustee”) as restated in Part II of the Twenty-ninth Supplemental Indenture dated as of July 15, 1989, which became effective on April 1, 1994, to which indenture and all indentures supplemental thereto executed on and after July 15, 1989 reference is hereby made for a description of the property mortgaged and pledged, the nature and extent of the security, the terms and conditions upon which the bonds are, and are to be, issued and secured, and the rights of the holders of the bonds and of the Trustee in respect of such security (which indenture and all indentures supplemental thereto, including the Forty-fourth Supplemental Indenture dated as of December 1, 2013 referred to below, are hereinafter collectively called the “Indenture”). As provided in the Indenture, the bonds may be issued thereunder for various principal sums and are issuable in series, which may mature at different times, may bear interest at different rates and may otherwise vary as therein provided. The bonds represented

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by this certificate are part of a series designated “3.94% First Mortgage Bonds 2013 Series E,” (herein called the “Bonds”) created by the Forty-fourth Supplemental Indenture dated as of December 1, 2013 as provided for in said Indenture.

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

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

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

This Bond shall be subject to redemption at the option of the Company, in whole at any time or in part from time to time (any such date of optional redemption, a “Redemption Date”), at the applicable redemption price (“Redemption Price”) set forth below.

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At any time prior to September 15, 2028, the Redemption Price will be equal to 100% of the principal amount of the Bonds to be redeemed on the Redemption Date together with the Make-Whole Amount (as defined below), if any, plus, in each case, accrued and unpaid interest thereon to the Redemption Date.

At any time on or after September 15, 2028, the Redemption Price will be equal to 100% of the principal amount of the bonds of 2013 Series E to be redeemed plus accrued and unpaid interest thereon to the redemption date.

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

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

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

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

“Reinvestment Yield” means, with respect to the Called Principal of a Bond, 0.5% (50 basis points) plus the yield to maturity implied by (i) the yields reported, as of 10:00 a.m. (New York City time) on the second Business Day preceding the Settlement Date with respect to such Called Principal, on the display designated as “PX-1” (or such other display as may replace Page PX-1), on Bloomberg Financial Markets for the most recently issued, actively traded on-the-run, benchmark U.S. Treasury securities having a maturity equal to the Remaining Average Life of such Called Principal as of such Settlement Date, or (ii) if such yields are not reported as of such time or the yields reported as of such

34

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

“Remaining Average Life” means, with respect to any Called Principal, the number of years obtained by dividing (i) such Called Principal into (ii) the sum of the products obtained by multiplying (a) the principal component of each Remaining Scheduled Payment with respect to such Called Principal by (b) the number of years, computed on the basis of a 360-day year composed of twelve 30-day months and calculated to two decimal places, that will elapse between the Settlement Date with respect to such Called Principal and the Stated Maturity of such Remaining Scheduled Payment.

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

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

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

35

Redemption Date and the Company shall deliver to holders of the Bonds and to the Trustee a certificate of a senior financial officer specifying the calculation of such Make-Whole Amount as of the Redemption Date.

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

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

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

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

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

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

36

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

Dated:

DTE GAS COMPANY

By:______________________________

Attest:

By:______________________________________

CERTIFICATE OF AUTHENTICATION

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

CITIBANK, N.A., as Trustee

By:_________________________________

Authorized Officer

Dated:

[End of 2013 Series E Bond Form]

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SECTION 4

Each certificate evidencing the 2013 Series E Bonds (and all 2013 Series E Bonds issued in exchange therefor or in substitution thereof) shall bear a legend in substantially the following form (each defined term in the legend being defined as such for purposes of the legend only):

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

The 2013 Series E Bonds shall be exchangeable upon surrender thereof at the corporate trust office of the Trustee in the Borough of Manhattan, the City of New York, New York, for registered bonds of the same aggregate principal amount and other terms, but of different authorized denomination or denominations, such exchanges to be made without service charge (except for any stamp tax or other governmental charge).

When 2013 Series E Bonds are presented to the Trustee with a request (i) to register the transfer of such Bonds; or (ii) to exchange such 2013 Series E Bonds for 2013 Series E Bonds of the same series of any authorized denominations of the same aggregate principal amount and Stated Maturity, the Trustee shall register the transfer or make the exchange as requested if its reasonable requirements for such transaction are met; provided, however, that the 2013 Series E Bonds surrendered for transfer or exchange: (A) shall be duly endorsed or be accompanied by a written instrument of transfer in form reasonably satisfactory to the Company and the Trustee, duly executed by the holder thereof or his attorney duly authorized in writing; and (B) are accompanied by the following additional information and documents, as applicable: (x) if such 2013 Series E Bonds are being delivered to the Company by a holder for registration in the name of such holder, without transfer, a certification from such holder to that effect; or (y) if such 2013 Series E Bonds are being transferred to the Company, a certification to that effect; or (z) if such 2013 Series E Bonds are being transferred pursuant to an exemption from registration in accordance with Rule 144 under the Securities Act or in reliance upon another exemption from the registration requirements of the Securities Act, (i) a certification to that effect and (ii) if the Company so requests, other evidence reasonably satisfactory to it as to the compliance with the restrictions set forth in the legend set forth above.

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Every 2013 Series E Bond so surrendered shall be accompanied by a proper transfer power duly executed by the registered owner or by a duly authorized attorney transferring such 2013 Series E Bond to the Company, and the signature to such transfer power shall be guaranteed to the satisfaction of the Trustee. All 2013 Series E Bonds so surrendered shall be forthwith canceled and delivered to or upon the order of the Company. All 2013 Series E Bonds executed, authenticated and delivered in exchange for 2013 Series E Bonds so surrendered shall be valid obligations of the Company, evidencing the same debt as the 2013 Series E Bonds surrendered, and shall be secured by the same lien and be entitled to the same benefits and protection as the 2013 Series E Bonds in exchange for which they are executed, authenticated and delivered.

The Company shall not be required to make any such exchange or any registration of transfer after the 2013 Series E Bond so presented for exchange or registration of transfer, or any portion thereof, has been called for redemption and notice thereof given to the registered owner.

SECTION 5

Pending the preparation of definitive 2013 Series E Bonds, the Company may from time to time execute, and upon its written order, the Trustee shall authenticate and deliver, in lieu of such definitive 2013 Series E Bonds and subject to the same provisions, limitations and conditions, one or more temporary 2013 Series E Bonds, in registered form, of any denomination specified in the written order of the Company for the authentication and delivery thereof, and with such omissions, insertions and variations as may be determined by the Board of Directors of the Company. Such temporary 2013 Series E Bonds shall be substantially of the tenor of the 2013 Series E Bonds to be issued as herein before recited.

If any such temporary 2013 Series E Bonds shall at any time be so authenticated and delivered in lieu of definitive 2013 Series E Bonds, the Company shall upon request at its own expense prepare, execute and deliver to the Trustee and thereupon, upon the presentation and surrender of temporary 2013 Series E Bonds, the Trustee shall authenticate and deliver in exchange therefor, without charge to the holder, definitive 2013 Series E Bonds of the same series and other terms, if any, and for the same principal sum in the aggregate as the temporary 2013 Series E Bonds surrendered. All temporary 2013 Series E Bonds so surrendered shall be forthwith canceled by the Trustee and delivered to or upon the order of the Company. Until exchanged for definitive 2013 Series E Bonds the temporary 2013 Series E 2013 Series E Bonds shall in all respects be entitled to the lien and security of the Indenture and all supplemental indentures.

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ARTICLE IV
ISSUE OF BONDS

The 2013 Series C Bonds, 2013 Series D Bonds and 2013 Series E Bonds in the aggregate principal amount of $170,000,000 may be executed, authenticated and delivered from time to time as permitted by the provisions of the Indenture, including with respect to exchange and replacement of bonds.

ARTICLE V THE TRUSTEE

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

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

ARTICLE VI RECORDING AND FILING OF SUPPLEMENTAL INDENTURE
DATED AS OF DECEMBER 1, 2012

Pursuant to the terms and provisions of the Original Indenture, a Supplemental Indenture dated as of December 1, 2012 providing for the terms of Collateral Bonds to be issued thereunder designated as 2012 Series D Mortgage Bonds has heretofore been entered into between the Company and the Trustee and has been filed in the Office of the Secretary of State of Michigan as a financing statement on December 11 2012 (Filing No. 2012171682-7) and has been recorded as a real estate mortgage in the offices of the respective Register of Deeds of certain counties in the State of Michigan, as follows:

COUNTY	RECORDED	LIBER/ INSTRUMENT NO.	PAGE
Alcona County Register of Deeds	12/11/12	493	1432
Alger County Register of Deeds	12/11/12	MI 201202714	N/A
Alpena County Register of Deeds	12/11/12	492	969
Antrim County Register of Deeds	12/11/12	833	724
Arenac County Register of Deeds	12/11/12	201204951	N/A
Barry County Register of Deeds	12/11/12	2012-008064	N/A
Benzie County Register of Deeds	12/11/12	2012R – 05906	N/A
Charlevoix County Register of Deeds	12/11/12	1013	679

40

COUNTY	RECORDED	LIBER/ INSTRUMENT NO.	PAGE
Cheboygan County Register of Deeds	12/11/12	1220	149
Chippewa County Register of Deeds	12/11/12	1147	365
Clare County Register of Deeds	12/11/12	1216	583
Clinton County Register of Deeds	12/11/12	5193677	N/A
Crawford County Register of Deeds	12/11/12	711	694
Delta County Register of Deeds	12/11/12	1066	621
Dickinson County Register of Deeds	12/11/12	GL 768 / 620	N/A
Emmet County Register of Deeds	12/12/12	1151	403
Gladwin County Register of Deeds	12/11/12	987	458
Grand Traverse County Register of Deeds	12/11/12	2012R – 23811	N/A
Gratiot County Register of Deeds	12/11/12	932	316
Ionia County Register of Deeds	`1/11/12	627	4097
Iosco County Register of Deeds	12/11/12	1067	387
Iron County Register of Deeds	12/11/12	609	168
Isabella County Register of Deeds	12/11/12	1615	946
Jackson County Register of Deeds	12/11/12	1999	202
Kalkaska County Register of Deeds	12/11/12	3111632	N/A
Kent County Register of Deeds	12/12/12	20130109-0003009	N/A
Lake County Register of Deeds	12/11/12	359	572
Leelanau County Register of Deeds	12/11/12	1147	166
Lenawee County Register of Deeds	12/11/12	2457.	970
Livingston County Register of Deeds	12/11/12	2012R-043983	N/A
Macomb County Register of Deeds	1/7/13	21821	777
Manistee County Register of Deeds	12/11/12	2012R007414	N/A
Marquette County Register of Deeds	12/11/12	2012R-14886	N/A
Mason County Register of Deeds	12/11/12	2012R07702	N/A
Mecosta County Register of Deeds	12/12/12	828	2074
Menominee County Register of Deeds	12/11/12	723	402
Missaukee County Register of Deeds	12/11/12	2012-04035 AMMTG	N/A
Monroe County Register of Deeds	12/11/12	2012R28430	N/A
Montcalm County Register of Deeds	12/11/12	1565	768
Montmorency County Register of Deeds	12/11/12	332	164
Muskegon County Register of Deeds	12/14/12	3933	482
Newaygo County Register of Deeds	12/11/12	448	6226
Oakland County Register of Deeds	1/17/13	45223	525
Oceana County Register of Deeds	12/11/12	2012	30642
Ogemaw County Register of Deeds	12/11/12	3110057	N/A
Osceola County Register of Deeds	12/11/12	916	130
Oscoda County Register of Deeds	12/11/12	212-03159	N/A
Otsego County Register of Deeds	12/11/12	1307	602
Ottawa County Register of Deeds	12/13/12	2012 – 0053217	N/A
Presque Isle County Register of Deeds	12/11/12	529	512
Roscommon County Register of Deeds	12/12/12	1122	933
St. Clair County Register of Deeds	12/11/12	4334	181

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COUNTY	RECORDED	LIBER/ INSTRUMENT NO.	PAGE
Saginaw County Register of Deeds	12/11/12	2702	2262
Shiawassee County Register of Deeds	12/11/12	1179	778
Washtenaw County Register of Deeds	12/11/12	4945	385
Wayne County Register of Deeds	12/11/12	50355	1245
Wexford County Register of Deeds	12/11/12	654	669

ARTICLE VII RECORDING OF AFFIDAVIT OF FACTS AFFECTING REAL PROPERTY

An Affidavit of Facts Affecting Real Property dated February 11, 2013 (the “Affidavit”) has been recorded in the offices of the respective Registers of Deeds of certain counties in the State of Michigan. The Affidavit, signed by the Company’s President and Chief Operating Officer, was given pursuant to MCL 565.451a to give notice of the fact that pursuant to a joint resolution of the Company’s sole shareholder and its board of directors, the Company amended its articles of incorporation effective January 1, 2013 to change its name from MICHIGAN CONSOLIDATED GAS COMPANY to DTE GAS COMPANY.

ARTICLE VIII MISCELLANEOUS PROVISIONS

Except insofar as herein otherwise expressly provided, all the provisions, terms and conditions of the Indenture shall be deemed to be incorporated in, and made a part of, this Forty-third Supplemental Indenture, and the Twenty-ninth Supplemental Indenture dated as of July 15, 1989, as supplemented by the Thirtieth Supplemental Indenture dated as of September 1, 1991, by the Thirty-first Supplemental Indenture dated as of December 15, 1991, by the Thirty-second Supplemental Indenture dated as of January 5, 1993, by the Thirty-third Supplemental Indenture dated as of May 1, 1995, by the Thirty-fourth Supplemental Indenture dated as of November 1, 1996, by the Thirty-fifth Supplemental Indenture dated as of June 18, 1998, by the Thirty-sixth Supplemental Indenture dated as of August 15, 2001, by the Thirty-seventh Supplemental Indenture dated as of February 15, 2003, by the Thirty-eighth Supplemental Indenture dated as of October 1, 2004, by the Thirty-ninth Supplemental Indenture dated as of April 1, 2008, by the Fortieth Supplemental Indenture dated as of June 1, 2008, by the Forty-first Supplemental Indenture dated as of August 1, 2008, by the Forty-second Supplemental Indenture dated as of December 1, 2008, by the Forty-third Supplemental Indenture dated as of December 1, 2012 and by this Supplemental Indenture is in all respects ratified and confirmed; and the Indenture and said Supplemental Indentures shall be read, taken and construed as one and the same instrument.

42

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

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

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

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

43

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

DTE GAS COMPANY

By:    /s/Donald J. Goshorn

    Donald J. Goshorn

Assistant Treasurer

Signed, sealed, acknowledged and
delivered by DTE GAS COMPANY in the presence of:

/s/Dana Pierre-Louis

Dana Pierre-Louis

/s/Kathleen Hier

Kathleen Hier

State of Michigan    }

} ss.

County of Wayne    }

The foregoing instrument was acknowledged before me this 1st day of December, 2013, by Donald J. Goshorn, as Assistant Treasurer, of DTE Gas Company, a Michigan corporation, on behalf of the corporation.

/s/Jennifer Evans

Jennifer Evans

Notary Public, Wayne County, MI

Acting in Wayne County, MI

My Commission Expires: December 28, 2016

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CITIBANK, N.A., as Trustee

By:/s/Wafaa Orfy

Wafaa Orfy

Vice President

Signed, sealed, acknowledged and
delivered by CITIBANK, N.A.
in the presence of:

/s/Louis Piscitelli

Name: Louis Piscitelli

Vice President

/s/Karen Schluter

Name: Karen Schluter

Vice President

State of New York    }

} ss.

County of New York    }

The foregoing instrument was acknowledged before me this 1st day of December, 2013, by Wafaa Orfy, as Vice President of Citibank, N.A., a national banking association, on behalf of the association, as Trustee, as in said instrument described.

/s/Karen Katlan

Notary Public, State of New York

No. 01KA4994374

Qualified in NY County

Acting in NY County

Commission Expires: April 6, 2014

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This instrument was drafted by:

Dana Pierre-Louis

One Energy Plaza, 688WCB

Detroit, MI 48226

When recorded return to:

Jennifer EvansOne Energy Plaza, 688WCB

Detroit, MI 48226

46

EX-12.58

Exhibit 12-56

DTE Energy Company
Computation of Ratio of Earnings to Fixed Charges
	Year Ended December 31
(Millions of Dollars)	2013			2012			2011		2010		2009
Earnings:
Pretax earnings	$	904		$	1,035		$	989	$	968	$	778
Adjustments	(8		)	(4		)	6		1		4
Fixed Charges	461			463			520		567		572
Net earnings	$	1,357		$	1,494		$	1,515	$	1,536	$	1,354
Fixed Charges:
Interest expense	$	432		$	441		$	490	$	543	$	545
Adjustments	29			22			30		24		27
Fixed Charges	$	461		$	463		$	520	$	567	$	572
Ratio of earnings to fixed charges	2.94			3.23			2.91		2.71		2.37

EX-21.9

Exhibit 21-9

SUBSIDIARIES OF DTE ENERGY COMPANY

DTE Energy Company’s principal subsidiaries as of December 31, 2013 are listed below. All other subsidiaries, if considered in the aggregate as a single subsidiary, would not constitute a significant subsidiary.

Subsidiary	State of Incorporation
1. DTE Electric Company	Michigan
2. DTE Enterprises, Inc.	Michigan
3. DTE Gas Holdings, Inc.	Michigan
4. DTE Gas Company	Michigan
5. DTE Energy Trading, Inc.	Michigan

EX-23.27

Exhibit 23-27

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S‑3 (Nos. 333-183442 and 333-157769) and Form S‑8 (Nos. 333-183440, 333-133645, 333-157768 and 333-109623) of DTE Energy Company of our report dated February 14, 2014 relating to the financial statements, financial statement schedule and the effectiveness of internal control over financial reporting, which appears in this Form 10‑K.

/s/ PricewaterhouseCoopers LLP

Detroit, Michigan

February 14, 2014

EX-31.87

Exhibit 31-87

FORM 10-K CERTIFICATION

I, Gerard M. Anderson, certify that:

1. I have reviewed this Annual Report on Form 10-K of DTE Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/S/ GERARD M. ANDERSON	Date:	February 14, 2014
Gerard M. Anderson Chairman of the Board and Chief Executive Officer of DTE Energy Company

EX-31.88

Exhibit 31-88

FORM 10-K CERTIFICATION

I, Peter B. Oleksiak, certify that:

1. I have reviewed this Annual Report on Form 10-K of DTE Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/S/ PETER B. OLEKSIAK	Date:	February 14, 2014
Peter B. Oleksiak Senior Vice President and Chief Financial Officer of DTE Energy Company

EX-32.87

Exhibit 32-87

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of DTE Energy Company (the “Company”) for the year ended December 31, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Gerard M. Anderson, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge and belief:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	February 14, 2014	/S/ GERARD M. ANDERSON
		Gerard M. Anderson Chairman of the Board and Chief Executive Officer of DTE Energy Company

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.88

Exhibit 32-88

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of DTE Energy Company (the “Company”) for the year ended December 31, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Peter B. Oleksiak, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge and belief:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	February 14, 2014	/S/ PETER B. OLEKSIAK
		Peter B. Oleksiak Senior Vice President and Chief Financial Officer of DTE Energy Company

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.55

Execution Copy        Exhibit 99 -55

FIRST AMENDMENT TO

AMENDMENT AND RESTATEMENT OF

MASTER TRUST AGREEMENT

This First Amendment to the Amendment and Restatement of Master Trust Agreement (the “Amendment”) is made and entered into by and between JPMorgan Chase Bank, N.A. (the “Trustee”), DTE Energy Corporate Services, LLC (“the Employer”) and DTE Energy Investment Committee (“Plan Administrator”).

WHEREAS, the Trustee, Employer and Plan Administrator are parties to an Amendment and Restatement of Master Trust Agreement dated as of October 15, 2010 (the “Agreement”) pertaining to the DTE Energy Company Savings and Stock Ownership Plan; Detroit Edison Company Savings & Stock Ownership Plan for Employees Represented by Local 223 of the Utility Workers Union of America; Detroit Edison Company Savings & Stock Ownership Plan for Employees Represented by Local 17 of the International Brotherhood of Electrical Workers; MichCon Investment and Stock Ownership Plan; (the “Plan”);

WHEREAS, the parties desire to amend the Agreement;

NOW, THEREFORE, in accordance with Section Thirteenth of the Agreement, the Trustee, the Employer and the Administrator do hereby agree to amend the Agreement, to be effective as of March 19, 2013, (“Effective Date”) in the following respects for plan name change:

1. All references to the Detroit Edison Company Savings & Stock Ownership Plan for Employees Represented by Local 223 of the Utility Workers Union of America in the Agreement shall be removed and replaced with DTE Electric Company Savings & Stock Ownership Plan for Employees Represented by Local 223 of Utility Workers Union of America.

2.All references to the Detroit Edison Company Savings & Stock Ownership Plan for Employees Represented by Local 17 of the International Brotherhood of Electrical Workers in the Agreement shall be removed and replaced with DTE Electric Company Savings & Stock Ownership Plan for Employees Represented by Local 17 of International Brotherhood of Electrical Workers.

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3.All references to the MichCon Investment and Stock Ownership Plan shall be removed and replaced with DTE Gas Company Investment and Stock Ownership Plan.

4.This Amendment may be executed in counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same Amendment. The parties’ execution and delivery of this Amendment by facsimile, email, or electronic copies shall have the same force and effect as execution and delivery of an original.

5.Except as modified herein, all other provisions of the Agreement shall continue in full force and effect.

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their respective duly authorized officers as of the day and year written below.

JPMORGAN CHASE BANK, N.A.

By: /s/Gerard T. Reilly, Jr.                                

Name:      Gerard T. Reilly, Jr.                                

Title:     Assistant Vice President                            

DTE ENERGY CORPORATE SERVICES, LLC

By: /s/Lisa A. Muschong                                

Name:      Lisa A. Muschong                                

Title:     Corporate Secretary & Chief of Staff                        

DTE ENERGY INVESTMENT COMMITTEE

By: /s/Paul B. Cavazos                                

Name:      Paul B. Cavazos                                

Title:     Secretary                                    

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EX-99.56

Exhibit 99-56

SECOND

AMENDMENT

TO THE

AMENDMENT AND RESTATEMENT OF THE

MASTER TRUST AGREEMENT

FOR THE DTE ENERGY COMPANY MASTER PLAN TRUST

SECOND AMENDMENT

TO AMENDMENT AND RESTATEMENT OF THE

MASTER TRUST AGREEMENT

FOR THE DTE ENERGY COMPANY MASTER PLAN TRUST

THIS SECOND AMENDMENT (the “Amendment”) to the Amendment and Restatement of Master Trust Agreement for the DTE Energy Company Master Plan Trust (the “Trust Agreement”) is made and entered into as of the date executed by and between DTE Energy Corporate Services, LLC (the “Employer”), DTE Energy Investment Committee (the “Plan Administrator”) and JPMorgan Chase Bank, N.A. (“Trustee”).

Recitals

A.    The Employer, the Plan Administrator and the Trustee previously entered into the Trust Agreement dated as of October 15, 2010.

B.    The Employer and the Plan Administrator desire that the Trustee provide additional services under the Trust Agreement and the Trustee desires to provide such additional services, as detailed in Schedules C, D and E attached hereto (the “Additional Services”) for the fees set forth in the attached fee schedule, as such may be amended from time to time (the “Fee Schedule”).

C.    The Employer, Plan Administrator and Trustee desire to adopt this Amendment in order to engage the Trustee to provide the Additional Services under the Trust Agreement effective as of September 30, 2013.

Amendment

In accordance with Article THIRTEENTH of the Trust Agreement, the Employer, the Plan Administrator and the Trustee do hereby agree to amend the Trust Agreement to provide that the Trustee shall provide the Additional Services effective as of September 30, 2013.

The attached Schedules C, D and E and the Fee Schedule are hereby addended to the Trust Agreement, effective as of September 30, 2013.

This Amendment may be executed in counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same amendment.  The parties’ execution and delivery of this Amendment by facsimile, email, or electronic copies shall have the same force and effect as execution and delivery of an original.

Unless changed by this Amendment, all terms used in this Amendment shall have the same meaning as in the Trust Agreement and all provisions of the Trust shall be deemed to be unchanged except as specifically hereby amended.

The parties have caused this Amendment to be signed by their duly authorized representatives as of the dates set forth below.

DTE ENERGY CORPORATE ERVICES, LLC

“Employer”

By /s/Paul B. Cavazos                        

Its Assistant Treasurer and Chief Investment Officer    

Date: 9/26/2013                        

DTE ENERGY INVESTMENT COMMITTEE

“Plan Administrator”

By /s/Paul B. Cavazos                        

Its Solely In His Capacity As Secretary of the DTE    

Energy Investment Committee                

Date: 9/26/2013                        

JPMORGAN CHASE BANK, N.A.

“Trustee”

By /s/Sreecaran Ganesan                    

Its Vice President                        

Date: 9/26/13                            

Schedule C
Amendment and Restatement of the Master Trust Agreement for the DTE Energy Company Master Plan Trust

INVESTMENT ANALYTICS & CONSULTING AGREEMENT

BETWEEN

DTE ENERGY CORPORATE SERVICES, LLC,

DTE ENERGY INVESTMENT COMMITTEE,

AND

JPMORGAN CHASE BANK, N.A

DM3\2598412.13 E1412/00145

INVESTMENT ANALYTICS & CONSULTING AGREEMENT

This Agreement is made as of September 30, 2013.

BETWEEN

(1) JPMORGAN CHASE BANK, NATIONAL ASSOCIATION, 1 Chase Manhattan Plaza, New York, New York 10081 (“J.P. Morgan”); and

(2) DTE ENERGY CORPORATE SERVICES, LLC and DTE ENERGY INVESTMENT COMMITTEE(collectively, “Customer”).

WHEREAS

(A) The Customer acts as Sponsor, Investment Manager, Investor, Trust or similar capacity to certain Plans and/or Funds

(B) The parties hereto wish to agree to terms which will govern the provision of certain services described herein to the Customer by J.P. Morgan.

NOW it is hereby agreed as follows:

1. Definitions

1.1 “Account” means the portion of assets of a Plan or Fund managed separately by a particular investment manager.

1.2 “Annual Cap” meansan amount equal to twenty percent of the fees payable by the Customer for the Services during the then current calendar year.

1.3 “Reports” means the reports provided by J.P. Morgan to the Customer in accordance with this Agreement.

1.4“Services” means the provision of Reports under this Agreement.

1.5 “Special or consequential loss or damage” means any indirect loss or damage, special or consequential loss or damage, damage to reputation, or loss of profits, business, revenue, goodwill, expended management time or anticipated savings, whether or not such loss or damage was reasonably foreseeable by J.P. Morgan or any of its affiliates, and including any investment loss resulting from the reliance by the Customer on the accuracy or completeness of any Report.

2. The Services

2.1 J.P. Morgan agrees to provide to the Customer the Reports in respect of each Account, containing the details, and in the manner and frequency as described in Schedule C-1.

3. J.P. Morgan’s Status

3.1 The Customer acknowledges that the Reports are provided exclusively for the purpose of assisting the Customer in monitoring the investment performance of the Accounts. J.P. Morgan is providing a reporting service to the Customer to assist it in the management of the Accounts and, in doing so, is not acting in a fiduciary

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capacity for the Accounts. The Customer acknowledges that J.P. Morgan has no responsibility for the selection, monitoring or termination of any investment manager with respect to any of the Accounts and that the Reports are not intended to be considered the rendering of investment advice or in any way to influence any investment decisions or the selection of any investment managers for the Accounts.

3.2 J.P. Morgan has no duty to advise the Customer as to the purchase or sale of any Securities or to monitor the performance of the Securities, save for the purpose of producing the Reports.

3.3 Neither J.P. Morgan nor any third party suppliers or third party licensors shall have any liability for any of the Customer's direct or indirect reliance on the Reports, including, but not limited to, investment decisions, regulatory filings or other uses made in reliance upon any such Report by the Customer. The Customer assumes sole responsibility for its use of the Reports and holds J.P. Morgan harmless against any liability or claim of any person that is attributable to improper use of the Reports by the Customer.

4. Reliance on Information

4.1. In preparing the Reports, J.P. Morgan may obtain and rely on information provided by third parties selected by it. Such third parties may include, but are not limited to, index return providers, security characteristics providers, and Value-at-Risk statistics providers. J.P. Morgan will use reasonable care in the selection of such third parties, but neither J.P. Morgan nor any third party provider selected by J.P. Morgan shall have any liability for the content of such information provided or for any reliance placed on such information.

4.2 Where J.P. Morgan relies on accounting, pricing and associated security data information provided by the Customer or its third party administrator, J.P. Morgan has no liability for the content of the information or for any reliance placed on that information.

4.3 Customer acknowledges and agrees that J.P. Morgan will make use of various calculation methodologies in preparing the Reports. Customer acknowledges and agrees that it has had an opportunity to make inquiries regarding J.P. Morgan’s methodologies for the Services and, whether or not Customer availed itself of such opportunity, Customer hereby acknowledges J.P. Morgan’s use of such methodologies in preparing the Reports.

5. Fees

5.1 In consideration of J.P. Morgan providing the Services as described in this Agreement to the Customer, the Customer shall pay J.P. Morgan such fees as are set forth in Schedule C-2.

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6. Termination

6.1 This Agreement will be in effect for an initial term of three years, effective as of the date of this Agreement. If the Customer terminates the Agreement prior to the initial term, the termination fee will be an amount equal to the fees that would have been otherwise paid for the balance remaining on the initial term of three years. This balance will be based on the average monthly volumes during the six month period prior to the Customer’s notice of termination.

6.2 After the initial term, the Agreement will be automatically renewed for successive one-year periods. This Agreement may be terminated by either party after the initial term of this Agreement, by giving the other party notice in writing ninety days prior to the start of a new one-year period.

7. Liability

7.1 J.P. Morgan will use reasonable care in preparing the Reports, and take reasonable precautions to ensure that the Services provided to the Customer are complete and accurate. J.P. Morgan will only be liable to the extent that any liability is solely attributable to its negligence or willful default in preparing or providing the Reports. Furthermore, J.P. Morgan shall not be liable in any event for any special or consequential loss or damage in connection with the Services provided under this Agreement.

7.2 The Customer agrees that J.P. Morgan’s aggregate liability (either in tort, for breach of contract, or otherwise) for damages or losses incurred during any calendar year arising under this Agreement shall not exceed an amount equal to the Annual Cap. No action (either in tort, for breach of contract, or otherwise) arising out of or pertaining to the Services may be brought more than one year after the cause of action has accrued.

7.3 J.P. Morgan makes no warranties or representations of any kind, whether express, implied, statutory or otherwise, concerning the Reports or the Services provided hereunder.

7.4 J.P. Morgan shall have no liability, and shall not be obliged to provide the Services as described in this Agreement where it is prevented from doing so (either in whole or in part), arising because of an act of God, fire, flood, severe weather, civil or labor disturbance, act of war or terrorism, act of any governmental or other authority, or threat of any such act, legal constraint, malfunction of equipment (including, without limitation, computer or related software), failure of or the effect of rules or operations of any funds or securities transfer system or any pricing service or agency, inability to obtain information from third parties, interruption or failure of communications facilities (including, without limitation, Internet service), or any other cause beyond the reasonable control of J.P. Morgan. Notwithstanding the foregoing, J.P. Morgan shall maintain a commercially reasonable disaster recovery / business continuity program.

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8. Redistribution

8.1 Except as expressly set forth below in 8.3, Customer shall not re-market or re-distribute any data or other output from the Services – including, but not limited to, raw data (such as entire index databases of historical returns or security level data) or all or substantially all of the Reports (“Data”) – without prior written permission from J.P. Morgan.

8.2 The Data and the Services may contain data licensed from third party suppliers (for example, MSCI, Merrill Lynch). This third-party data is the intellectual property of those vendors and is subject to restrictions contained in the licenses, which J.P. Morgan cannot unilaterally change. If the third party supplier adds additional restrictions to the third party’s data's use, J.P. Morgan shall use reasonable efforts to notify the Customer of such change in writing. Customer's continued use of the data after receipt of notice shall constitute Customer's acceptance of the revised usage provision.

8.3 Customer is permitted to (i) create Derived Data from the Data, (ii) use the Derived Data for internal business analysis purposes, and (iii) may use the Reports or Derived Data from the Reports to produce internal and external performance comparisons and/or analyses, including marketing and client service materials for use with Customer’s existing and prospective clients and partners. “Derived Data” shall mean data created by Customer, in connection with Customer’s use of the Data as permitted under the terms of this Agreement, as a result of combining, processing, changing, converting or calculating the Data or any portion thereof with other data and which cannot be readily reverse engineered such that a third-party may access the Data via the Derived Data. In order to use and/or create Derived Data as set forth above, Customer agrees (i) to obtain any prior licenses, consents, or permits required by the third party suppliers, and (ii) not distribute or create Derived Data in the event the third party supplier prohibits the use of their information in this manner.

9. Miscellaneous

9.1 This Agreement will be governed and construed under the laws of the State of New York, as applicable, without regard to New York’s principles regarding conflict of laws, except that the foregoing shall not reduce any statutory right to choose New York law or forum. The parties consent to the exclusive jurisdiction of the courts of the State of New York. The parties further hereby knowingly, voluntarily and intentionally waive, to the fullest extent permitted by applicable law, any right to a trial by jury with respect to any such lawsuit or judicial proceeding arising or relating to this Agreement or the transactions contemplated hereby.

9.2 This Agreement, including the Schedules, sets out the entire Agreement between the parties in connection with the subject matter, and this Agreement supersedes any other agreement, statement, or representation relating to the subject matter of this Agreement, whether oral or written. Amendments must be in writing and signed by J.P. Morgan and the Customer.

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9.3 Notices will be served by registered mail or hand delivery to the address of the respective parties as set out on the first page of this Agreement, unless notice of a new address is given to the other parties in writing. Notice will not be deemed to be given unless it has been received.

9.4 This Agreement will be binding on each of the parties’ successors and assigns, but the parties agree that no party can assign its rights and obligations under this Agreement without the prior written consent of the other parties, which consent will not be unreasonably withheld.

9.5 If one or more provisions of this Agreement are held invalid, illegal or unenforceable in any respect on the basis of any particular circumstances or in any jurisdiction, the validity, legality and enforceability of such provision or provisions under other circumstances or in other jurisdictions and of the remaining provisions will not in any way be affected or impaired.

9.6 A person who is not a party to this Agreement shall have no right to enforce any term of this Agreement.

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SCHEDULE C-1

Description of Services

J.P. Morgan shall provide the reports detailed in this Schedule C-1 to the recipient designated by the Customer, which is J.P. Morgan Retirement Plan Services LLC (“RPS”), via email on a monthly basis:

• Performance Measurement – Calculated Monthly, Reported Monthly – Total Fund Level

Performance Measurement reporting provides a monthly rate of return against a benchmark. Performance data is compiled using market values and transactional data in the Trustee accounting system. Performance data is available at the total fund and composite level.

Note:    Requires subscription to Trustee Accounting services. Performance Measurement reporting is available on the 4th business day, or 2 days after accounting has been finalized, subject to Employer requirements.

Scope of Services:

(a) Access to existing standard package of account level Performance Measurement reports, which are available via email.

(b) Standard Performance Measurement reporting includes basic rates of return based on industry standard calculation methodologies for portfolios only. Does not include benchmarks.

(c) Start of service loading of historical data, at the total portfolio or composite – at no additional cost if supplied in our specific format.

(d) In line with market practice, J.P. Morgan does not provide performance calculations on portfolios where a majority of the positions are short.

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SCHEDULE C-2

Fees

As provided by Section 5 of this Agreement, J.P. Morgan will charge fees as set forth in the Fee Schedule dated September 30, 2013, as such Fee Schedule may be amended from time to time.

7    

Schedule D

Amendment and Restatement of the Master Trust Agreement for the DTE Energy Company Master Plan Trust

Accounting Services Rider

Bet

e

ACCOUNTING SERVICES RIDER

Between

DTE ENERGY CORPORATE SERVICES, LLC,

DTE ENERGY INVESTMENT COMMITTEE

and

JP MORGAN CHASE BANK, N.A.

DERGY CORPORATE SERVICES, LLC,

DTE ENERGY INVESTMENT COMMITTEE

and

JP MORGAN CHASE BANK, N.A.

ACCOUNTING SERVICES RIDER

DTE Energy Corporate Services, LLC and DTE Energy Investment Committee (collectively, the “Customer”), and J.P. Morgan Chase Bank, N.A. (“J.P. Morgan”) wish J.P. Morgan to provide certain accounting services with respect to certain accounts maintained under the Amendment and Restatement of the Master Trust Agreement for the DTE Energy Company Master Plan Trust (each a "Fund"). J.P. Morgan is willing to do so, under the terms and conditions set forth in this Accounting Services Rider (this "Rider").

1.    Services Provided.

(a)    J.P. Morgan will provide the accounting services set forth in Schedule D-1 to this Rider. J.P. Morgan shall be acting solely as agent for Customer in providing those services and shall not be deemed to be a fiduciary with respect to Customer, any Fund, or any investor or participant in any Fund with respect to those services, even if J.P. Morgan or one of its affiliates separately acts in a fiduciary capacity with respect to such Fund..

(b)    J.P. Morgan will also keep records relating to the services provided hereunder in such form and manner as J.P. Morgan may deem appropriate or advisable.

2.    Fees and Expenses.

Customer will pay J.P. Morgan for its services hereunder the fees set forth in Schedule D-2 to this Rider or such other amounts as may be agreed upon in writing from time to time, together with J.P. Morgan's reasonable out‑of‑pocket or incidental expenses, including, but not limited to, legal fees. Customer authorizes J.P. Morgan to charge the Trust Fund, for any such fees or expenses set forth in Schedule D-2 or otherwise agreed to in writing by Customer. J.P. Morgan may charge to the Trust Fund its reasonable out-of-pocket or incidental expenses, including but not limited to, legal fees, only after written notice by invoice to Customer.

3.    Valuation Rules.

(a)    J.P. Morgan shall determine the net value of the assets and liabilities of a Fund (including securities out on a loan and excluding collateral held therefor) in accordance with the valuation rules set forth in Schedule D-3 to this Rider (the "Valuation Rules") and such other procedures as J.P. Morgan and Customer may establish from time to time ("Additional Procedures"). In this regard, J.P. Morgan may propose changes or additions to the Additional Procedures by notice to Customer in advance of the effective date of the proposed changes or additions, and Customer shall be deemed to have agreed to such changes or additions unless it sends notice objecting thereto within ten days after the date of such notice.

(b)    For Funds that maintain a unit value, the Fund's unit value shall be the result obtained by dividing the net value of the Fund's assets and liabilities by the number of existing units of the Fund. In determining unit value, fractions will be taken to two or four decimal places, as agreed upon with Customer. Unit value shall be determined as of each valuation date before taking into account additions to and withdrawals from the Funds occurring as of such valuation date. At the direction of the Customer or in the case of an ERISA plan, the participant recordkeeper (the "Recordkeeper"), J.P. Morgan may make a uniform change on any Valuation Day (as defined in Schedule D-3 to this Rider) in the value of all outstanding units of a Fund, either by creating a larger number of smaller units or a smaller number of larger units pro rata across all unit holders.

4.    Limitation of Liability and Indemnification.

(a)    J.P. Morgan shall not be liable for any error of judgment or mistake of law or for any loss or expense suffered by Customer or any Fund, in connection with the matters to which this Rider relates, except

Accounting Services Rider – February 2011    Page 2

DM3\2598412.13 E1412/00145

for a loss or expense solely caused by or resulting from willful misfeasance, bad faith or gross negligence on J.P. Morgan's part in the performance of its duties or from reckless disregard by J.P. Morgan of its obligations and duties under this Rider. In no event shall J.P. Morgan be liable for any indirect, incidental, special or consequential losses or damages of any kind whatsoever (including but not limited to lost profits), even if J.P. Morgan has been advised of the likelihood of such loss or damage and regardless of the form of action. Furthermore, in the event of any error or omission in connection with the calculation of the net asset value of any Fund, J.P. Morgan's liability and responsibility shall be subject to the materiality standards set forth in Schedule D-4 to this Rider.

(b)    Customer will indemnify the Indemnified Persons against, and hold them harmless from, any Liabilities that may be imposed on, incurred by or asserted against any of them in connection with or arising out of J.P. Morgan's performance under this Rider, provided the Indemnified Persons have not acted with gross negligence or engaged in fraud or willful misconduct in connection with the Liabilities in question.

(c)    In performing its services hereunder, J.P. Morgan shall be entitled to rely on, and act in accordance with, any oral or written instructions, notices or other communications, including electronic transmissions, from Customer and its officers and directors, investors, investment managers, agents and other service providers which J.P. Morgan reasonably believes to be genuine and authorized, and the Indemnified Persons shall be indemnified by Customer for any Liabilities caused by such reliance. J.P. Morgan also shall be entitled to consult with and rely on the advice and opinions of outside legal counsel retained by J.P. Morgan, as necessary or appropriate.

5.    Applicability of Trust Agreement.

This Rider shall be governed by the terms and conditions of the DTE Energy Company Master Plan Trust Agreement (“Trust Agreement”) between the parties of which this Rider is a part, except to the extent specifically provided by this Rider. Capitalized terms in this Rider (including the Schedules) that are not defined herein but are defined in the Trust Agreement shall bear the definition set forth in the Trust Agreement.

6.    Effective Date; Term.

This Rider shall be effective as of September 30, 2013. This Rider shall continue in effect unless terminated by either party on 180 days' prior written notice. This Rider shall automatically terminate upon the termination of the Trust Agreement to which this Rider relates.

The provisions of Section 4 shall survive termination of this Rider.

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DM3\2598412.13 E1412/00145

SCHEDULE D-1

ACCOUNTING SERVICES

J.P. Morgan shall prepare the following accounting reports for each Fund:

_X_    Monthly Financial Report

_X_    Annual Financial Report

_X_    Annual ERISA Report

_X_    The Net Asset Value per unit for the agreed upon daily accounts will be provided each business day when the respective markets are open.

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DM3\2598412.13 E1412/00145

SCHEDULE D-2

FEES AND EXPENSES

Fees for services under this Rider are set forth in the Fee Schedule dated September 30, 2013, as such Fee Schedule may be amended from time to time

SCHEDULE D-3

VALUATION RULES

Time of Valuations

"Valuation Day" shall mean each day on which the New York Stock Exchange is open for business.

J.P. Morgan shall determine the value of the Fund or the value of the Fund’s units with respect to any Valuation Day as of the close of business of the New York Stock Exchange on that day, or at such other time on which J.P. Morgan and Customer may agree.

Valuation Rules

Except as otherwise expressly agreed by Customer and J.P. Morgan, the value of securities or other property held by a Fund shall be determined in accordance with the following rules (the “Valuation Rules”) and as further directed by Customer in Schedule D-1 attached hereto:

(a)    General Rules

(i)    Publicly-traded securities for which a price is readily available shall be reported based upon information and financial publications of general circulation, generally available statistical and valuation services, and records of security exchanges, or from quotes from brokers customarily used by J.P. Morgan for security pricing purposes;

(ii)    Units or shares in investment companies subject to the Investment Company Act of 1940 (“40 Act”) (“Mutual Funds”), shall be reported at the most recently announced net asset value pursuant to regulations under the 40 Act;

(iii)    Units or shares in limited liability companies, or other funds other than Mutual Funds (each, together with units or shares of investment companies, a “Fund”) or Group Trusts shall be reported at their most recent asset value or other unit or share value stated by the Fund or its operator;

(iv)    Units in Group Trusts shall be reported at the value stated by the trustee of the Group Trust;

(v)    Contracts of a type that J.P. Morgan, acting reasonably, determines to be an over-the-counter derivative (“OTC Derivative Contracts”) shall be reported at the price provided by the applicable investment manager or by a vendor selected by that investment manager or the Customer; and

(vi)    Other Securities shall be reported at prices certified by the applicable investment manager or at the price provided by a vendor or appraiser selected by the investment manager, or the Customer.

(b)    J.P. Morgan shall follow general market practice with regard to reviewing the reasonableness of prices received by it under clause (a)(i), but shall not otherwise be responsible for any error or inaccuracy in any such price as received by J.P. Morgan. The Customer or the applicable investment manager, as the

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DM3\2598412.13 E1412/00145

case may be, shall be deemed to have directed J.P. Morgan as to any price reported under clauses (a)(ii)-(vi), and J.P. Morgan shall conduct no review or verification of any such price.

(c)    The Customer or the applicable investment manager shall be responsible for assessing whether the prices reported by J.P. Morgan reflect the fair market value or fair value of the applicable asset at the time as of which J.P. Morgan reports the value of the account(s). J.P. Morgan shall have no obligation to make a fair value adjustment of any price received by it, although it will incorporate into its reports any fair value adjustment that the Customer or an investment manager may provide Instructions for, to the extent that it is practicable for J.P. Morgan to do so from an operational perspective. J.P. Morgan shall be fully protected in relying upon the prices reported in accordance with this Schedule D-3 to Accounting Services Rider for all purposes under this Agreement, as well as any requirements of the Financial Accounting Standards Board or Governmental Accounting Standards Board.

(d)    The Customer acknowledges that reported prices of securities (particularly values of OTC Derivative Contracts and other assets lacking a readily available price) are indicative values only and do not indicate the actual terms at which the relevant asset or liability could be sold or unwound.

(e)    In cases where the Customer selects J.P. Morgan or one of its affiliates as the vendor of prices of OTC Derivative Contracts, J.P. Morgan’s responsibility for the errors or omissions of such vendor shall be as set forth in a separate OTC Derivative Contract pricing agreement with the Customer.

Suspension of Fund Valuation

J.P. Morgan may suspend the valuation of a Fund in the event the New York Stock Exchange, or any other exchange on which the financial assets of a Fund trade, is closed, or during periods when trading on any such exchange is restricted or an emergency or any other unusual circumstances exist which make the disposition or valuation of financial assets owned by a Fund impracticable.

Accounting Services Rider – February 2011    Page 6

DM3\2598412.13 E1412/00145

SCHEDULE D-4

NET ASSET VALUE ERROR CORRECTION POLICY & PROCEDURES

Definitions

Terms defined in the Agreement to which this Schedule D-4 to Accounting Services Rider is attached shall have the same meaning herein as in the Trust Agreement.

“Basis Point” or “bps” means 0.0001 or 0.01% of net assets.

“Fund” shall mean those accounts maintained under the Trust Agreement with respect to which the Customer wishes J.P. Morgan to provide periodic NAV calculations.

A “Fund Benefit” means a situation where a Fund has either paid insufficient redemption proceeds as a result of an understatement of NAV or received excessive purchase proceeds as a result of an overstatement of NAV. When a Fund Benefit occurs, the unit holders effecting transactions suffer a corresponding loss.

A “Fund Loss” means a situation where a Fund has either paid excessive redemption proceeds as a result of an overstatement of the NAV, or received insufficient purchase proceeds, as a result of an understatement of the NAV. When a Fund Loss occurs, the unit holders effecting transactions receive a corresponding benefit (a “Unitholder Benefit”).

“NAV” shall mean the net value of a Fund’s assets and liabilities.

“NAV Error” means one or more errors in the computation of a Fund’s NAV which, when considered cumulatively, results in a difference between the originally computed NAV and the corrected NAV of at least $0.010 per unit. This computation is based upon the actual difference and is not based upon rounding of the NAV to the nearest cent per share. Where a Fund incurs instrument-driven portfolio liabilities (e.g., short selling) the absolute value of all instruments in the Fund shall be used for purposes of determining if the error equals or exceeds 10 Basis Points.

“NAV Error Period” means the period comprising those days during which an NAV Error existed.

“Net Fund Loss (Benefit) Amount” means an amount equal to the difference between (i) the aggregate amount of Fund Losses less (ii) the aggregate amount of Fund Benefits arising out of a given NAV Error. This amount shall be a “Net Fund Loss Amount” when a positive number and a “Net Fund Benefit Amount” when a negative number.

“Per Unit NAV” shall mean the result obtained by dividing a Fund’s NAV by the number of existing units of the Fund. In determining unit value, fractions will be taken to two or four decimal places, as agreed upon with the Customer. Unit value shall be determined as of each valuation date before taking into account additions to and withdrawals from the Funds occurring as of such valuation date.

“Per Unit NAV Error” is the difference between the originally computed per unit NAV, and the amount that would have been computed had the errors not occurred.

“Responsible Person” means a person who, by virtue of negligence, fraud, or willful misconduct, caused or contributed to a NAV Error.

General Principles

a.The process described in this Schedule D-4 shall be a comprehensive analysis encompassing all known errors. If there is a subsequent discovery of an error which occurs during the same period as another NAV Error that has previously been corrected in the manner described herein, the subsequently discovered error will be analyzed in isolation without taking into consideration the previously corrected errors.

Accounting Services Rider – February 2011    Page 7

DM3\2598412.13 E1412/00145

b.The Customer shall not be liable for any Net Fund Loss Amount in the absence of J.P. Morgan’s negligence. J.P. Morgan shall not be liable for (i) values provided to J.P. Morgan by any pricing service or vendor, (ii) values stated by the trustee of any group trust (other than a group trust of which J.P. Morgan is the trustee), (iii) the net asset value or other unit or share value as announced by any limited partnership, limited liability company, investment company, or other fund or its operator, (iv) any redemption fees, surrender charges or similar fees or charges imposed on any investment held by the Fund; or (v) the value of any securities or other property held in any Investment Alternative provided by the investment manager of such Investment Alternative

Correction procedures for Non-Unitized Master Trust Accounts (Defined Benefit and Non-Participant-Directed Defined Contribution Plan Accounts)

a.    In the event of an NAV Error, J.P. Morgan shall calculate the basis point impact of the NAV Error and the Net Fund Benefit or Net Fund Loss Amount for each affected period.

b.    If the Basis Point impact of the NAV Error exceeds 50 bps, J.P. Morgan will process appropriate adjustments to each Plan participating in the Fund, if applicable.

c.    All corrections shall be made by adjusting each participating Plan’s respective interests.

d.    Any Net Fund Loss Amount remaining following the foregoing steps in this Section 4 shall be funded by J.P. Morgan , only to the extent that such Net Fund Loss Amount is attributable to J.P. Morgan’s negligence.

Correction Procedures for Unitized Accounts (Participant-Directed Defined Contribution Plan Accounts)

a.    In the event of an NAV Error, J.P. Morgan shall calculate the Basis Point impact of the NAV Error and, if the Basis Point Impact of the NAV Error exceeds 10 bps, the Net Fund Loss Amount or Net Fund Benefit Amount.

b.    If the Basis Point of the NAV Errorimpact does not exceed 10 bps of the Fund’s NAV, no action need be taken

c.    Subject to subsection 5(e)of this Schedule, if the Basis Point impact is 10 bps or more but does not exceed 50 bps of the Fund’s NAV, J.P. Morgan shall reimburse the Fund for the Net Fund Loss Amount to the extent that the NAV Error is attributable to J.P. Morgan’s negligence. The Customer shall be responsible for obtaining reimbursement of the Net Fund Loss Amount to the extent attributable to any other Person (e.g., the adviser, administrator or record keeper) responsible for the NAV Error to the extent required of such party pursuant to its contractual arrangement with the Customer. If the Fund experienced a Net Fund Benefit Amount, no action need be taken; however, the Net Fund Benefit Amount will not be carried forward to any analysis performed in the future for other NAV Errors that may arise.

d.    If the Basis Point impact exceeds 50 basis points (0.50%), the Customer shall cause the Plan’s Recordkeeper to reprocess participant purchases and redemptions in the affected Fund to the extent set forth in Subsection 5(f) of this Schedule and take the steps specified in Subsection 5(f) of this Schedule to recoup any excess redemption payments in order to reduce the aggregate amounts of the Net Fund Losses and Net Fund Benefits arising out of the NAV Error. J.P. Morgan shall then reimburse the Fund for the reprocessing and any notification costs incurred under Subsection 5(f) of this Schedule and for any remaining Net Fund Loss Amount to the extent that the NAV Error is attributable to J.P. Morgan’s negligence. The Customer shall be responsible for obtaining reimbursement of those amounts from any other Person (e.g., the adviser, administrator or Recordkeeper) responsible for the NAV Errorto the extent required of such party pursuant to its contractual arrangement with the Customer

e.    If the Basis Point impact is 10 bps or more but less than 50 bps, and either J.P. Morgan or the Customer determines that the Net Fund Loss would be reduced (after taking into account the reprocessing and notification costs) if the processes set forth in Subsections 5(d) and (f) of this Schedule were followed

Accounting Services Rider – February 2011    Page 8

DM3\2598412.13 E1412/00145

would be less than the Net Loss Amount calculated under Subsection 5(c) of this Schedule, the parties shall follow the processes set forth in Subsection 5(d) and 5(f) of this Schedule instead of the process set forth in Subsection 5(c).

f.    Participant-level adjustments shall be made as follows:    

i.    In cases where a NAV Error has occurred, the Customer, upon J.P. Morgan’s request, will instruct the Plan’s Recordkeeper to reprocess transactions and to adjust each participant’s units in any Fund or investment option under the Plan upwards or downwards accordingly, at the expense of the responsible person or persons. If the Plan’s Recordkeeper does not agree to reprocess transactions resulting from a NAV Error for which J.P. Morgan is a responsible person, J.P. Morgan’s liability will be limited to the amount it would have been liable for had the reprocessing occurred.

ii.    If there has been a complete distribution or 100% withdrawal of a participant’s entire interest in the Plan which is affected by an NAV Error in one of the Funds, an understated Per Unit NAV will cause a distribution underpayment while an overstated Per Unit NAV will cause a distribution overpayment. If the participant account loss equals or exceeds $25 the Recordkeeper will send a notification to the participant (or other distributee) and the Fund will distribute the amount of the original underpayment on behalf of the Plan. If the participant account benefit equals or exceeds $25, the Customer will make good faith efforts to recover the overpayment from the participant (or other distributee).

Accounting Services Rider – February 2011    Page 9

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Schedule E    

Amendment and Restatement of the Master Trust Agreement for the DTE Energy Company Master Plan Trust

Cash Allocation and Rebalancing Services (J. P. MORGAN

CARSsm) Rider

Between

DTE ENERGY CORPORATE SERVICES, LLC,

DTE ENERGY INVESTMENT COMMITTEE

and

JP MORGAN CHASE BANK, N.A.

This Rider supplements the Amendment and Restatement of the Master Trust Agreement for the DTE Energy Company Master Plan Trust, dated October 15, 2010 (the “Agreement”) between DTE Energy Corporate Services, LLC and DTE Energy Investment Committee (collectively, the “Customer”) and JPMorgan Chase Bank, N.A. ( “J.P. Morgan”).

1.    Definitions

(a)    As used in this Rider the following terms shall be defined as follows:

“Absolute Dollar Amounts” means Customer-specified dollar amounts with respect to trades made in connection with Minimum/Maximum Trade Amounts.

“Annual Cap” means an amount equal to the annual fees payable to J.P. Morgan for the Services.

“Fund” means an investment alternative under the Plan for which J.P. Morgan is retained by the Customer to provide the Services.

“Underlying Fund” means any of the investments of which a Fund is comprised, whether comprised of interests in a mutual fund, group trust, or other collective investment vehicle or a separately managed account.

“Guidelines” means the cash allocation and/or rebalancing guidelines set forth on Schedule E-1 with respect to a Fund. Such guidelines may consist of Target Percentages, Minimum/Maximum Trade Amounts, Absolute Dollar Amounts, or other parameters and Tolerances, as hereinafter defined, with respect thereto, as directed by the Company to J.P. Morgan, which direction may be revised by the Company from time to time upon advance written notice to J.P. Morgan.

“Minimum/Maximum Trade Amounts” means Customer-specified dollar amounts added to any underlying investment component within a participant directed fund to dictate the thresholds for daily trades. When a Minimum/Maximum Trade Amount is applied, it will override the trade amount created in Cash Allocation and Rebalancing Services and the Minimum/Maximum Trade Amount will instead apply to any trade. A minimum trade is typically used for new investment options in order to prevent small dollar trades. The maximum trade is typically used to prevent very large trades being placed and the Fund incurring additional trade costs.

“Services” means the allocation and rebalancing services to be provided under this Rider, as more particularly described in Sections 2 and 3 below.

“Target Percentage” means the Customer-specified target percentage for an underlying investment within a participant directed fund. The total Target Percentage for each participant directed fund must total 100%.

“Tolerance” means the Customer-specified permissible parameters of a Fund’s holdings in the applicable Underlying Fund, as set forth on Schedule E-1 to this Rider (as amended from time to time). A Tolerance is a percentage amount that is added by the Customer to the Target Percentage for an underlying component in a

participant directed fund. The Tolerance creates a band around a Target Percentage and expands the threshold for trading before a rebalance occurs.

(b) Other capitalized terms used in this Rider shall have the meaning set forth in the Agreement.

2.    Allocation Service [Check if applicable x and initial ___]

(a) In cases where cash is credited to a Fund, J.P. Morgan shall allocate that cash to that Fund’s Underlying Funds in accordance with the Guidelines applicable to cash allocations. J.P. Morgan shall execute, in accordance with the Guidelines, purchase or redemption orders in the proper amount with that Underlying Fund or in the case of an Underlying Fund which is a separately managed account, credit cash to that account, in the applicable amount.

(b) In cases where J.P. Morgan is given Instructions to redeem investments in a Fund, J.P. Morgan shall allocate the amount of cash required to be raised among the Fund’s Underlying Funds in accordance with the Guidelines applicable to cash allocations. J.P. Morgan shall execute, in accordance with the Guidelines, purchase or redemption orders in the proper amount with that Underlying Fund, or in the case of a separately managed account, notify the Investment Manager of the amount of cash needed, in the applicable amount.

3.    Rebalancing Service

(a) On or about the days set forth on Schedule E-1 with respect to a given Fund, J.P. Morgan shall calculate the percentage and/or dollar amount of the Fund’s assets which are invested in each underlying Fund. In the event that the portion of the Fund’s assets invested in any Underlying Fund is outside the Tolerance for that Underlying Fund, J.P. Morgan shall execute purchase or redemption orders in the proper amount with that Underlying Fund (or in the case of an Underlying Fund that is a separately managed account arrange for the deposit of cash in or withdrawal of cash from that account) in such an amount as is necessary to make the Fund’s investment in that Underlying Fund consistent with the rebalancing parameters set forth in the Guidelines. In no event shall J.P. Morgan be required to settle any investment in an Underlying Fund unless the Fund has sufficient cash on hand to fund the settlement.

(b) In carrying out the purchase and redemptions transactions required under Section 3(a), J.P. Morgan shall arrange for the investment of cash proceeds of redemptions of an Underlying Fund that is in excess of its Tolerance, and shall redeem interests in other Underlying Funds as needed to fund a purchase with regard to an Underlying Fund that is below its Tolerance, provided that:

(i) the proportion of the cash to be purchased or redeemed that would ordinarily be allocated to an Underlying Fund that is out of Tolerance shall be reallocated to the remaining Underlying Funds in accordance with the parameters set forth in the Guidelines for rebalancing; and

(ii) to the extent that the amount of cash to be invested in or redeemed from any of the remaining Underlying Funds would, if included in the Underlying Fund on the date of the investment cause that Underlying Fund to be out of Tolerance, that amount of cash shall be allocated to the other Underlying Funds in accordance with the parameters set forth in the Guidelines for rebalancing;.

4.    Compliance with Underlying Fund Rules

To the extent applicable to the Underlying Funds, the Customer shall (i) be responsible for compliance by the trust and plan participants with Rule 22c-2 under the Investment Company Act of 1940, (ii) cause any recordkeeper engaged by the Customer to comply with Rule 22c-2, and (iii) comply or cause any such recordkeeper or plan participant, as applicable, to comply with any requests and/or requirements of any investment company relating to Rule 22c-2 or compliance with any provision of the investment company’s prospectus or statement of additional information. The foregoing obligations shall also apply with respect to an Underlying Fund which is not an investment company but which applies rules similar to those of Rule 22c-2.

5.    Non-Fiduciary Nature of Service

The Customer acknowledges and agrees that J.P. Morgan: does not exercise any discretion or any authority or control in performing the Services; does not have any authority or discretion to change the Target or Tolerance assigned to any Underlying Fund; and shall be acting solely as agent for the Customer in providing the Services, and that the Services are not intended to be fiduciary in nature, even if J.P. Morgan separately acts in a fiduciary capacity with respect to the Plans.

6.    Liability

(a) Except to the extent required by applicable law, including but not limited to ERISA, the Customer agrees that J.P. Morgan’s aggregate liability (either in tort, for breach of contract or otherwise) for damages or losses incurred with regard to the Services during any calendar year shall not exceed an amount equal to the Annual Cap.

(b) Except to the extent required by applicable law, including but not limited to ERISA, no action (either in tort, for breach of contract or otherwise) arising out of any error or omission in performing the Services may be brought against J.P. Morgan more than one year after the cause of action has accrued.

7.    Compensation

The Customer shall pay J.P. Morgan for performing the Services as agreed in the Fee Schedule dated September 30, 2013, as such Fee Schedule may be amended from time to time.

8.    Applicability of the Agreement

This Rider shall be governed by the terms and conditions of the Agreement, except to the extent specifically provided by this Rider.

9.    Effective Date; Term

This Rider shall be effective as of September 30, 2013. This Rider shall continue in effect unless terminated by either party on 30 days’ prior written notice and shall terminate automatically upon termination of the Agreement.

Schedule E-1A: Initial Cash Allocation as of September 30, 2013

Schedule E-1B: Target Allocation—Rebalanced Monthly, First of the Month

Schedule E-1C: Tolerances

CONFIDENTIAL AND PROPRIETARY INFORMATION

Schedule E-1D: Minimum Trade Amounts

CONFIDENTIAL AND PROPRIETARY INFORMATION

Schedule E-1E: Maximum Trade Amounts

CONFIDENTIAL AND PROPRIETARY INFORMATION

FEE SCHEDULE

CONFIDENTIAL AND PROPRIETARY INFORMATION

XML

Acquisition (Tables)

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Schedule of Purchase Price Allocation [Table Text Block]

The following table summarizes the fair value of the assets acquired and liabilities assumed as of the closing date:

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

XML

Segment Information (Inter-segment billing) (Details) (Intersegment Eliminations [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Inter-Segment Revenue [Line Items]
Revenue, Net	$ 868	$ 848	$ 301
Electric [Member]
Inter-Segment Revenue [Line Items]
Revenue, Net	26	29	33
Gas [Member]
Inter-Segment Revenue [Line Items]
Revenue, Net	4	4	2
Gas Storage and Pipelines [Member]
Inter-Segment Revenue [Line Items]
Revenue, Net	3	6	8
Power and Industrial Projects [Member]
Inter-Segment Revenue [Line Items]
Revenue, Net	816	801	238
Energy Trading [Member]
Inter-Segment Revenue [Line Items]
Revenue, Net	43	43	70
Corporate and Other [Member]
Inter-Segment Revenue [Line Items]
Revenue, Net	(24)	(37)	(50)
Discontinued Operations [Member]
Inter-Segment Revenue [Line Items]
Revenue, Net	$ 0	$ 2	$ 0

XML

Capital and Operating Leases (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Capital and Operating Leases [Abstract]
Operating Leases, Rent Expense	$ 34	$ 36	$ 40
Description of Lessor Leasing Arrangements, Capital Leases	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.

XML

Segment Information (Tables)

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

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

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 in the following segments:

	2013			2012			2011
	(In millions)
Electric	$	26		$	29		$	33
Gas	4			4			2
Gas Storage and Pipelines	3			6			8
Power and Industrial Projects	816			801			238
Energy Trading	43			43			70
Corporate and Other	(24		)	(37		)	(50		)
Discontinued Operations	—			2			—
	$	868		$	848		$	301

Schedule of Segment Reporting Information, by Segment [Table Text Block]

Financial data of the business segments follows:

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures
	(In millions)
2013
Electric	$	5,199		$	902	$	(1	)	$	268		$	252		$	484		$	17,508		$	1,208	$	1,325
Gas	1,474			95		(7		)	58			77			143			3,938			743		209
Gas Storage and Pipelines	132			23		(7		)	18			45			70			824			24		245
Power and Industrial Projects	1,950			72		(6		)	27			(45		)	66			1,067			26		93
Energy Trading	1,771			1		—			8			(38		)	(58		)	623			17		3
Corporate and Other	3			1		(51		)	120			(37		)	(44		)	2,945			—		1
Reclassifications and Eliminations	(868		)	—		63			(63		)	—			—			(970		)	—		—
Total	$	9,661		$	1,094	$	(9	)	$	436		$	254		$	661		$	25,935		$	2,018	$	1,876

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures
	(In millions)
2012
Electric	$	5,293		$	827	$	(1	)	$	272		$	280		$	483		$	17,755		$	1,208	$	1,230
Gas	1,315			92		(7		)	59			50			115			4,059			745		221
Gas Storage and Pipelines	96			8		(8		)	8			39			61			668			22		233
Power and Industrial Projects	1,823			65		(7		)	37			(44		)	42			991			26		83
Energy Trading	1,109			2		—			8			7			12			629			17		1
Corporate and Other	3			1		(52		)	121			(46		)	(47		)	3,074			—		3
Reclassifications and Eliminations	(848		)	—		65			(65		)	—			—			(837		)	—		—
Total from Continuing Operations	$	8,791		$	995	$	(10	)	$	440		$	286		$	666		$	26,339		$	2,018	$	1,771
Discontinued Operations (Note 7)															(56		)	—			—		49
Total															$	610		$	26,339		$	2,018	$	1,820

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures
	(In millions)
2011
Electric	$	5,154		$	818	$	(1	)	$	289		$	265		$	434		$	17,567		$	1,208	$	1,203
Gas	1,505			89		(7		)	64			60			110			4,065			745		179
Gas Storage and Pipelines	91			6		(5		)	7			35			57			538			22		16
Power and Industrial Projects	1,129			60		(8		)	32			11			38			789			26		56
Energy Trading	1,276			3		—			9			34			52			612			17		1
Corporate & Other	4			1		(47		)	145			(136		)	23			2,605			—		—
Reclassifications and Eliminations	(301		)	—		58			(58		)	(1		)	—			(485		)	—		—
Total from Continuing Operations	$	8,858		$	977	$	(10	)	$	488		$	268		$	714		$	25,691		$	2,018	$	1,455
Discontinued Operations (Note 7)															(3		)	318			2		29
Total															$	711		$	26,009		$	2,020	$	1,484

XML

Preferred and Preferenced Securities (Tables)

12 Months Ended

Dec. 31, 2013

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

Preferred and Preference Securities [Table Text Block]

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

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

XML

Retirement Benefits and Trusteed Assets (Pension Plan - Fair Value Measurements) (Details) (Pension Plan, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 3,720	$ 3,223	$ 2,886
Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2,034	1,667
Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,121	1,038
Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	565	518
Short-term investments [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	22	24
Short-term investments [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	22	0
Short-term investments [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	24
Short-term investments [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
US Large Cap Equity Securities [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	896	732
US Large Cap Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	896	688
US Large Cap Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	44
US Large Cap Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
US Small Cap and Mid Cap Equity Securities [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	221	158
US Small Cap and Mid Cap Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	221	153
US Small Cap and Mid Cap Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	5
US Small Cap and Mid Cap Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Non US Equity Securities [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	741	650
Non US Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	611	530
Non US Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	130	120
Non US Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fixed income securities [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	937	852
Fixed income securities [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	16	87
Fixed income securities [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	921	765
Fixed income securities [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Hedge Funds and Similar Investments [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	733	628
Hedge Funds and Similar Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	268	209
Hedge Funds and Similar Investments [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	70	80
Hedge Funds and Similar Investments [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	395	339
Private Equity and Other [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	170	179
Private Equity and Other [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Private Equity and Other [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Private Equity and Other [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 170	$ 179

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Fair Value (Gains and Losses and Proceeds from the Sale of Securities by the Nuclear Decommissioning Trust Funds) (Details) (Nuclear Decommissioning Trust Fund [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Nuclear Decommissioning Trust Fund [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Realized gains	$ 83	$ 37	$ 46
Realized losses	(41)	(31)	(38)
Proceeds from sales of securities	$ 1,118	$ 759	$ 833

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Retirement Benefits and Trusteed Assets (OPEB - Other Changes in Plan Assets and APBO Recognized in Regulatory Assets and OCI) (Details) (Other Postretirement Benefit Plan, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ (353)	$ (34)
Amortization of net actuarial loss	(64)	(80)
Prior service credit	(218)	(264)
Amortization of prior service cost	131	27
Amortization of transition asset	0	(2)
Total recognized Regulatory assets and Other comprehensive income	(504)	(353)
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive icnome	(546)	(202)
Future amortization of net actuarial loss into net periodic benefit cost	21	69
Future amortization of prior service credit into net periodic benefit cost	$ (144)	$ (91)

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Supplementary Quarterly Financial Information (Unaudited ) (Tables)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information [Table Text Block]

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

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
	(In millions, except per share amounts)
2013
Operating Revenues	$	2,516	$	2,225	$	2,387	$	2,533	$	9,661
Operating Income	$	410	$	223	$	329	$	241	$	1,203
Net Income Attributable to DTE Energy Company	$	234	$	105	$	198	$	124	$	661
Basic Earnings per Share	$	1.35	$	0.60	$	1.13	$	0.70	$	3.76
Diluted Earnings per Share	$	1.34	$	0.60	$	1.13	$	0.70	$	3.76

2012
Operating Revenues	$	2,239	$	2,013		$	2,190	$	2,349		$	8,791
Operating Income	$	312	$	294		$	406	$	267		$	1,279
Net Income Attributable to DTE Energy Company
Continuing Operations	$	156	$	147		$	226	$	137		$	666
Discontinued Operations	—		(1		)	1		(56		)	(56		)
Net Income Attributable to DTE Energy Company	$	156	$	146		$	227	$	81		$	610
Basic Earnings per Share
Continuing Operations	$	0.91	$	0.87		$	1.31	$	0.79		$	3.89
Discontinued Operations	—		(0.01		)	0.01		(0.32		)	(0.33		)
Total	$	0.91	$	0.86		$	1.32	$	0.47		$	3.56
Diluted Earnings per Share
Continuing Operations	$	0.91	$	0.87		$	1.30	$	0.79		$	3.88
Discontinued Operations	—		(0.01		)	0.01		(0.32		)	(0.33		)
Total	$	0.91	$	0.86		$	1.31	$	0.47		$	3.55

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Financial and Other Derivative Instruments (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	$ 1
Letters of Credit Outstanding, Amount	19	63
Cash Collateral Posted Net of Cash Collateral Received	12
Cash Collateral Paid or Received for Derivative Assets	26	0
Cash Collateral Paid or Received for Derivative Liabilities	17
Cash Collateral Paid	34	4
Cash Collateral Received	13	24
Value of Transactions Company Would Have Been Exposed to if Credit Rating Below Investment Grade	406
Derivative, Net Liability Position, Aggregate Fair Value	1,176
Collateral Already Posted, Aggregate Fair Value	902	20
Additional Collateral, Aggregate Fair Value	249
FTR [Member]
Derivative [Line Items]
Derivative Instruments Recoverable Through PSCR Mechanism	5	15
Credit Risk Contract [Member]
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	$ 25

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Long-Term Debt (Debt Redemptions) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended	1 Months Ended								9 Months Ended	1 Months Ended
	Dec. 31, 2013	Sep. 30, 2013 Electric [Member] Securitization Bonds [Member]	Mar. 31, 2013 Electric [Member] Securitization Bonds [Member]	Dec. 31, 2013 Electric [Member] Tax Exempt Revenue Bonds [Member]	Mar. 31, 2013 Electric [Member] Tax Exempt Revenue Bonds [Member]	Apr. 30, 2013 Electric [Member] Long Term Debt, Other [Member]	Sep. 30, 2013 Electric [Member] Senior Notes [Member]	Dec. 31, 2013 Electric [Member] Tax-Exempt Revenue Bonds 1 [Member]	Apr. 30, 2013 Gas [Member] Senior Notes [Member]	Sep. 30, 2013 DTE Energy [Member] Long Term Debt, Other [Member]	Jun. 30, 2013 DTE Energy [Member] Senior Notes [Member]
Extinguishment of Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.62%	6.42%	5.50%	5.30%		6.40%	6.75%	5.26%
Extinguishment of Debt, Amount	$ 961	$ 89	$ 88	$ 49	$ 51	$ 13	$ 250	$ 50	$ 60	$ 11	$ 300

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

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

A reconciliation of both calculations is presented in the following table as of December 31:

	2013		2012		2011
	(In millions, expect per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	661	$	610	$	711
Average number of common shares outstanding	175		171		169
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	453	$	413	$	392
Dividends declared — net restricted shares	1		1		1
Total distributed earnings	$	454	$	414	$	393
Net income less distributed earnings	$	207	$	196	$	318
Distributed (dividends per common share)	$	2.59	$	2.42	$	2.32
Undistributed	1.17		1.14		1.87
Total Basic Earnings per Common Share	$	3.76	$	3.56	$	4.19
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	661	$	610	$	711
Average number of common shares outstanding	175		171		169
Average incremental shares from assumed exercise of options	—		1		1
Common shares for dilutive calculation	175		172		170
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	453	$	413	$	392
Dividends declared — net restricted shares	1		1		1
Total distributed earnings	$	454	$	414	$	393
Net income less distributed earnings	$	207	$	196	$	318
Distributed (dividends per common share)	$	2.59	$	2.42	$	2.32
Undistributed	1.17		1.13		1.86
Total Diluted Earnings per Common Share	$	3.76	$	3.55	$	4.18

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Basis of Accounting, Policy [Policy Text Block]

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.

Consolidation, Variable Interest Entity, Policy [Policy Text Block]

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. 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. 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 and are consolidated when the Company is the primary beneficiary. In addition, 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, 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, 2013 and 2012. All assets and liabilities of a consolidated VIE are presented where it has been determined that 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. 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.

Revenues Policy [Policy Text Block]

Revenues

Revenues from the sale and delivery of electricity, and the sale, delivery and storage of natural gas are recognized as services are provided. DTE Electric and DTE Gas record revenues for electricity and gas provided but unbilled at the end of each month. Rates for DTE Electric and DTE Gas include provisions to adjust billings for fluctuations in fuel and purchased power costs, cost of natural gas and certain other costs. Revenues are adjusted for differences between actual costs subject to reconciliation and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are recorded on the Consolidated Statements of Financial Position and are recovered or returned to customers through adjustments to the billing factors.

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

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

Accounting For ISO Transactions [Policy Text Block]

Accounting for ISO Transactions

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

Energy Trading participates in the energy markets through various independent system operators and regional transmission organizations (ISOs and RTOs). These markets require that Energy Trading submits hourly day-ahead, real-time bids and offers for energy at locations across each region. 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 trading contracts which are presented on a net basis in Operating Revenues in the Consolidated Statements of Operations.

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

Comprehensive Income [Policy Text Block]

Comprehensive Income (Loss)

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 tables, amounts recorded to accumulated other comprehensive loss for the year ended December 31, 2013 include unrealized gains and losses from derivatives accounted for as cash flow hedges, unrealized gains and losses on available-for-sale securities, the Company’s interest in 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.

Cash and Cash Equivalents [Policy Text Block]

Cash Equivalents and Restricted Cash

Cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with remaining maturities of three months or less. Restricted cash consists of funds held to satisfy requirements of certain debt, primarily Securitization bonds, and partnership operating agreements. Restricted cash designated for interest and principal payments within one year is classified as a current asset.

Receivables [Policy Text Block]

Receivables

Accounts receivable are primarily composed of trade receivables and unbilled revenue. Our accounts receivable are stated at net realizable value.

The allowance for doubtful accounts for DTE Electric and DTE Gas is generally calculated using the aging approach that utilizes rates developed in reserve studies. We establish an allowance for uncollectible accounts based on historical losses and management’s assessment of existing economic conditions, customer trends, and other factors. Customer accounts are generally considered delinquent if the amount billed is not received by the due date, which is typically in 21 days, however, factors such as assistance programs may delay aggressive action. We assess late payment fees on trade receivables based on past-due terms with customers. Customer accounts are written off when collection efforts have been exhausted. The time period for write-off is 150 days after service has been terminated.

The customer allowance for doubtful accounts for our other businesses is calculated based on specific review of probable future collections based on receivable balances in excess of 30 days.

Unbilled revenues of $815 million and $686 million are included in customer accounts receivable at December 31, 2013 and 2012, respectively.

Notes Receivable

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

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

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

Inventories [Policy Text Block]

Inventories

The Company generally values inventory at average cost.

Natural gas inventory of $4 million and $37 million as of December 31, 2013 and 2012, respectively, at DTE Gas is determined using the last-in, first-out (LIFO) method. At December 31, 2013, the replacement cost of gas remaining in storage exceeded the LIFO cost by $170 million. At December 31, 2012, the replacement cost of gas remaining in storage exceeded the LIFO cost by $113 million.

Property, Retirement and Maintenance, Depreciation, Depletion and Amortization [Policy Text Block]

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

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

Utility property at DTE Electric and DTE Gas is depreciated over its estimated useful life using straight-line rates approved by the MPSC.

Non-utility property is depreciated over its estimated useful life using the straight-line and units of production methods.

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

Approximately $26 million and $12 million of expenses related to Fermi 2 refueling outages were accrued at December 31, 2013 and 2012, respectively. Amounts are accrued on a pro-rata basis, generally over an 18-month period, that coincides with scheduled refueling outages at Fermi 2. This accrual of outage costs matches the regulatory recovery of these costs in rates set by the MPSC. See Note 11.

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

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

Long-Lived Assets [Policy Text Block]

Long-Lived Assets

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

Intangible Assets

Emission allowances and renewable energy credits are charged to expense, using average cost, as the allowances and credits are consumed in the operation of the business. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 1 to 28 years. Intangible assets amortization expense was $14 million in 2013, $6 million in 2012 and $5 million in 2011.

Deferred Debt Costs [Policy Text Block]

Deferred Debt Costs

The costs related to the issuance of long-term debt are deferred and amortized over the life of each debt issue. In accordance with MPSC regulations applicable to the Company’s electric and gas utilities, the unamortized discount, premium and expense related to 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.

Investments in Debt and Equity Securities [Policy Text Block]

Investments in Debt and Equity Securities

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

Government Grants [Policy Text Block]

Government Grants

Grants are recognized when there is reasonable assurance that the grant will be received and that any conditions associated with the grant will be met. When grants are received related to Property, Plant and Equipment, the Company reduces the 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.

Foundation Related Party [Policy Text Block]

DTE Energy Foundation

Charitable contributions to the DTE Energy Foundation were $18 million, $21 million, and $21 million for the years ended December 31, 2013, 2012 and 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.

Fair Value Measurement, Policy [Policy Text Block]

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, 2013 and 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:

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

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

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

Nuclear Decommissioning Trust and Other Investments, Policy [Policy Text Block]

The nuclear decommissioning trusts and other investments hold debt and equity securities directly and indirectly through institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices in actively traded markets. The 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 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 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 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.

Derivatives, Reporting of Derivative Activity [Policy Text Block]

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.

Fair Value Transfer, Policy [Policy Text Block]

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

Fair Value of Financial Instruments, Policy [Policy Text Block]

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

Derivatives, Policy [Policy Text Block]

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

The Company’s primary market risk exposure is associated with commodity prices, credit and interest rates. The Company has risk management policies to monitor and manage market risks. The Company uses derivative instruments to manage some of the exposure. The Company uses derivative instruments for trading purposes in its Energy Trading segment. Contracts classified as derivative instruments include power, natural gas, oil and certain coal forwards, futures, options and swaps, and foreign currency exchange contracts. Items not classified as derivatives include natural gas inventory, pipeline transportation contracts, renewable energy credits and natural gas storage assets.

Derivatives, Offsetting Fair Value Amounts, Policy [Policy Text Block]

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.

For contracts with certain clearing agents the fair value of derivative instruments is netted against realized positions with the net balance reflected as either 1) a derivative asset or liability or 2) an account receivable or payable. Other than certain clearing agents, accounts receivable and accounts payable that are subject to netting arrangements have not been offset against the fair value of derivative assets and liabilities. Certain contracts that have netting arrangements have not been offset in the Consolidated Statements of Financial Position. The impact of netting these derivative instruments and cash collateral related to such contracts is not material. Only the gross amounts for these derivative instruments are included in the table below.

Derivatives, Methods of Accounting, Derivatives Not Designated or Qualifying as Hedges [Policy Text Block]

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.

Asset Retirement Obligations, Policy [Policy Text Block]

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.

Public Utilities, Policy [Policy Text Block]

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 regulatory environment.

Income Tax, Policy [Policy Text Block]

Excise and Sales Taxes

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

Deferred 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.

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

Compensation Related Costs, Policy [Policy Text Block]

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

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Goodwill (Carrying Amount of Goodwill) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Goodwill [Line Items]
Beginning Balance	$ 2,018	$ 2,020
Goodwill Period Increase (Decrease)	0	(2)
Ending Balance	$ 2,018	$ 2,018

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Retirement Benefits and Trusteed Assets (Pension Plan - Benefits related to Qualified and Nonqualified Pension Plans Expected to be paid in the Next Ten Years) (Details) (Pension Plan, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Pension Plan, Defined Benefit [Member]
Pension Benefits to be Paid Over the Next 5 Years and Thereafter [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in next twelve months	$ 242
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	250
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	258
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	268
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	280
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	1,529
Total Defined Benefit Pension Plan Expected Future Payments	$ 2,827

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Retirement Benefits and Trusteed Assets (OPEB - Assumptions used in Determining the PBO and Net Pension Costs) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Mar. 31, 2013
Assumptions Used to Determine Projected Benefit Obligation and Benefit Costs [Line Items]
Health care trend rate pre and post 65			7.00%
Ultimate health care trend rate			5.00%
Other Postretirement Benefit Plan, Defined Benefit [Member]
Assumptions Used to Determine Projected Benefit Obligation and Benefit Costs [Line Items]
Assumptions Used Calculating Benefit Obligation, Discount Rate	4.95%	4.15%	5.00%	4.30%
Defined Benefit Plan Health Care Trend Rate Pre Sixty Five	7.50%
Defined Benefit Plan Health Care Trend Rate Post Sixty Five	6.50%
Health care trend rate pre and post 65	7.00%	7.00%	7.00%
Ultimate health care trend rate		5.00%	5.00%
Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.15%
Defined Benefit Plan Assumptions Used Calculating Other Postretirement Benefit Cost Discount Rate		5.00%	5.50%
Defined Benefit Plan Assumptions Used Calculating Other Postretirement Benefit Cost Discount Rate, post remeasurement	4.30%
Expected long-term rate of return on plan assets	8.25%	8.25%	8.75%
Accumulated postretirement benefit obligation [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Assumptions Used to Determine Projected Benefit Obligation and Benefit Costs [Line Items]
Ultimate health care trend rate	4.50%
Other postretirement benefit costs [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Assumptions Used to Determine Projected Benefit Obligation and Benefit Costs [Line Items]
Ultimate health care trend rate	5.00%

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Stock-Based Compensation (Stock Option Activity) (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options outstanding at beginning of period	1,192,670
Granted	0
Exercised	(458,603)
Forfeitured and expired	(10,370)
Options outstanding and exercisable at end of period	723,697
Weighted Average Exercise Price Per Share - Options outstanding at beginning of period	$ 41.86
Weighted Average Exercise Price Per Share - Granted	$ 0.00
Weighted Average Exercise Price Per Share - Exercised	$ 40.71
Weighted Average Exercise Price Per Share - Forfeitured or expired	$ 41.46
Weighted Average Exercise Price Per Share - Options outstanding and exercisable at end of period	$ 42.60
Aggregate Intrinsic Value - Options outstanding and exercisable at end of period	$ 18

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Financial and Other Derivative Instruments (Fair Value of Derivative Instruments) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivatives designated as hedging instruments:
Derivative Asset, Fair Value, Gross Asset	$ 833	$ 1,016
Derivative Liability, Fair Value, Gross Liability	(936)	(1,020)
Derivative Asset, Current	99	108
Derivative Assets, Noncurrent	27	39
Derivative Liabilities, Current	(195)	(125)
Derivative Liabilities, Noncurrent	(43)	(26)
Estimate of Fair Value, Fair Value Disclosure [Member]
Derivatives designated as hedging instruments:
Derivative Asset, Current	691	862
Derivative Assets, Noncurrent	142	154
Derivative Liabilities, Current	(773)	(879)
Derivative Liabilities, Noncurrent	(163)	(141)
Designated as Hedging Instrument [Member] | Interest rate contracts [Member]
Derivatives designated as hedging instruments:
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	0	(1)
Not Designated as Hedging Instrument [Member]
Derivatives designated as hedging instruments:
Derivative Asset, Fair Value, Gross Asset	833	1,016
Derivative Liability, Fair Value, Gross Liability	(936)	(1,019)
Not Designated as Hedging Instrument [Member] | Foreign currency exchange contracts [Member]
Derivatives designated as hedging instruments:
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	(1)	0
Not Designated as Hedging Instrument [Member] | Natural Gas [Member]
Derivatives designated as hedging instruments:
Derivative Asset, Fair Value, Gross Asset	396	645
Derivative Liability, Fair Value, Gross Liability	(503)	(661)
Not Designated as Hedging Instrument [Member] | Electricity [Member]
Derivatives designated as hedging instruments:
Derivative Asset, Fair Value, Gross Asset	400	360
Derivative Liability, Fair Value, Gross Liability	(398)	(351)
Not Designated as Hedging Instrument [Member] | Other [Member]
Derivatives designated as hedging instruments:
Derivative Asset, Fair Value, Gross Asset	37	11
Derivative Liability, Fair Value, Gross Liability	$ (34)	$ (7)

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Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning balance	$ 1,719
Accretion	106
Liabilities incurred	5
Liabilities settled	(13)
Revision in estimated cash flows	10
Asset retirement obligations, ending balance	$ 1,827

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Organization and Basis of Presentation (Details Textuals) (USD $) In Millions, unless otherwise specified		12 Months Ended
	Dec. 31, 2013 customers	Dec. 31, 2012 Proceeds from sale of nuclear decommissioning trust funds [Member]	Dec. 31, 2011 Proceeds from sale of nuclear decommissioning trust funds [Member]	Dec. 31, 2012 Investment in Nuclear Decommissioning Trust Funds [Member]	Dec. 31, 2011 Investment in Nuclear Decommissioning Trust Funds [Member]
Prior Period Reclassification Adjustment		$ 662	$ 753	$ (662)	$ (753)
Number of Electric Utility Customers	2,100,000
Number of Gas Utility Customers	1,200,000
Significant Potential Exposure to Loss Due to VIE Long-Term Purchase Contracts	$ 0

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Short-Term Credit Arrangements and Borrowings (Details Textuals) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013 banks	Dec. 31, 2012
Short-term Debt [Line Items]
Revolving Credit Facilities with a Syndicate Number of Banks	19
Number of Banks that Provide Percentage of Commitment in any Facility	1
Maximum Percentage of Commitment to Bank in any Facility	8.70%
Maximum Total Funded Debt to Total Capitalization Ratio	0.65
Letters of Credit Outstanding, Amount	$ 375
Short-term Debt, Weighted Average Interest Rate	0.20%	0.40%
DTE Energy [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio	0.48
Letters of Credit Outstanding, Amount	279
DTE Electric [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio	0.50
Letters of Credit Outstanding, Amount	0
DTE Gas [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio	0.48
Letters of Credit Outstanding, Amount	96
Letter of Credit [Member]
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	244
Letter of Credit [Member] | DTE Energy [Member]
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	244
Letter of Credit [Member] | DTE Electric [Member]
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	0
Letter of Credit [Member] | DTE Gas [Member]
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	0
Letter of Credit [Member] | Other outstanding letters of credit [Member] | DTE Energy [Member]
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	53
Letter of Credit [Member] | Demand Financing Agreement with Newedge letter of credit to raise capacity [Member] | DTE Energy [Member]
Short-term Debt [Line Items]
Borrowing Capacity Under Financing Agreement With iss Clearing Agent	50
Demand Financing Agreement with Newedge plus letter of credit [Member] | DTE Energy [Member]
Short-term Debt [Line Items]
Borrowing Capacity Under Financing Agreement With iss Clearing Agent	150
Demand Financing Agreement with Newedge [Member] | DTE Energy [Member]
Short-term Debt [Line Items]
Borrowing Capacity Under Financing Agreement With iss Clearing Agent	100
Maximum Additional Margin Financing	50
Financing Agreement, Amount Outstanding	$ 138	$ 65

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Stock-Based Compensation (Number, Weighted Average Exercise Price and Weighted Average Remaining Contractual Life of Options Outstanding) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Number of Options	723,697
Weighted Average Exercise Price	$ 42.60
Weighted Average Remaining Contractual Life (Years)	3 years 10 months
Exercise Price Range One [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices Lower Limit	$ 27.00
Range of Exercise Prices Upper Limit	$ 38.00
Number of Options	67,257
Weighted Average Exercise Price	$ 28.30
Weighted Average Remaining Contractual Life (Years)	5 years 1 month 23 days
Exercise Price Range Two [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices Lower Limit	$ 38.01
Range of Exercise Prices Upper Limit	$ 42.00
Number of Options	167,447
Weighted Average Exercise Price	$ 41.23
Weighted Average Remaining Contractual Life (Years)	3 years 2 months 15 days
Exercise Price Range Three [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices Lower Limit	$ 42.01
Range of Exercise Prices Upper Limit	$ 45.00
Number of Options	351,893
Weighted Average Exercise Price	$ 44.02
Weighted Average Remaining Contractual Life (Years)	4 years 1 month 27 days
Exercise Price Range Four [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices Lower Limit	$ 45.01
Range of Exercise Prices Upper Limit	$ 50.00
Number of Options	137,100
Weighted Average Exercise Price	$ 47.67
Weighted Average Remaining Contractual Life (Years)	3 years 1 month

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Financial and Other Derivative Instruments (Effect of Derivatives not Deisgnated as Hedging Instruments on the Consolidated Statement of Operations) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ (11)	$ 65
Foreign currency exchange contracts [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(1)	0
Natural Gas [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(48)	(29)
Natural Gas [Member] | Fuel, purchased power and gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(44)	25
Electricity [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	82	64
Other [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 0	$ 5

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Property, Plant and Equipment (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Public Utility Property, Plant and Equipment [Line Items]
AFUDC capitalized	$ 23	$ 20
Capitalized Computer Software, Amortization	71	68	65
Capitalized Computer Software, Gross	668	608
Capitalized Computer Software, Accumulated Amortization	384	313
Capital Leased Assets, Gross	35	32
Capital Leases, Lessee Balance Sheet, Assets by Major Class, Accumulated Depreciation	$ 21	$ 20
Electric [Member]
Public Utility Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	3.40%	3.30%	3.30%
Gas [Member]
Public Utility Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.40%	2.40%	2.30%
Minimum [Member]
Public Utility Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Finite-Lived Intangible Assets, Useful Life	1 year
Maximum [Member]
Public Utility Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	55 years
Finite-Lived Intangible Assets, Useful Life	28 years
Computer Software, Intangible Asset [Member] | Minimum [Member]
Public Utility Property, Plant and Equipment [Line Items]
Finite-Lived Intangible Assets, Useful Life	3 years
Computer Software, Intangible Asset [Member] | Maximum [Member]
Public Utility Property, Plant and Equipment [Line Items]
Finite-Lived Intangible Assets, Useful Life	15 years

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Valuation and Qualifying Accounts Valuation and Qualifying Accounts (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Valuation and Qualifying Accounts [Abstract]
Balance at Beginning of Period	$ 62	$ 162	$ 196
Charged to cost and expenses	94	79	94
Charged to other accounts	23	16	18
Deductions	(124)	(195)	(146)
Balance at End of Period	$ 55	$ 62	$ 162

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Acquisition (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Allocation of the Purchase Price to Assets and Liabilities [Line Items]
Business Combination, Cash	$ 22
Business Combination, Accounts receivables	14
Business Combination, Other Current assets	8
Business Combination, Property, Plant and Equipment	100
Business Combination, Intangible assets	75
Business Combination, Other Noncurrent Assets	9
Business Combination, Current Liabilities	(7)
Business Combination, Non-controlling Interest	(1)
Business Combination, Purchase Price	$ 220

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Jointly Owned Utility Plant (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013 dte.capacity
Belle River [Member]
Jointly Owned Utility Plant Interests [Line Items]
Total plant capacity (in MW)	1,270
Investment (in millions)	$ 1,702
Accumulated depreciation (in millions)	969
Ludington [Member]
Jointly Owned Utility Plant Interests [Line Items]
Total plant capacity (in MW)	1,872
Ownership interest	49.00%
Investment (in millions)	354
Accumulated depreciation (in millions)	$ 170

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Financial and Other Derivative Instruments (Cumulative Gross Volume of Derivative Contracts Outstanding) (Details)	Dec. 31, 2013 dte.volumes
Natural Gas [Member]
Derivative [Line Items]
Volume of Commodity Contracts	795,553,773
Electricity [Member]
Derivative [Line Items]
Volume of Commodity Contracts	55,658,483
Foreign currency exchange contracts [Member]
Derivative [Line Items]
Volume of Commodity Contracts	65,074,206
FTR [Member]
Derivative [Line Items]
Volume of Commodity Contracts	10,485,618

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Fair Value (Fair Value and Unrealized Gains for the Nuclear Decommissioning Trust Funds) (Details) (Nuclear Decommissioning Trust Fund [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Option, Quantitative Disclosures [Line Items]
Nuclear decommissioning trusts	$ 1,191	$ 1,037
Unrealized Gains	213	149
Equity Securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Equity securities	730	631
Unrealized Gains	201	122
Debt Securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Debt securities	442	399
Unrealized Gains	12	27
Cash and Cash Equivalents [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	19	7
Unrealized Gains	$ 0	$ 0

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Short-Term Credit Arrangements and Borrowings (Notes)

12 Months Ended

Dec. 31, 2013

Short-term Debt [Abstract]

Short-Term Credit Arrangements and Borrowings

SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

DTE Energy and its wholly owned subsidiaries, DTE Electric and DTE Gas, have unsecured revolving credit agreements with a syndicate of 19 banks that can be used for general corporate borrowings, but are intended to provide liquidity support for each of the companies’ commercial paper programs. No one bank provides more than 8.7% of the commitment in any facility. Borrowings under the facilities are available at prevailing short-term interest rates. Additionally, DTE Energy has other facilities to support letter of credit issuance.

The agreements require the Company to maintain a total funded debt to capitalization ratio of no more than 0.65 to 1. In the agreements, “total funded debt” means all indebtedness of the Company and its consolidated subsidiaries, including capital lease obligations, hedge agreements and guarantees of third parties’ debt, but excluding contingent obligations, nonrecourse and junior subordinated debt and certain equity-linked securities and, except for calculations at the end of the second quarter, certain DTE Gas short-term debt. “Capitalization” means the sum of (a) total funded debt plus (b) “consolidated net worth,” which is equal to consolidated total stockholders’ equity of the Company and its consolidated subsidiaries (excluding pension effects under certain FASB statements), as determined in accordance with accounting principles generally accepted in the United States of America. At December 31, 2013, the total funded debt to total capitalization ratios for DTE Energy, DTE Electric and DTE Gas are 0.48 to 1, 0.50 to 1 and 0.48 to 1, respectively, and are in compliance with this financial covenant. The availability under the facilities in place at December 31, 2013 is shown in the following table:

	DTE Energy		DTE Electric		DTE Gas		Total
	(In millions)
Unsecured letter of credit facility, expiring in May 2014	$	50	$	—	$	—	$	50
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Unsecured revolving credit facility, expiring April 2018	1,200		300		300		1,800
	1,375		300		300		1,975
Amounts outstanding at December 31, 2013:
Commercial paper issuances	35		—		96		131
Letters of credit	244		—		—		244
	279		—		96		375
Net availability at December 31, 2013	$	1,096	$	300	$	204	$	1,600

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $53 million which are used for various corporate purposes.

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

In conjunction with maintaining certain exchange traded risk management positions, the Company may be required to post cash collateral with its clearing agent. The Company has a demand financing agreement for up to $100 million with its clearing agent. The agreement, as amended, also allows for up to $50 million of additional margin financing provided that the Company posts a letter of credit for the incremental amount. At December 31, 2013, a $50 million letter of credit was in place, raising the capacity under this facility to $150 million. The $50 million letter of credit is included in the table above. The amount outstanding under this agreement was $138 million and $65 million at December 31, 2013 and 2012, respectively.

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Segment Information (Details Textuals)	Dec. 31, 2013 customers
Segment Reporting [Abstract]
Number of Electric Utility Customers	2,100,000
Number of Gas Utility Customers	1,200,000
Number of Citizens Gas Customers	17,000

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Capital and Operating Leases (Tables)

12 Months Ended

Dec. 31, 2013

Capital and Operating Leases [Abstract]

Capital and Operating Leases [Table Text Block]

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

	Capital Leases		Operating Leases
	(In millions)
2014	$	8	$	35
2015	8		31
2016	3		27
2017	—		25
2018	—		20
Thereafter	—		92
Total minimum lease payments	$	19	$	230
Less imputed interest	1
Present value of net minimum lease payments	18
Less current portion	7
Non-current portion	$	11

Schedule of Capital Lease of Lessor [Table Text Block]

The components of the net investment in the capital leases at December 31, 2013, were as follows:

	(In millions)
2014	$	12
2015	12
2016	12
2017	12
2018	12
Thereafter	19
Total minimum future lease receipts	79
Residual value of leased pipeline	40
Less unearned income	(40		)
Net investment in capital lease	79
Less current portion	(5		)
	$	74

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Jointly Owned Utility Plant (Tables)

12 Months Ended

Dec. 31, 2013

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

Schedule of Jointly Owned Utility Plants [Table Text Block]

Ownership information of the two utility plants as of December 31, 2013 was as follows:

	Belle River			Ludington Hydroelectric Pumped Storage
In-service date	1984-1985			1973
Total plant capacity	1,270		MW	1,872		MW
Ownership interest	(a)			49		%
Investment in property, plant and equipment (in millions)	$	1,702		$	354
Accumulated depreciation (in millions)	$	969		$	170

_______________________________________

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

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Financial and Other Derivative Instruments (Netting Offsets Reconciliation to Balance Sheet) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Derivative Asset, Current	$ 99	$ 108
Derivative Assets, Noncurrent	27	39
Derivative Liabilities, Current	(195)	(125)
Derivative Liabilities, Noncurrent	(43)	(26)
Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Current	691	862
Derivative Assets, Noncurrent	142	154
Derivative Liabilities [Member]
Derivative [Line Items]
Derivative Liabilities, Current	(773)	(879)
Derivative Liabilities, Noncurrent	(163)	(141)
Counterparty Netting [Member]
Derivative [Line Items]
Derivative Asset, Current	(566)	(754)
Derivative Assets, Noncurrent	(115)	(115)
Derivative Liabilities, Current	566	754
Derivative Liabilities, Noncurrent	115	115
Collateral Adjustment [Member]
Derivative [Line Items]
Derivative Asset, Current	(26)	0
Derivative Assets, Noncurrent	0	0
Derivative Liabilities, Current	12	0
Derivative Liabilities, Noncurrent	$ 5	$ 0

XML

Income Taxes (Reconciliation of Unrecognized Tax Benefits) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, beginning balance	$ 11	$ 48	$ 28
Additions for tax positions of prior years	0	0	27
Reductions for tax positions of prior years	0	(2)	(4)
Additions for tax positions related to the current year	0	1	1
Settlements	0	(30)	(3)
Lapse of statute of limitations	(1)	(6)	(1)
Unrecognized Tax Benefits, ending balance	$ 10	$ 11	$ 48

XML

Financial and Other Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair value of derivative instruments

The following tables present the fair value of derivative instruments as of December 31, 2013 and 2012:

	December 31, 2013					December 31, 2012
	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	—		$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	—	$	(1	)	$	—	$	—
Commodity Contracts:
Natural Gas	396		(503		)	645		(661		)
Electricity	400		(398		)	360		(351		)
Other	37		(34		)	11		(7		)
Total derivatives not designated as hedging instruments:	$	833	$	(936	)	$	1,016	$	(1,019	)
Total derivatives:
Current	$	691	$	(773	)	$	862	$	(879	)
Noncurrent	142		(163		)	154		(141		)
Total derivatives	$	833	$	(936	)	$	1,016	$	(1,020	)

Netting Offsets of Derivative Assets and Liabilities [Table Text Block]

The following table presents the netting offsets of derivative assets and liabilities at December 31, 2013 and 2012:

	December 31, 2013									December 31, 2012
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position			Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position
	(In millions)
Derivative assets:
Commodity Contracts:
Natural Gas	$	396		$	(382	)	$	14		$	645		$	(605	)	$	40
Electricity	400			(291		)	109			360			(258		)	102
Other	37			(34		)	3			11			(6		)	5
Total derivative assets	$	833		$	(707	)	$	126		$	1,016		$	(869	)	$	147
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(503	)	$	395		$	(108	)	$	(661	)	$	605		$	(56	)
Electricity	(398		)	269			(129		)	(351		)	258			(93		)
Other	(34		)	34			—			(7		)	6			(1		)
Other derivative liabilities	(1		)	—			(1		)	(1		)	—			(1		)
Total derivative liabilities	$	(936	)	$	698		$	(238	)	$	(1,020	)	$	869		$	(151	)

Netting Offsets of Derivative Assets and Liabilities Reconciliation to the Statements of Financial Position [Table Text Block]

The following table presents the netting offsets of derivative assets and liabilities at December 31, 2013 and 2012:

	December 31, 2013												December 31, 2012
	Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent			Current			Noncurrent			Current			Noncurrent
	(In millions)
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	691		$	142		$	(773	)	$	(163	)	$	862		$	154		$	(879	)	$	(141	)
Counterparty netting	(566		)	(115		)	566			115			(754		)	(115		)	754			115
Collateral adjustment	(26		)	—			12			5			—			—			—			—
Total derivatives as reported	$	99		$	27		$	(195	)	$	(43	)	$	108		$	39		$	(125	)	$	(26	)

Gain (Loss) Recognized in Income on Derivative

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

	Location of Gain (Loss) Recognized in Income on Derivatives	Gain (Loss) Recognized in Income on Derivatives for Years Ended December 31
Derivatives not Designated as Hedging Instruments		2013			2012
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	(1	)	$	—
Commodity Contracts:
Natural Gas	Operating Revenue	(48		)	(29		)
Natural Gas	Fuel, purchased power and gas	(44		)	25
Electricity	Operating Revenue	82			64
Other	Operating Revenue	—			5
Total		$	(11	)	$	65

Volume of Commodity Contracts [Table Text Block]

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

Commodity	Number of Units
Natural Gas (MMBtu)	795,553,773
Electricity (MWh)	55,658,483
Foreign Currency Exchange ($ CAD)	65,074,206
FTR (MWh)	10,485,618

XML

Retirement Benefits and Trusteed Assets (Tables)

12 Months Ended

Dec. 31, 2013

Pension Plan, Defined Benefit [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Net Benefit Costs [Table Text Block]

Net pension cost includes the following components:

	2013			2012			2011
	(In millions)
Service cost	$	94		$	82		$	69
Interest cost	192			204			202
Expected return on plan assets	(266		)	(244		)	(246		)
Amortization of:
Net loss	208			176			142
Prior service cost	—			—			3
Special termination benefits	—			2			2
Net pension cost	$	228		$	220		$	172

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

	2013			2012
	(In millions)
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income
Net actuarial (gain) loss	$	(581	)	$	395
Amortization of net actuarial loss	(208		)	(178		)
Total recognized Regulatory assets and Other comprehensive income	$	(789	)	$	217
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	(561	)	$	437
Estimated amounts to be amortized from Regulatory assets and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year
Net actuarial loss	$	151		$	202

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

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:

	2013			2012
	(In millions)
Accumulated benefit obligation, end of year	$	4,068		$	4,349
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	4,729		$	4,195
Service cost	94			82
Interest cost	192			204
Plan amendments	(3		)	—
Actuarial (gain) loss	(400		)	474
Special termination benefits	—			2
Benefits paid	(232		)	(228		)
Projected benefit obligation, end of year	$	4,380		$	4,729
Change in plan assets
Plan assets at fair value, beginning of year	$	3,223		$	2,886
Actual return on plan assets	445			325
Company contributions	284			240
Benefits paid	(232		)	(228		)
Plan assets at fair value, end of year	$	3,720		$	3,223
Funded status of the plans	$	(660	)	$	(1,506	)
Amount recorded as:
Current liabilities	$	(7	)	$	(8	)
Noncurrent liabilities	(653		)	(1,498		)
	$	(660	)	$	(1,506	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	174		$	205
Prior service (credit)	(1		)	(2		)
	$	173		$	203
Amounts recognized in Regulatory assets (see Note 11)
Net actuarial loss	$	1,654		$	2,413
Prior service cost	6			7
	$	1,660		$	2,420

Schedule of Expected Benefit Payments [Table Text Block]

At December 31, 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:

	(In millions)
2014	$	242
2015	250
2016	258
2017	268
2018	280
2019-2023	1,529
	$	2,827

Schedule of Assumptions Used [Table Text Block]

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

	2013		2012		2011
Projected benefit obligation
Discount rate	4.95	%	4.15	%	5.00	%
Rate of compensation increase	4.20	%	4.20	%	4.20	%
Net pension costs
Discount rate	4.15	%	5.00	%	5.50	%
Rate of compensation increase	4.20	%	4.20	%	4.00	%
Expected long-term rate of return on plan assets	8.25	%	8.25	%	8.50	%

Schedule of Allocation of Plan Assets [Table Text Block]

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

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

Pension Plans Fair Value Hierachy Level [Table Text Block]

Fair Value Measurements for pension plan assets at December 31, 2013 and 2012 (a):

	December 31, 2013								December 31, 2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In millions)
Asset Category:
Short-term investments (b)	$	22	$	—	$	—	$	22	$	—	$	24	$	—	$	24
Equity securities
U.S. Large Cap (c)	896		—		—		896		688		44		—		732
U.S. Small/Mid Cap (d)	221		—		—		221		153		5		—		158
Non U.S. (e)	611		130		—		741		530		120		—		650
Fixed income securities (f)	16		921		—		937		87		765		—		852
Hedge Funds and Similar Investments (g)	268		70		395		733		209		80		339		628
Private Equity and Other (h)	—		—		170		170		—		—		179		179
Total	$	2,034	$	1,121	$	565	$	3,720	$	1,667	$	1,038	$	518	$	3,223

_______________________________________

(a) See Note 3 — Fair Value for a description of levels within the fair value hierarchy.

(b) This category predominantly represents certain short-term fixed income securities and money market investments that are managed in separate accounts or commingled funds. Pricing for investments in this category are obtained from quoted prices in actively traded markets or valuations from brokers or pricing services.

(c) This category comprises both actively and not actively managed portfolios that track the S&P 500 low cost equity index funds. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(d) This category represents portfolios of small and medium capitalization domestic equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(e) This category primarily consists of portfolios of non-U.S. developed and emerging market equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(f) This category includes corporate bonds from diversified industries, U.S. Treasuries, and mortgage-backed securities. Pricing for investments in this category is obtained from quoted prices in actively traded markets and quotations from broker or pricing services. Non-exchange traded securities and exchange-traded securities held in commingled funds are classified as Level 2 assets.

(g) This category utilizes a diversified group of strategies that attempt to capture financial market inefficiencies and includes publicly traded debt and equity, publicly traded mutual funds, commingled and limited partnership funds and non-exchange traded securities. Pricing for Level 1 and Level 2 assets in this category is obtained from quoted prices in actively traded markets and quoted prices from broker or pricing services. Non-exchange traded securities held in commingled funds are classified as Level 2 assets. Valuations for some Level 3 assets in this category may be based on limited observable inputs as there may be little, if any, publicly available pricing.

(h) This category includes a diversified group of funds and strategies that primarily invests in private equity partnerships. This category also includes investments in timber and private mezzanine debt. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available pricing. Valuations for assets in this category may be based on discounted cash flow analyses, relevant publicly-traded comparables and comparable transactions.

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

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

	Year Ended December 31, 2013								Year Ended December 31, 2012
	Hedge Funds and Similar Investments		Private Equity and Other			Total			Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1	$	339	$	179		$	518		$	296		$	168		$	464
Total realized/unrealized gains (losses):
Realized gains (losses)	—		18			18			18			(6		)	12
Unrealized gains (losses)	40		(14		)	26			(5		)	12			7
Purchases, sales and settlements:
Purchases	16		15			31			250			33			283
Sales	—		(28		)	(28		)	(220		)	(28		)	(248		)
Ending Balance at December 31	$	395	$	170		$	565		$	339		$	179		$	518
The amount of total gains for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	38	$	3		$	41		$	16		$	6		$	22

Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Net Benefit Costs [Table Text Block]

Net other postretirement cost includes the following components:

	2013			2012			2011
	(In millions)
Service cost	$	47		$	68		$	64
Interest cost	88			120			121
Expected return on plan assets	(110		)	(92		)	(94		)
Amortization of:
Net loss	64			80			55
Prior service credit	(131		)	(27		)	(26		)
Net transition asset	—			2			2
Net other postretirement cost (benefit)	$	(42	)	$	151		$	122

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

	2013			2012
	(In millions)
Other changes in plan assets and APBO recognized in Regulatory assets (liabilities) and Other comprehensive income
Net actuarial gain	$	(353	)	$	(34	)
Amortization of net actuarial loss	(64		)	(80		)
Prior service credit	(218		)	(264		)
Amortization of prior service credit	131			27
Amortization of transition asset	—			(2		)
Total recognized in Regulatory assets (liabilities) and Other comprehensive income	$	(504	)	$	(353	)
Total recognized in net periodic benefit cost, Regulatory assets (liabilities) and Other comprehensive income	$	(546	)	$	(202	)
Estimated amounts to be amortized from Regulatory assets (liabilities) and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year
Net actuarial loss	$	21		$	69
Prior service credit	$	(144	)	$	(91	)

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

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

	2013			2012
	(In millions)
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation, beginning of year	$	2,315		$	2,470
Service cost	47			68
Interest cost	88			120
Plan amendments	(218		)	(264		)
Actuarial (gain) loss	(267		)	5
Medicare Part D subsidy	1			6
Benefits paid	(88		)	(90		)
Accumulated postretirement benefit obligation, end of year	$	1,878		$	2,315
Change in plan assets
Plan assets at fair value, beginning of year	$	1,153		$	985
Actual return on plan assets	196			131
Company contributions	264			140
Benefits paid	(86		)	(103		)
Plan assets at fair value, end of year	$	1,527		$	1,153
Funded status, end of year	$	(351	)	$	(1,162	)
Amount recorded as:
Current liabilities	$	(1	)	$	(2	)
Noncurrent liabilities	(350		)	(1,160		)
	$	(351	)	$	(1,162	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	29		$	40
Prior service credit	(10		)	(14		)
Net transition asset	—			(1		)
	$	19		$	25
Amounts recognized in Regulatory assets (liabilities) (See Note 11)
Net actuarial loss	$	321		$	727
Prior service credit	(393		)	(302		)
Net transition obligation	—			1
	$	(72	)	$	426

Schedule of Expected Benefit Payments [Table Text Block]

At December 31, 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:

	(In millions)
2014	$	103
2015	110
2016	115
2017	123
2018	130
2019 — 2023	724
	$	1,305

Schedule of Assumptions Used [Table Text Block]

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

	2013		2012		2011
Accumulated postretirement benefit obligation
Discount rate	4.95	%	4.15	%	5.00	%
Health care trend rate pre- and post- 65	7.50	/ 6.50%	7.00	%	7.00	%
Ultimate health care trend rate	4.50	%	5.00	%	5.00	%
Year in which ultimate reached pre- and post- 65	2025 / 2024		2021		2020
Other postretirement benefit costs
Discount rate (prior to interim remeasurement)	4.15	%	5.00	%	5.50	%
Discount rate (post interim remeasurement)	4.30	%	N/A		N/A
Expected long-term rate of return on plan assets	8.25	%	8.25	%	8.75	%
Health care trend rate pre- and post- 65	7.00	%	7.00	%	7.00	%
Ultimate health care trend rate	5.00	%	5.00	%	5.00	%
Year in which ultimate reached	2021		2020		2019

Schedule of Allocation of Plan Assets [Table Text Block]

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

U.S. Large Cap Equity Securities	17	%
U.S. Small Cap and Mid Cap Equity Securities	4
Non U.S. Equity Securities	20
Fixed Income Securities	25
Hedge Funds and Similar Investments	20
Private Equity and Other	14
	100	%

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

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

	Year Ended December 31, 2013								Year Ended December 31, 2012
	Hedge Funds and Similar Investments		Private Equity and Other			Total			Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1	$	119	$	86		$	205		$	95		$	60		$	155
Total realized/unrealized gains (losses):
Realized gains (losses)	—		2			2			6			(11		)	(5		)
Unrealized gains	14		7			21			—			14			14
Purchases, sales and settlements:
Purchases	26		15			41			86			36			122
Sales	—		(9		)	(9		)	(68		)	(13		)	(81		)
Ending Balance at December 31	$	159	$	101		$	260		$	119		$	86		$	205
The amount of total gains for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	14	$	9		$	23		$	6		$	2		$	8

Other Postretirement Benefit Plans Hierachy Level [Table Text Block]

Fair Value Measurements for other postretirement benefit plan assets at December 31, 2013 and 2012 (a):

	December 31, 2013								December 31, 2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Asset Category:	(In millions)
Short-term investments (b)	$	5	$	—	$	—	$	5	$	1	$	2	$	—	$	3
Equity securities:
U.S. Large Cap (c)	302		—		—		302		189		3		—		192
U.S. Small/Mid Cap (d)	147		—		—		147		105		—		—		105
Non U.S. (e)	282		9		—		291		230		7		—		237
Fixed income securities (f)	17		350		—		367		38		247		—		285
Hedge Funds and Similar Investments (g)	130		25		159		314		102		24		119		245
Private Equity and Other (h)	—		—		101		101		—		—		86		86
Total	$	883	$	384	$	260	$	1,527	$	665	$	283	$	205	$	1,153

_______________________________________

(a) See Note 3 — Fair Value for a description of levels within the fair value hierarchy.

(b) This category predominantly represents certain short-term fixed income securities and money market investments that are managed in separate accounts or commingled funds. Pricing for investments in this category are obtained from quoted prices in actively traded markets or valuations from brokers or pricing services.

(c) This category comprises both actively and not actively managed portfolios that track the S&P 500 low cost equity index funds. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(d) This category represents portfolios of small and medium capitalization domestic equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(e) This category primarily consists of portfolios of non-U.S. developed and emerging market equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(f) This category includes corporate bonds from diversified industries, U.S. Treasuries, bank loans and mortgage backed securities. Pricing for investments in this category is obtained from quoted prices in actively traded markets and quotations from broker or pricing services. Non-exchange traded securities and exchange-traded securities held in commingled funds are classified as Level 2 assets.

(g) This category utilizes a diversified group of strategies that attempt to capture financial market inefficiencies and includes publicly traded debt and equity, publicly traded mutual funds, commingled and limited partnership funds and non-exchange traded securities. Pricing for Level 1 and Level 2 assets in this category is obtained from quoted prices in actively traded markets and quoted prices from broker or pricing services. Non-exchange traded securities held in commingled funds are classified as Level 2 assets. Valuations for some Level 3 assets in this category may be based on limited observable inputs as there may be little, if any, publicly available pricing.

(h) This category includes a diversified group of funds and strategies that primarily invests in private equity partnerships. This category also includes investments in timber and private mezzanine debt. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available pricing. Valuations for assets in this category may be based on discounted cash flow analyses, relevant publicly-traded comparables and comparable transactions.

XML

Fair Value (Unobservable Inputs related to Level 3 Assets and Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013 MMBTU	Dec. 31, 2012 MMBTU
Fair Value, Inputs, Level 3 [Member] | Natural Gas Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Weighted Average Forward Basis Price	(0.16)	0.03
Fair Value, Inputs, Level 3 [Member] | Electricity Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Weighted Average Forward Basis Price	3	3
Fair Value, Measurements, Recurring [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Assets	$ 126	$ 147
Derivative Liabilities	(238)	(151)
Fair Value, Measurements, Recurring [Member] | Natural Gas Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Assets	14	40
Derivative Liabilities	(108)	(56)
Fair Value, Measurements, Recurring [Member] | Electricity Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Assets	109	102
Derivative Liabilities	(129)	(93)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Assets	176	160
Derivative Liabilities	(212)	(173)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Assets	34	24
Derivative Liabilities	(86)	(62)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Electricity Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Assets	139	134
Derivative Liabilities	$ (126)	$ (111)
Minimum [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Weighted Average Range for Unobservable Inputs	(0.88)	(0.63)
Minimum [Member] | Fair Value, Inputs, Level 3 [Member] | Electricity Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Weighted Average Range for Unobservable Inputs	(7)	(2)
Maximum [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Weighted Average Range for Unobservable Inputs	5.07	1.95
Maximum [Member] | Fair Value, Inputs, Level 3 [Member] | Electricity Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Weighted Average Range for Unobservable Inputs	15	16

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Capital and Operating (Components of the Net Investment in the Capital Leases) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Capital Leases of Lessor [Abstract]
Capital Leases, Future Minimum Payments Receivable, Next Twelve Months	$ 12
Capital Leases, Future Minimum Payments, Receivable in Two Years	12
Capital Leases, Future Minimum Payments, Receivable in Three Years	12
Capital Leases, Future Minimum Payments, Receivable in Four Years	12
Capital Leases, Future Minimum Payments, Receivable in Five Years	12
Capital Leases, Future Minimum Payments, Receivable Due Thereafter	19
Capital Leases, Future Minimum Payments Receivable, Total	79
Capital Leases, Residual value of leased pipeline	40
Capital Leases, Less unearned income	(40)
Net Investment in Capital lease	79
Capital Leases, Less current portion	(5)
Capital Leases, Lessor Balance Sheet, Net Investment in Direct Financing Leases, Noncurrent	$ 74

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Significant Accounting Policies (Intangible Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Finite-Lived Intangible Assets [Line Items]
Intangible Assets, Gross	$ 179	$ 189
Less: Accumulated Amortization	45	34
Intangible Assets, Net	134	155
Less current intangible assets	12	20
Finite-Lived Intangible Assets, Net	122	135
Emission Allowances [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible Assets, Gross	2	6
Renewable Energy Credits [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible Assets, Gross	51	44
Contract Intangible Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible Assets, Gross	$ 126	$ 139

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2013

Long-term Debt, Unclassified [Abstract]

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

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

	2013			2012
	(In millions)
Mortgage bonds, notes, and other
DTE Energy Debt, Unsecured
6.1% due 2014 to 2033	$	1,297		$	1,298
DTE Electric Taxable Debt, Principally Secured
4.7% due 2014 to 2043	4,286			3,777
DTE Electric Tax-Exempt Revenue Bonds (b)
5.1% due 2014 to 2036	558			707
DTE Gas Taxable Debt, Principally Secured
5.6% due 2014 to 2042	1,029			919
Other Long-Term Debt, Including Non-Recourse Debt	142			153
	7,312			6,854
Less amount due within one year	(694		)	(634		)
	$	6,618		$	6,220
Securitization bonds
6.6% due 2015	$	302		$	479
Less amount due within one year	(197		)	(177		)
	$	105		$	302
Junior Subordinated Debentures
6.5% due 2061	$	280		$	280
5.25% due 2062	200			200
	$	480		$	480

_______________________________________

(a) Weighted average interest rates as of December 31, 2013 are shown below the description of each category of debt.

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

Schedule of Issued Debt [Table Text Block]

In 2013, the following debt was issued:

Company	Month Issued	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March	Mortgage Bonds (a)	4.00	%	2043	$	375
DTE Electric	August	Mortgage Bonds (a)	3.65	%	2024	400
DTE Energy	November	Senior Notes (a)	3.85	%	2023	300
DTE Gas	December	Mortgage Bonds (a)	3.64	%	2023	50
DTE Gas	December	Mortgage Bonds (a)	3.74	%	2025	70
DTE Gas	December	Mortgage Bonds (a)	3.94	%	2028	50
						$	1,245

_______________________________________

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

Schedule of Extinguishment of Debt [Table Text Block]

In 2013, the following debt was redeemed:

Company	Month	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March	Securitization Bonds	6.42	%	2013	$	88
DTE Electric	March	Tax Exempt Revenue Bonds (a)	5.30	%	2030	51
DTE Electric	April	Other Long-Term Debt	Various		2013	13
DTE Gas	April	Senior Notes	5.26	%	2013	60
DTE Energy	June	Senior Notes	Variable		2013	300
DTE Electric	September	Securitization Bonds	6.62	%	2013	89
DTE Electric	September	Senior Notes	6.40	%	2013	250
DTE Electric	December	Tax Exempt Revenue Bonds (a)	5.50	%	2030	49
DTE Electric	December	Tax Exempt Revenue Bonds (a)	6.75	%	2038	50
DTE Energy	Various	Other Long-Term Debt	Various		2013	11
						$	961

_______________________________________

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

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

The following table shows the scheduled debt maturities:

	2014		2015		2016		2017		2018		2019 and Thereafter		Total
	(In millions)
Amount to mature	$	891	$	476	$	465	$	9	$	407	$	5,846	$	8,094

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Organization and Basis of Presentation (Notes)

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

ORGANIZATION AND BASIS OF PRESENTATION

Corporate Structure

DTE Energy owns the following businesses:

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

• DTE Gas, a natural gas utility engaged in the purchase, storage, transportation, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan and the sale of storage and transportation capacity; and

• Other businesses involved in 1) natural gas pipelines, gathering and storage; 2) power and industrial projects; and 3) energy marketing and trading operations.

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

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

Basis of Presentation

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

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

Principles of Consolidation

The Company consolidates all majority-owned subsidiaries and investments in entities in which it has controlling influence. Non-majority owned investments are accounted for using the equity method when the Company is able to influence the operating policies of the investee. 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. 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 and are consolidated when the Company is the primary beneficiary. In addition, 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, 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, 2013 and 2012. All assets and liabilities of a consolidated VIE are presented where it has been determined that 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. VIEs, in which the Company holds a majority voting interest and is the primary beneficiary, that meet the definition of a business and whose assets can be used for purposes other than the settlement of the VIE's obligations have been excluded from the table below.

	December 31, 2013						December 31, 2012
	Securitization		Other		Total		Securitization		Other		Total
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	12	$	12	$	—	$	10	$	10
Restricted cash	100		8		108		102		7		109
Accounts receivable	34		16		50		34		7		41
Inventories	—		118		118		—		141		141
Other current assets	—		1		1		—		1		1
Property, plant and equipment	—		99		99		—		93		93
Securitized regulatory assets	231		—		231		413		—		413
Other assets	4		8		12		7		11		18
	$	369	$	262	$	631	$	556	$	270	$	826
LIABILITIES
Accounts payable and accrued current liabilities	$	7	$	23	$	30	$	11	$	14	$	25
Current portion long-term debt, including capital leases	196		9		205		177		8		185
Current regulatory liabilities	43		—		43		50		—		50
Other current liabilities	—		4		4		—		4		4
Mortgage bonds, notes and other	—		21		21		—		25		25
Securitization bonds	105		—		105		302		—		302
Capital lease obligations	—		7		7		—		11		11
Other long-term liabilities	8		2		10		7		2		9
	$	359	$	66	$	425	$	547	$	64	$	611

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

	December 31, 2013		December 31, 2012
	(In millions)
Other investments	$	141	$	130
Notes receivable	$	8	$	6

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Stock-Based Compensation (Unrecognized Compensation Costs) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Share Based Compensation Unrecognized and Non-Vested Cost [Line Items]
Unrecognized Compensation Cost	$ 55
Weighted Average to be Recognized	11 months 5 days
Restricted Stock [Member]
Share Based Compensation Unrecognized and Non-Vested Cost [Line Items]
Unrecognized Compensation Cost	10
Weighted Average to be Recognized	11 months 5 days
Performance Shares [Member]
Share Based Compensation Unrecognized and Non-Vested Cost [Line Items]
Unrecognized Compensation Cost	$ 45
Weighted Average to be Recognized	11 months 5 days

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Retirement Benefits and Trusteed Assets (Pension Plan - Other Changes in Plan Assets and Benefit Obligations recognized in Reg Assets and OCI) (Details) (Pension Plan, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ (581)	$ 395
Amortization of net actuarial loss	(208)	(178)
Total recognized Regulatory assets and Other comprehensive income	(789)	217
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	(561)	437
Future amortization of net actuarial loss into net periodic benefit cost	$ 151	$ 202

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Significant Accounting Policies (Future Amortization Expense Intangible Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	$ 13
Finite-Lived Intangible Assets, Amortization Expense, Year Two	12
Finite-Lived Intangible Assets, Amortization Expense, Year Three	11
Finite-Lived Intangible Assets, Amortization Expense, Year Four	8
Finite-Lived Intangible Assets, Amortization Expense, Year Five	$ 8

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Retirement Benefits and Trusteed Assets (OPEB - Target Allocations of Plan Assets) (Details) (Other Postretirement Benefit Plan, Defined Benefit [Member])	12 Months Ended
	Dec. 31, 2013
Other Postretirement Benefits Target Allocations of Plan Assets [Line Items]
Target Allocation Percentage of Assets	1
US Large Cap Equity Securities [Member]
Other Postretirement Benefits Target Allocations of Plan Assets [Line Items]
Target Allocation Percentage of Assets	0.17
US Small Cap and Mid Cap Equity Securities [Member]
Other Postretirement Benefits Target Allocations of Plan Assets [Line Items]
Target Allocation Percentage of Assets	0.04
Non US Equity Securities [Member]
Other Postretirement Benefits Target Allocations of Plan Assets [Line Items]
Target Allocation Percentage of Assets	0.2
Fixed Income Securities [Member]
Other Postretirement Benefits Target Allocations of Plan Assets [Line Items]
Target Allocation Percentage of Assets	0.25
Hedge Funds and Similar Investments [Member]
Other Postretirement Benefits Target Allocations of Plan Assets [Line Items]
Target Allocation Percentage of Assets	0.2
Private Equity and Other [Member]
Other Postretirement Benefits Target Allocations of Plan Assets [Line Items]
Target Allocation Percentage of Assets	0.14

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Stock Based-Compensation (Stock Awards Activity Rollforward) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forfeitures	(10,370)
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding, Number	597,648
Grants	127,785	167,320	381,840
Forfeitures	(7,155)
Vested and Issued	(225,949)
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding, Number	492,329	597,648
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 48.33
Weighted Average Grant Date Fair Value Per Share - Grants	$ 64.72	$ 53.71	$ 47.98
Weighted Average Grant Date Fair Value Per Share - Foreitures	$ 54.61
Weighted Average Grant Date Fair Value Per Share - Vested and issued	$ 45.54
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 53.76	$ 48.33

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

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

A reconciliation of the asset retirement obligations for 2013 follows:

	(In millions)
Asset retirement obligations at December 31, 2012	$	1,719
Accretion	106
Liabilities incurred	5
Liabilities settled	(13		)
Revision in estimated cash flows	10
Asset retirement obligations at December 31, 2013	$	1,827

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Stock-Based Compensation (Notes)

12 Months Ended

Dec. 31, 2013

Share-based Compensation [Abstract]

Stock-based Compensation

STOCK-BASED COMPENSATION

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

• Authorized limit is 11,500,000 shares of common stock;

• Prohibits the grant of a stock option with an exercise price that is less than the fair market value of the Company’s stock on the date of the grant; and

• Imposes the following award limits to a single participant in a single calendar year, (1) options for more than 500,000 shares of common stock; (2) stock awards for more than 150,000 shares of common stock; (3) performance share awards for more than 300,000 shares of common stock (based on the maximum payout under the award); or (4) more than 1,000,000 performance units, which have a face amount of $1.00 each.

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

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

	2013		2012		2011
	(In millions)
Stock-based compensation expense	$	99	$	83	$	66
Tax benefit	38		33		25
Stock-based compensation cost capitalized in property, plant and equipment	15		5		4

Stock Options

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

Stock option activity was as follows:

	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In millions)
Options outstanding at December 31, 2012	1,192,670		$	41.86
Granted	—		$	—
Exercised	(458,603	)	$	40.71
Forfeited or expired	(10,370	)	$	41.46
Options outstanding and exercisable at December 31, 2013	723,697		$	42.60	$	18

As of December 31, 2013, the weighted average remaining contractual life for the exercisable shares is 3.83 years. As of December 31, 2013, all options were vested. During 2013, 200,844 options vested.

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

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

						Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)
					Number of Options
Range of Exercise Prices
$	27.00	—	$	38.00	67,257	$	28.30	5.15
$	38.01	—	$	42.00	167,447	$	41.23	3.21
$	42.01	—	$	45.00	351,893	$	44.02	4.16
$	45.01	—	$	50.00	137,100	$	47.67	3.08
					723,697	$	42.60	3.83

Restricted Stock Awards

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

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

Stock award activity for the years ended December 31 was:

	2013		2012		2011
Fair value of awards vested (in millions)	$	8	$	9	$	13
Restricted common shares awarded	127,785		167,320		381,840
Weighted average market price of shares awarded	$	64.72	$	53.71	$	47.98
Compensation cost charged against income (in millions)	$	23	$	12	$	12

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

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at December 31, 2012	597,648		$	48.33
Grants	127,785		$	64.72
Forfeitures	(7,155	)	$	54.61
Vested and issued	(225,949	)	$	45.54
Balance at December 31, 2013	492,329		$	53.76

Performance Share Awards

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

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

	2013		2012		2011
	(In millions)
Compensation expense	$	77	$	71	$	53
Cash settlements (a)	$	9	$	4	$	3
Stock settlements (a)	$	56	$	41	$	25

_______________________________________

(a) Sum of cash and stock settlements approximates the intrinsic value of the liability.

During the vesting period, the recipient of a performance share award has no shareholder rights. 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 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, 2013:

	Performance Shares
Balance at December 31, 2012	1,634,364
Grants	564,561
Forfeitures	(41,512	)
Payouts	(548,624	)
Balance at December 31, 2013	1,608,789

Unrecognized Compensation Costs

As of December 31, 2013, there was $55 million of total unrecognized compensation cost related to non-vested stock-based compensation arrangements. That cost is expected to be recognized over a weighted-average period of 0.93 years.

	Unrecognized Compensation Cost		Weighted Average to be Recognized
	(In millions)		(In years)
Stock awards	$	10	0.93
Performance shares	45		0.93
	$	55	0.93

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Retirement Benefits and Trusteed Assets (Notes)

12 Months Ended

Dec. 31, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Retirement Benefits and Trusteed Assets

RETIREMENT BENEFITS AND TRUSTEED ASSETS

Pension Plan Benefits

The Company has qualified defined benefit retirement plans for eligible represented and non-represented employees. The plans are noncontributory and cover 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 a defined benefit retirement plan. In its place, the Company will annually contribute an amount equivalent to 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 and additional amounts when it deems appropriate. The Company contributed $277 million to its qualified pension plans in 2013. At the discretion of management, and depending upon financial market conditions, we anticipate making up to $345 million in contributions to the pension plans in 2014.

Net pension cost includes the following components:

	2013			2012			2011
	(In millions)
Service cost	$	94		$	82		$	69
Interest cost	192			204			202
Expected return on plan assets	(266		)	(244		)	(246		)
Amortization of:
Net loss	208			176			142
Prior service cost	—			—			3
Special termination benefits	—			2			2
Net pension cost	$	228		$	220		$	172

	2013			2012
	(In millions)
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income
Net actuarial (gain) loss	$	(581	)	$	395
Amortization of net actuarial loss	(208		)	(178		)
Total recognized Regulatory assets and Other comprehensive income	$	(789	)	$	217
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	(561	)	$	437
Estimated amounts to be amortized from Regulatory assets and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year
Net actuarial loss	$	151		$	202

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:

	2013			2012
	(In millions)
Accumulated benefit obligation, end of year	$	4,068		$	4,349
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	4,729		$	4,195
Service cost	94			82
Interest cost	192			204
Plan amendments	(3		)	—
Actuarial (gain) loss	(400		)	474
Special termination benefits	—			2
Benefits paid	(232		)	(228		)
Projected benefit obligation, end of year	$	4,380		$	4,729
Change in plan assets
Plan assets at fair value, beginning of year	$	3,223		$	2,886
Actual return on plan assets	445			325
Company contributions	284			240
Benefits paid	(232		)	(228		)
Plan assets at fair value, end of year	$	3,720		$	3,223
Funded status of the plans	$	(660	)	$	(1,506	)
Amount recorded as:
Current liabilities	$	(7	)	$	(8	)
Noncurrent liabilities	(653		)	(1,498		)
	$	(660	)	$	(1,506	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	174		$	205
Prior service (credit)	(1		)	(2		)
	$	173		$	203
Amounts recognized in Regulatory assets (see Note 11)
Net actuarial loss	$	1,654		$	2,413
Prior service cost	6			7
	$	1,660		$	2,420

At December 31, 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:

	(In millions)
2014	$	242
2015	250
2016	258
2017	268
2018	280
2019-2023	1,529
	$	2,827

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

	2013		2012		2011
Projected benefit obligation
Discount rate	4.95	%	4.15	%	5.00	%
Rate of compensation increase	4.20	%	4.20	%	4.20	%
Net pension costs
Discount rate	4.15	%	5.00	%	5.50	%
Rate of compensation increase	4.20	%	4.20	%	4.00	%
Expected long-term rate of return on plan assets	8.25	%	8.25	%	8.50	%

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 stocks, and large and small market capitalizations. Fixed income securities generally include 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 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, 2013 are listed below:

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

Fair Value Measurements for pension plan assets at December 31, 2013 and 2012 (a):

	December 31, 2013								December 31, 2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In millions)
Asset Category:
Short-term investments (b)	$	22	$	—	$	—	$	22	$	—	$	24	$	—	$	24
Equity securities
U.S. Large Cap (c)	896		—		—		896		688		44		—		732
U.S. Small/Mid Cap (d)	221		—		—		221		153		5		—		158
Non U.S. (e)	611		130		—		741		530		120		—		650
Fixed income securities (f)	16		921		—		937		87		765		—		852
Hedge Funds and Similar Investments (g)	268		70		395		733		209		80		339		628
Private Equity and Other (h)	—		—		170		170		—		—		179		179
Total	$	2,034	$	1,121	$	565	$	3,720	$	1,667	$	1,038	$	518	$	3,223

_______________________________________

(a) See Note 3 — Fair Value for a description of levels within the fair value hierarchy.

(b) This category predominantly represents certain short-term fixed income securities and money market investments that are managed in separate accounts or commingled funds. Pricing for investments in this category are obtained from quoted prices in actively traded markets or valuations from brokers or pricing services.

(c) This category comprises both actively and not actively managed portfolios that track the S&P 500 low cost equity index funds. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(d) This category represents portfolios of small and medium capitalization domestic equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(e) This category primarily consists of portfolios of non-U.S. developed and emerging market equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(f) This category includes corporate bonds from diversified industries, U.S. Treasuries, and mortgage-backed securities. Pricing for investments in this category is obtained from quoted prices in actively traded markets and quotations from broker or pricing services. Non-exchange traded securities and exchange-traded securities held in commingled funds are classified as Level 2 assets.

(g) This category utilizes a diversified group of strategies that attempt to capture financial market inefficiencies and includes publicly traded debt and equity, publicly traded mutual funds, commingled and limited partnership funds and non-exchange traded securities. Pricing for Level 1 and Level 2 assets in this category is obtained from quoted prices in actively traded markets and quoted prices from broker or pricing services. Non-exchange traded securities held in commingled funds are classified as Level 2 assets. Valuations for some Level 3 assets in this category may be based on limited observable inputs as there may be little, if any, publicly available pricing.

(h) This category includes a diversified group of funds and strategies that primarily invests in private equity partnerships. This category also includes investments in timber and private mezzanine debt. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available pricing. Valuations for assets in this category may be based on discounted cash flow analyses, relevant publicly-traded comparables and comparable transactions.

The pension trust holds debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices in actively traded markets. The commingled funds and institutional mutual funds hold exchange-traded equity or debt securities and are valued based on 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 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.

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

	Year Ended December 31, 2013								Year Ended December 31, 2012
	Hedge Funds and Similar Investments		Private Equity and Other			Total			Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1	$	339	$	179		$	518		$	296		$	168		$	464
Total realized/unrealized gains (losses):
Realized gains (losses)	—		18			18			18			(6		)	12
Unrealized gains (losses)	40		(14		)	26			(5		)	12			7
Purchases, sales and settlements:
Purchases	16		15			31			250			33			283
Sales	—		(28		)	(28		)	(220		)	(28		)	(248		)
Ending Balance at December 31	$	395	$	170		$	565		$	339		$	179		$	518
The amount of total gains for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	38	$	3		$	41		$	16		$	6		$	22

There were no transfers between Level 3 and Level 2 and there were no significant transfers between Level 2 and Level 1 in the years ended December 31, 2013 and 2012.

Other Postretirement Benefits

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 $264 million to its other postretirement medical and life insurance benefit plans during 2013. At the discretion of management, we anticipate making up to $145 million of contributions to the VEBA trusts in 2014.

Starting in 2012, in lieu of offering future employees post-employment health care and life insurance benefits, the Company allocates a fixed amount per year to an account in a tax-exempt trust for each employee. These trusts are managed either by the Company (for non-represented and certain represented groups), or by the Utility Workers of America (UWUA) for Local 223 employees. The cost of these plans was $2 million in 2013 and less than $1 million in 2012.

Beginning in 2013, the Company replaced sponsored retiree medical, prescription drug and dental coverage 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; as well as future Medicare eligible represented retirees, spouses, surviving spouses or same sex domestic partners. The 2013 RHCA allowance ranged between $3,250 and $3,500 depending on an employee’s date of hire and will increase each year at the lower of the rate of medical inflation or 2%.

Net other postretirement cost includes the following components:

	2013			2012			2011
	(In millions)
Service cost	$	47		$	68		$	64
Interest cost	88			120			121
Expected return on plan assets	(110		)	(92		)	(94		)
Amortization of:
Net loss	64			80			55
Prior service credit	(131		)	(27		)	(26		)
Net transition asset	—			2			2
Net other postretirement cost (benefit)	$	(42	)	$	151		$	122

	2013			2012
	(In millions)
Other changes in plan assets and APBO recognized in Regulatory assets (liabilities) and Other comprehensive income
Net actuarial gain	$	(353	)	$	(34	)
Amortization of net actuarial loss	(64		)	(80		)
Prior service credit	(218		)	(264		)
Amortization of prior service credit	131			27
Amortization of transition asset	—			(2		)
Total recognized in Regulatory assets (liabilities) and Other comprehensive income	$	(504	)	$	(353	)
Total recognized in net periodic benefit cost, Regulatory assets (liabilities) and Other comprehensive income	$	(546	)	$	(202	)
Estimated amounts to be amortized from Regulatory assets (liabilities) and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year
Net actuarial loss	$	21		$	69
Prior service credit	$	(144	)	$	(91	)

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

	2013			2012
	(In millions)
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation, beginning of year	$	2,315		$	2,470
Service cost	47			68
Interest cost	88			120
Plan amendments	(218		)	(264		)
Actuarial (gain) loss	(267		)	5
Medicare Part D subsidy	1			6
Benefits paid	(88		)	(90		)
Accumulated postretirement benefit obligation, end of year	$	1,878		$	2,315
Change in plan assets
Plan assets at fair value, beginning of year	$	1,153		$	985
Actual return on plan assets	196			131
Company contributions	264			140
Benefits paid	(86		)	(103		)
Plan assets at fair value, end of year	$	1,527		$	1,153
Funded status, end of year	$	(351	)	$	(1,162	)
Amount recorded as:
Current liabilities	$	(1	)	$	(2	)
Noncurrent liabilities	(350		)	(1,160		)
	$	(351	)	$	(1,162	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	29		$	40
Prior service credit	(10		)	(14		)
Net transition asset	—			(1		)
	$	19		$	25
Amounts recognized in Regulatory assets (liabilities) (See Note 11)
Net actuarial loss	$	321		$	727
Prior service credit	(393		)	(302		)
Net transition obligation	—			1
	$	(72	)	$	426

At December 31, 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:

	(In millions)
2014	$	103
2015	110
2016	115
2017	123
2018	130
2019 — 2023	724
	$	1,305

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

	2013		2012		2011
Accumulated postretirement benefit obligation
Discount rate	4.95	%	4.15	%	5.00	%
Health care trend rate pre- and post- 65	7.50	/ 6.50%	7.00	%	7.00	%
Ultimate health care trend rate	4.50	%	5.00	%	5.00	%
Year in which ultimate reached pre- and post- 65	2025 / 2024		2021		2020
Other postretirement benefit costs
Discount rate (prior to interim remeasurement)	4.15	%	5.00	%	5.50	%
Discount rate (post interim remeasurement)	4.30	%	N/A		N/A
Expected long-term rate of return on plan assets	8.25	%	8.25	%	8.75	%
Health care trend rate pre- and post- 65	7.00	%	7.00	%	7.00	%
Ultimate health care trend rate	5.00	%	5.00	%	5.00	%
Year in which ultimate reached	2021		2020		2019

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 $9 million in 2013 and increased the accumulated benefit obligation by $124 million at December 31, 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 $8 million in 2013 and would have decreased the accumulated benefit obligation by $108 million at December 31, 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, 2013 are listed below:

U.S. Large Cap Equity Securities	17	%
U.S. Small Cap and Mid Cap Equity Securities	4
Non U.S. Equity Securities	20
Fixed Income Securities	25
Hedge Funds and Similar Investments	20
Private Equity and Other	14
	100	%

Fair Value Measurements for other postretirement benefit plan assets at December 31, 2013 and 2012 (a):

	December 31, 2013								December 31, 2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Asset Category:	(In millions)
Short-term investments (b)	$	5	$	—	$	—	$	5	$	1	$	2	$	—	$	3
Equity securities:
U.S. Large Cap (c)	302		—		—		302		189		3		—		192
U.S. Small/Mid Cap (d)	147		—		—		147		105		—		—		105
Non U.S. (e)	282		9		—		291		230		7		—		237
Fixed income securities (f)	17		350		—		367		38		247		—		285
Hedge Funds and Similar Investments (g)	130		25		159		314		102		24		119		245
Private Equity and Other (h)	—		—		101		101		—		—		86		86
Total	$	883	$	384	$	260	$	1,527	$	665	$	283	$	205	$	1,153

_______________________________________

(a) See Note 3 — Fair Value for a description of levels within the fair value hierarchy.

(b) This category predominantly represents certain short-term fixed income securities and money market investments that are managed in separate accounts or commingled funds. Pricing for investments in this category are obtained from quoted prices in actively traded markets or valuations from brokers or pricing services.

(c) This category comprises both actively and not actively managed portfolios that track the S&P 500 low cost equity index funds. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(d) This category represents portfolios of small and medium capitalization domestic equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(e) This category primarily consists of portfolios of non-U.S. developed and emerging market equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets.

(f) This category includes corporate bonds from diversified industries, U.S. Treasuries, bank loans and mortgage backed securities. Pricing for investments in this category is obtained from quoted prices in actively traded markets and quotations from broker or pricing services. Non-exchange traded securities and exchange-traded securities held in commingled funds are classified as Level 2 assets.

(g) This category utilizes a diversified group of strategies that attempt to capture financial market inefficiencies and includes publicly traded debt and equity, publicly traded mutual funds, commingled and limited partnership funds and non-exchange traded securities. Pricing for Level 1 and Level 2 assets in this category is obtained from quoted prices in actively traded markets and quoted prices from broker or pricing services. Non-exchange traded securities held in commingled funds are classified as Level 2 assets. Valuations for some Level 3 assets in this category may be based on limited observable inputs as there may be little, if any, publicly available pricing.

(h) This category includes a diversified group of funds and strategies that primarily invests in private equity partnerships. This category also includes investments in timber and private mezzanine debt. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available pricing. Valuations for assets in this category may be based on discounted cash flow analyses, relevant publicly-traded comparables and comparable transactions.

The VEBA trusts hold debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices in actively traded markets. The commingled funds and institutional mutual funds hold exchange-traded equity or debt securities and are valued based on 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):

	Year Ended December 31, 2013								Year Ended December 31, 2012
	Hedge Funds and Similar Investments		Private Equity and Other			Total			Hedge Funds and Similar Investments			Private Equity and Other			Total
	(In millions)
Beginning Balance at January 1	$	119	$	86		$	205		$	95		$	60		$	155
Total realized/unrealized gains (losses):
Realized gains (losses)	—		2			2			6			(11		)	(5		)
Unrealized gains	14		7			21			—			14			14
Purchases, sales and settlements:
Purchases	26		15			41			86			36			122
Sales	—		(9		)	(9		)	(68		)	(13		)	(81		)
Ending Balance at December 31	$	159	$	101		$	260		$	119		$	86		$	205
The amount of total gains for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period	$	14	$	9		$	23		$	6		$	2		$	8

There were no transfers between Level 3 and Level 2 and there were no significant transfers between Level 2 and Level 1 in the years ended December 31, 2013 and 2012.

Interim Re-Measurement of Other Postretirement Benefit Obligation

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 benefit changes resulting from the new labor contracts.

Healthcare Legislation

In December 2003, the Medicare Act was signed into law which provides for a non-taxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least “actuarially equivalent” to the benefit established by law. The effects of the subsidy reduced net periodic other postretirement benefit costs by $1 million in 2013, $6 million in 2012 and $6 million in 2011.

Grantor Trust

DTE Gas maintains a Grantor Trust to fund other postretirement benefit obligations that invests in life insurance contracts and income securities. Employees and retirees have no right, title or interest in the assets of the Grantor Trust, and DTE Gas can revoke the trust subject to providing the MPSC with prior notification. The Company accounts for its investment at fair value, approximately $17 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.

Defined Contribution Plans

The Company also sponsors defined contribution retirement savings plans. Participation in one of these plans is available to substantially all represented and non-represented employees. The Company matches employee contributions up to certain predefined limits based upon eligible compensation, the employee’s contribution rate and, in some cases, years of credited service. The cost of these plans was $41 million, $37 million, and $35 million in each of the years 2013, 2012, and 2011, respectively.

XML

Common Stock (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Class of Stock [Line Items]
Maximum Total Funded Debt to Total Capitalization Ratio	0.65
Line of Credit Facility, Dividend Restrictions	166
Retained Earnings (Accumulated Deficit)	$ 4,150	$ 3,944
Other Restrictions on Payment of Dividends	0

XML

Valuation and Qualifying Accounts (Tables)

12 Months Ended

Dec. 31, 2013

Valuation and Qualifying Accounts [Abstract]

Summary of Valuation Allowance [Table Text Block]

Valuation and Qualifying Accounts

	Year Ending December 31,
	2013			2012			2011
	(In millions)
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statements of Financial Position)
Balance at Beginning of Period	$	62		$	162		$	196
Additions:
Charged to costs and expenses	94			79			94
Charged to other accounts (a)	23			16			18
Deductions (b)	(124		)	(195		)	(146		)
Balance at End of Period	$	55		$	62		$	162

XML

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets [Table Text Block]

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

	2013			2012
	(In millions)
Assets
Recoverable pension and other postretirement costs:
Pension	$	1,660		$	2,420
Other postretirement costs	—			426
Asset retirement obligation	394			424
Recoverable Michigan income taxes	286			304
Recoverable income taxes related to securitized regulatory assets	126			226
Cost to achieve Performance Excellence Process	75			96
Other recoverable income taxes	71			76
Unamortized loss on reacquired debt	63			63
Deferred environmental costs	59			58
Enterprise Business Systems costs	13			16
Recoverable revenue decoupling	9			28
Choice incentive mechanism	3			66
Accrued PSCR/GCR revenue	—			87
Recoverable restoration expense	—			49
Other	104			78
	2,863			4,417
Less amount included in current assets	(26		)	(182		)
	$	2,837		$	4,235
Securitized regulatory assets	$	231		$	413

Schedule of Regulatory Liabilities [Table Text Block]

	2013			2012
	(In millions)
Liabilities
Asset removal costs	$	351		$	439
Renewable energy	277			230
Refundable revenue decoupling/deferred gain	127			127
Negative pension offset	84			105
Over recovery of Securitization	72			54
Refundable other postretirement costs	72			—
Accrued PSCR/GCR	65			16
Refundable income taxes	45			56
Energy optimization	31			34
Fermi 2 refueling outage	26			12
Refundable uncollectible expense	12			37
Other	2			10
	$	1,164		$	1,120
Less amount included current liabilities	(302		)	(89		)
	$	862		$	1,031

XML

Segment Information (Notes)

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Segment Information

SEGMENT AND RELATED INFORMATION

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

Electric segment consists principally of DTE Electric, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million residential, commercial and industrial customers in southeastern Michigan.

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

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

Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers; produce reduced emissions fuel (REF) and sell electricity from biomass-fired energy projects.

Energy Trading consists of energy marketing and trading operations.

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

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

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

	2013			2012			2011
	(In millions)
Electric	$	26		$	29		$	33
Gas	4			4			2
Gas Storage and Pipelines	3			6			8
Power and Industrial Projects	816			801			238
Energy Trading	43			43			70
Corporate and Other	(24		)	(37		)	(50		)
Discontinued Operations	—			2			—
	$	868		$	848		$	301

Financial data of the business segments follows:

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures
	(In millions)
2013
Electric	$	5,199		$	902	$	(1	)	$	268		$	252		$	484		$	17,508		$	1,208	$	1,325
Gas	1,474			95		(7		)	58			77			143			3,938			743		209
Gas Storage and Pipelines	132			23		(7		)	18			45			70			824			24		245
Power and Industrial Projects	1,950			72		(6		)	27			(45		)	66			1,067			26		93
Energy Trading	1,771			1		—			8			(38		)	(58		)	623			17		3
Corporate and Other	3			1		(51		)	120			(37		)	(44		)	2,945			—		1
Reclassifications and Eliminations	(868		)	—		63			(63		)	—			—			(970		)	—		—
Total	$	9,661		$	1,094	$	(9	)	$	436		$	254		$	661		$	25,935		$	2,018	$	1,876

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures
	(In millions)
2012
Electric	$	5,293		$	827	$	(1	)	$	272		$	280		$	483		$	17,755		$	1,208	$	1,230
Gas	1,315			92		(7		)	59			50			115			4,059			745		221
Gas Storage and Pipelines	96			8		(8		)	8			39			61			668			22		233
Power and Industrial Projects	1,823			65		(7		)	37			(44		)	42			991			26		83
Energy Trading	1,109			2		—			8			7			12			629			17		1
Corporate and Other	3			1		(52		)	121			(46		)	(47		)	3,074			—		3
Reclassifications and Eliminations	(848		)	—		65			(65		)	—			—			(837		)	—		—
Total from Continuing Operations	$	8,791		$	995	$	(10	)	$	440		$	286		$	666		$	26,339		$	2,018	$	1,771
Discontinued Operations (Note 7)															(56		)	—			—		49
Total															$	610		$	26,339		$	2,018	$	1,820

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Taxes			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures
	(In millions)
2011
Electric	$	5,154		$	818	$	(1	)	$	289		$	265		$	434		$	17,567		$	1,208	$	1,203
Gas	1,505			89		(7		)	64			60			110			4,065			745		179
Gas Storage and Pipelines	91			6		(5		)	7			35			57			538			22		16
Power and Industrial Projects	1,129			60		(8		)	32			11			38			789			26		56
Energy Trading	1,276			3		—			9			34			52			612			17		1
Corporate & Other	4			1		(47		)	145			(136		)	23			2,605			—		—
Reclassifications and Eliminations	(301		)	—		58			(58		)	(1		)	—			(485		)	—		—
Total from Continuing Operations	$	8,858		$	977	$	(10	)	$	488		$	268		$	714		$	25,691		$	2,018	$	1,455
Discontinued Operations (Note 7)															(3		)	318			2		29
Total															$	711		$	26,009		$	2,020	$	1,484

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Supplementary Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

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

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
	(In millions, except per share amounts)
2013
Operating Revenues	$	2,516	$	2,225	$	2,387	$	2,533	$	9,661
Operating Income	$	410	$	223	$	329	$	241	$	1,203
Net Income Attributable to DTE Energy Company	$	234	$	105	$	198	$	124	$	661
Basic Earnings per Share	$	1.35	$	0.60	$	1.13	$	0.70	$	3.76
Diluted Earnings per Share	$	1.34	$	0.60	$	1.13	$	0.70	$	3.76

2012
Operating Revenues	$	2,239	$	2,013		$	2,190	$	2,349		$	8,791
Operating Income	$	312	$	294		$	406	$	267		$	1,279
Net Income Attributable to DTE Energy Company
Continuing Operations	$	156	$	147		$	226	$	137		$	666
Discontinued Operations	—		(1		)	1		(56		)	(56		)
Net Income Attributable to DTE Energy Company	$	156	$	146		$	227	$	81		$	610
Basic Earnings per Share
Continuing Operations	$	0.91	$	0.87		$	1.31	$	0.79		$	3.89
Discontinued Operations	—		(0.01		)	0.01		(0.32		)	(0.33		)
Total	$	0.91	$	0.86		$	1.32	$	0.47		$	3.56
Diluted Earnings per Share
Continuing Operations	$	0.91	$	0.87		$	1.30	$	0.79		$	3.88
Discontinued Operations	—		(0.01		)	0.01		(0.32		)	(0.33		)
Total	$	0.91	$	0.86		$	1.31	$	0.47		$	3.55

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Consolidated Statements of Changes in Equity (USD $) In Millions, except Share data	Total	Common Stock [Member]	Retained Earnings	Accumulated Translation Adjustment [Member]	Other Postretirement Benefit Plan, Defined Benefit [Member]	Accumulated Net Unrealized Investment Gain (Loss) [Member]	Accumulated Other Comprehensive Loss	Non-controlling Interest
Beginning Balance at Dec. 31, 2010	$ 6,767	$ 3,440	$ 3,431				$ (149)	$ 45
Beginning Balance, shares at Dec. 31, 2010		169,428,000
Net Income	720		711					9
Dividends declared on common stock	(392)		(392)
Repurchase of common stock, Shares		(1,184,000)
Repurchase of Common Stock, Value	(58)	(58)
Other Comprehensive Income (Loss), Net of Tax	(9)				(9)
Stock-based compensation, distributions to noncontrolling interests and other, Shares		1,003,000
Stock-based compensation, distributions to noncontrolling interests and other	25	35						(10)
Ending Balance at Dec. 31, 2011	7,053	3,417	3,750				(158)	44
Ending Balance, shares at Dec. 31, 2011		169,247,000
Net Income	618		610					8
Dividends declared on common stock	(414)		(414)
Issuance of common stock, Shares		684,000
Issuance of common stock, Value	39	39
Contribution of Common Stock to Pension Plan Shares		1,335,000
Contribution of Common Stock to Pension Plan	80	80
Other Comprehensive Income (Loss), Net of Tax	0			1	(2)	1
Stock-based compensation, distributions to noncontrolling interests and other, Shares		1,086,000
Stock-based compensation, distributions to noncontrolling interests and other	35	51	(2)					(14)
Ending Balance at Dec. 31, 2012	7,411	3,587	3,944				(158)	38
Ending Balance, shares at Dec. 31, 2012	172,351,680	172,352,000
Net Income	668		661					7
Dividends declared on common stock	(454)		(454)
Issuance of common stock, Shares		589,000
Issuance of common stock, Value	39	39
Contribution of Common Stock to Pension Plan Shares		3,026,000
Contribution of Common Stock to Pension Plan	200	200
Other Comprehensive Income (Loss), Net of Tax	22			(2)	22	2
Stock-based compensation, distributions to noncontrolling interests and other, Shares		1,120,000
Stock-based compensation, distributions to noncontrolling interests and other	68	81	(1)					(12)
Ending Balance at Dec. 31, 2013	$ 7,954	$ 3,907	$ 4,150				$ (136)	$ 33
Ending Balance, shares at Dec. 31, 2013	177,087,230	177,087,000

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Valuation and Qualifying Accounts (Notes)

12 Months Ended

Dec. 31, 2013

Valuation and Qualifying Accounts [Abstract]

Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]

Valuation and Qualifying Accounts

	Year Ending December 31,
	2013			2012			2011
	(In millions)
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statements of Financial Position)
Balance at Beginning of Period	$	62		$	162		$	196
Additions:
Charged to costs and expenses	94			79			94
Charged to other accounts (a)	23			16			18
Deductions (b)	(124		)	(195		)	(146		)
Balance at End of Period	$	55		$	62		$	162

_______________________________________

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

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Discontinued Operations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total operating expenses					$ 8,458	$ 7,512	$ 7,437
Disposal Group, Income tax expense (benefit)					0	29	1
Discontinued Operations Income (Loss), net of tax	(56)	1	(1)	0	0	(56)	(3)
Segment, Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Operating Revenues						55	39
Disposal Group, Operation and maintenance						24	16
Disposal Group, Depreciation, Depletion and Amortization						23	18
Disposal Group, Taxes Other than Income						4	3
Disposal Group, Assets (Gains) and Losses, Net						83	0
Total operating expenses						134	37
Disposal Group, Operating Income (Loss)						(79)	2
Disposal Group, Other (income) and deductions						6	6
Disposal Group, Income (Loss) from Discontinued Operation, before Income Tax						(85)	(4)
Disposal Group, Income tax expense (benefit)						(29)	(1)
Discontinued Operations Income (Loss), net of tax						$ (56)	$ (3)

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Commitments and Contingencies (Purchase Commitments) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Purchase Obligation, Fiscal Year Maturity [Abstract]
Purchase Obligation, Due in Next Twelve Months	$ 2,617
Purchase Obligation, Due in Second Year	1,195
Purchase Obligation, Due in Third Year	643
Purchase Obligation, Due in Fourth Year	345
Purchase Obligation, Due in Fifth Year	311
Purchase Obligation, Due after Fifth Year	3,487
Long-term Purchase Commitment, Amount	$ 8,598

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Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2013

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]

	2012			2011
	(In millions)
Operating Revenues	$	55		$	39
Operation and Maintenance	24			16
Depreciation, Depletion and Amortization	23			18
Taxes Other Than Income	4			3
Asset (Gains) and Losses, Net	83			—
	134			37
Operating Income (Loss)	(79		)	2
Other (Income) and Deductions	6			6
Loss Before Income Taxes	(85		)	(4		)
Income Tax Expense (Benefit)	(29		)	(1		)
Net Loss Attributable to DTE Energy Company	$	(56	)	$	(3	)

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Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2013

Share-based Compensation [Abstract]

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Table Text Block]

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

	2013		2012		2011
	(In millions)
Stock-based compensation expense	$	99	$	83	$	66
Tax benefit	38		33		25
Stock-based compensation cost capitalized in property, plant and equipment	15		5		4

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

Stock option activity was as follows:

	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In millions)
Options outstanding at December 31, 2012	1,192,670		$	41.86
Granted	—		$	—
Exercised	(458,603	)	$	40.71
Forfeited or expired	(10,370	)	$	41.46
Options outstanding and exercisable at December 31, 2013	723,697		$	42.60	$	18

Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, by Exercise Price Range [Table Text Block]

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

						Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)
					Number of Options
Range of Exercise Prices
$	27.00	—	$	38.00	67,257	$	28.30	5.15
$	38.01	—	$	42.00	167,447	$	41.23	3.21
$	42.01	—	$	45.00	351,893	$	44.02	4.16
$	45.01	—	$	50.00	137,100	$	47.67	3.08
					723,697	$	42.60	3.83

Schedule of Share-based Compensation, Restricted Stock Units Award Activity [Table Text Block]

Stock award activity for the years ended December 31 was:

	2013		2012		2011
Fair value of awards vested (in millions)	$	8	$	9	$	13
Restricted common shares awarded	127,785		167,320		381,840
Weighted average market price of shares awarded	$	64.72	$	53.71	$	47.98
Compensation cost charged against income (in millions)	$	23	$	12	$	12

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block]

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

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at December 31, 2012	597,648		$	48.33
Grants	127,785		$	64.72
Forfeitures	(7,155	)	$	54.61
Vested and issued	(225,949	)	$	45.54
Balance at December 31, 2013	492,329		$	53.76

Share Based Compensation Expense [Table Text Block]

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

	2013		2012		2011
	(In millions)
Compensation expense	$	77	$	71	$	53
Cash settlements (a)	$	9	$	4	$	3
Stock settlements (a)	$	56	$	41	$	25

Summary of Performance Share Activity [Table Text Block]

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

	Performance Shares
Balance at December 31, 2012	1,634,364
Grants	564,561
Forfeitures	(41,512	)
Payouts	(548,624	)
Balance at December 31, 2013	1,608,789

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

	Unrecognized Compensation Cost		Weighted Average to be Recognized
	(In millions)		(In years)
Stock awards	$	10	0.93
Performance shares	45		0.93
	$	55	0.93

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Fair Value (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Option, Quantitative Disclosures [Line Items]
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, before Tax	$ 0	$ 0
Trading Securities, Change in Unrealized Holding Gain (Loss)	22,000,000	11,000,000	4,000,000
Equity Securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Nuclear Decommissioning Trust Fund Investments	61.00%	61.00%
Debt Securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Nuclear Decommissioning Trust Fund Investments	37.00%	38.00%
Cash and Cash Equivalents [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Nuclear Decommissioning Trust Fund Investments	2.00%	1.00%
Fair Value, Measurements, Recurring [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	125,000,000	123,000,000
Other investments	136,000,000	110,000,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	115,000,000	123,000,000
Other investments	44,000,000	44,000,000
Other Investments [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	16,000,000
Other Investments [Member] | Fair Value, Measurements, Recurring [Member] | Equity [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Available-for-sale Securities, Fair Value Disclosure	7,000,000	5,000,000
Other investments	136,000,000	110,000,000
Other Investments [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure		14,000,000
Restricted Assets [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	109,000,000
Restricted Assets [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure		109,000,000
Nuclear Decommissioning Trust Fund [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Average Maturity of Debt Securities	7 years	6 years
Nuclear Decommissioning Trust Fund [Member] | Cash and Cash Equivalents [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	19,000,000	7,000,000
Fermi 2 [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Unrealized losses recognized as regulatory assets	31,000,000	44,000,000
Fermi 1 [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Other than Temporary Impairment Losses, Investments, Portion Recognized in Earnings, Net	$ 0	$ 0	$ 0

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Consolidated Statements of Operations (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement [Abstract]
Operating Revenue	$ 9,661	$ 8,791	$ 8,858
Operating Expenses
Fuel, purchased power and gas	4,055	3,296	3,537
Operation and maintenance	2,978	2,892	2,612
Depreciation, depletion and amortization	1,094	995	977
Taxes other than income	340	332	310
Asset (gains) and losses, reserves and impairments, net	(9)	(3)	1
Total operating expenses	8,458	7,512	7,437
Operating Income	1,203	1,279	1,421
Other (Income) and Deductions
Interest expense	436	440	488
Interest income	(9)	(10)	(10)
Other Income	(201)	(173)	(117)
Other expenses	55	62	69
Total Other (Income) and Deductions	281	319	430
Income Before Income Taxes	922	960	991
Income Tax Expense	254	286	268
Income from Continuing Operations	668	674	723
Discontinued Operations Income (Loss), net of tax	0	(56)	(3)
Net Income	668	618	720
Less: Net Income Attributable to Noncontrolling Interests	7	8	9
Net Income Attributable to DTE Energy Company	$ 661	$ 610	$ 711
Basic Earnings per Common Share
Income from continuing operations	$ 3.76	$ 3.89	$ 4.21
Income (Loss) from Discontinued Operations, Net of Tax, Per Basic Share	$ 0.00	$ (0.33)	$ (0.02)
Total Basic Earnings per Common Share	$ 3.76	$ 3.56	$ 4.19
Diluted Earnings per Common Share
Income from continuing operations	$ 3.76	$ 3.88	$ 4.20
Income (Loss) from Discontinued Operations, Net of Tax, Per Diluted Share	$ 0.00	$ (0.33)	$ (0.02)
Total Diluted Earnings per Common Share	$ 3.76	$ 3.55	$ 4.18
Weighted Average Common Shares Outstanding
Basic	175	171	169
Weighted Average Number Diluted Shares Outstanding Adjustment	175	172	170
Dividends Declared per Common Share	$ 2.59	$ 2.42	$ 2.32

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

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

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

	2013			2012			2011
	(In millions)
Income before income taxes	$	922		$	960		$	991
Income tax expense at 35% statutory rate	$	323		$	336		$	347
Production tax credits	(68		)	(49		)	(6		)
Investment tax credits	(6		)	(6		)	(6		)
Depreciation	(4		)	(4		)	(4		)
AFUDC - Equity	(5		)	(4		)	(1		)
Employee Stock Ownership Plan dividends	(4		)	(4		)	(4		)
Domestic production activities deduction	(14		)	(14		)	(7		)
State and local income taxes, net of federal benefit	37			37			37
Enactment of Michigan Corporate Income Tax, net of federal expense	—			—			(87		)
Other, net	(5		)	(6		)	(1		)
Income tax expense	$	254		$	286		$	268
Effective income tax rate	27.5		%	29.8		%	27.0		%

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

Components of income tax expense were as follows:

	2013		2012			2011
	(In millions)
Current income tax expense (benefit)
Federal	$	74	$	190		$	27
State and other income tax	16		49			21
Total current income taxes	90		239			48
Deferred income tax expense (benefit)
Federal	122		39			318
State and other income tax	42		8			(98		)
Total deferred income taxes	164		47			220
Total income taxes from continuing operations	254		286			268
Discontinued operations	—		(29		)	(1		)
Total	$	254	$	257		$	267

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

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

	2013			2012
	(In millions)
Property, plant and equipment	$	(3,372	)	$	(3,389	)
Securitized regulatory assets	(127		)	(256		)
Alternative minimum tax credit carry-forwards	266			254
Merger basis differences	18			42
Pension and benefits	(30		)	(33		)
Other comprehensive loss	—			101
Derivative assets and liabilities	—			66
State net operating loss and credit carry-forwards	43			37
Other	(110		)	41
	(3,312		)	(3,137		)
Less valuation allowance	(37		)	(33		)
	$	(3,349	)	$	(3,170	)
Current deferred income tax assets (liabilities)	$	(28	)	$	21
Long-term deferred income tax liabilities	(3,321		)	(3,191		)
	$	(3,349	)	$	(3,170	)
Deferred income tax assets	$	1,808		$	1,038
Deferred income tax liabilities	(5,157		)	(4,208		)
	$	(3,349	)	$	(3,170	)

Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]

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

	2013			2012			2011
	(In millions)
Balance at January 1	$	11		$	48		$	28
Additions for tax positions of prior years	—			—			27
Reductions for tax positions of prior years	—			(2		)	(4		)
Additions for tax positions of current year	—			1			1
Settlements	—			(30		)	(3		)
Lapse of statute of limitations	(1		)	(6		)	(1		)
Balance at December 31	$	10		$	11		$	48

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Income Taxes (Deferred Tax Assets (Liabilities)) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Components of Deferred Tax Assets and Liabilities [Abstract]
Property, plant and equipment	$ (3,372)	$ (3,389)
Securitized regulatory assets	(127)	(256)
Alternative minimum tax credit carry-forwards	266	254
Merger basis differences	18	42
Pension and benefits	(30)	(33)
Other comprehensive income	0	101
Derivative assets liabilities	0	66
State net operating loss and credit carry-forwards	43	37
Deferred Tax Liabilities, Other	(110)
Other		41
Deferred Tax Liabilities, Gross	(3,312)	(3,137)
Less valuation allowance	(37)	(33)
Current deferred income tax assets	(28)	21
Long-term deferred income tax liabilities	(3,321)	(3,191)
Deferred Tax Assets, Net of Valuation Allowance	1,808	1,038
Deferred Tax Liability, Net of Valuation Allowance	(5,157)	(4,208)
Deferred income tax liabilities	$ (3,349)	$ (3,170)

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Stock-Based Compensation (Stock Award Activity) (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock Award Activity [Line Items]
Compensation cost charged against income (in millions)	$ 99	$ 83	$ 66
Restricted Stock [Member]
Stock Award Activity [Line Items]
Fair value of awards vested (in millions)	8	9	13
Restricted common shares awarded	127,785	167,320	381,840
Weighted average market price of shares awarded	$ 64.72	$ 53.71	$ 47.98
Compensation cost charged against income (in millions)	$ 23	$ 12	$ 12

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Commitments and Contingencies (Details Textuals) (USD $)	12 Months Ended			12 Months Ended		12 Months Ended			3 Months Ended		9 Months Ended	12 Months Ended		12 Months Ended
	Dec. 31, 2013 employees	Aug. 31, 2013	Dec. 31, 2010 dte_instances	Dec. 31, 2013 Gas [Member] facilities	Dec. 31, 2012 Gas [Member]	Dec. 31, 2013 Synthetic Fuel [Member]	Dec. 31, 2013 Emissions [Member]	Dec. 31, 2013 Other Guarantees [Member]	Dec. 31, 2013 Electric [Member] facilities dte_instances	Mar. 31, 2013 Electric [Member] dte_instances facilities	Dec. 31, 2013 Electric [Member] facilities dte_instances	Dec. 31, 2013 Electric [Member] facilities kWh dte_instances	Dec. 31, 2012 Electric [Member]	Dec. 31, 2011 Eight Year [Member] Electric [Member]
Loss Contingencies [Line Items]
Environmental Capital Expenditures Through Current Year												$ 2,000,000,000
Estimated capital expenditures in next fiscal year												280,000,000
Environmental Capital Expenditures In Future Years												1,200,000,000
EPA is Alleging Power Plants Violated New Source Performance Standards									5		5	5
Number of NOVs/FOVs currently being discussed with the EPA									2		2	2
Sierra Club is Alleging DTE Electric Coal Fired Power Plants Violated the Clean Air Act										4
Exceedances of Opacity Standard									1,139	1,499	1,139	1,139
Period of excess opacity of air emissions at alleged facilities										6 minutes
2004 EPA proposed compliance timeline in years														8 years
Number of Former MGP Sites				15								3
Accrued for remediation related to the sites				28,000,000	29,000,000				8,000,000		8,000,000	8,000,000	9,000,000
Number of Options to Regulate Coal Ash Residue									2		2	2
Period Gas Utility Can Amortize MGP Costs				10 years
Number of NOVs			2
Possible Environmental Capital Expenditures to Comply with Requirements	3,000,000
EPA Sulfur Dioxide Ambient Air Quality Standard	1 hour
Waiting Period of Policy	P12W
Insurance Coverage for Extra Expense when Power Plant Unavailable												490,000,000
Period of Coverage of Policy for Extra Expenses												3 years
Primary Coverage												500,000,000
Coverage for Stabilization Decontamination Debris Removal Repair and Replacement of Property and Decommissioning												2,250,000,000
Combined Coverage Limit for Total Property Damage												2,750,000,000
Insurance Deductible for Nuclear Power Plant									1,000,000		1,000,000	1,000,000
Total Limit for Property Damage for Non-Nuclear Events									1,800,000,000		1,800,000,000	1,800,000,000
Limit of Coverage for Aggregate Extra Expenses for Non-Nuclear Events											327,000,000
Limit for Property Damage for Non-Nuclear Events Aggregate of Extra Expenses of Period											2 years
Time Period for TRIA Insurance After the First Loss from Terrorism												1 year
NEIL Policies Against Terroism Loss												3,200,000,000
Amount per Event Loss Associated with Nuclear Power Plants												34,000,000
Maintenance of Public Liability Insurance for Nuclear Power Plants												375,000,000
Aggregate Limit of Liabilities Arises From Terroist Act Outside Scope of Trials Subject to One Industry												300,000,000
Deferred Premium Charged Leviied Against Each Licensed Nuclear Facility												127,300,000
Limit Deferred Premium Charges Per Year												19,000,000
Company Obligated to Pay DOE Fee of Fermi 2 Electricity Generated and Sold												1
Settlement Provided for Delay-Related Costs									48,000,000		48,000,000	48,000,000
Court of Appeals proposal to congress to reduce nuclear waste fee, amount									0
Time period after which the Court of Appeals proposal to Congress for nuclear waste fee reduction will take effect	90 days
Days Obligations will Survive After Expiration of All Applicable Statutes of Limiations						90 years	90 days
Guarantor Obligations, Maximum Exposure, Undiscounted						1,100,000,000	144,000,000	60,000,000
Performance Bonds Outstanding	41,000,000
Number of Represented Employees	4,900
Long-term Purchase Commitment, Amount	8,598,000,000
Estimated future capital expenditures for next year	2,300,000,000
Bankruptcy Claims, Accounts Receivable under Review by Management		$ 20,000,000

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Consolidated Statements of Financial Position (Parenthetical) (Parentheticals) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Allowance for doubtful accounts	$ 55	$ 62
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	400,000,000	400,000,000
Common stock, shares issued	177,087,230	172,351,680
Common stock, shares outstanding	177,087,230	172,351,680

XML

Income Taxes (Reconciliation of Income Tax Expense to the Statutory Federal Income Tax Rate) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	$ 922	$ 960	$ 991
Income tax expense at 35% statutory rate	323	336	347
Production tax credits	(68)	(49)	(6)
Investment tax credits	(6)	(6)	(6)
Depreciation	(4)	(4)	(4)
AFUDC - Equity	(5)	(4)	(1)
Employee Stock Ownership Plan dividends	(4)	(4)	(4)
Domestic production activities deduction	(14)	(14)	(7)
State and Local income taxes, net of federal benefit	37	37	37
Enactment of Michigan Corporate income Tax, net of federal expense	0	0	(87)
Other, net	(5)	(6)	(1)
Income Tax Expense (Benefit)	$ 254	$ 286	$ 268
Effective Income Tax Rate	27.50%	29.80%	27.00%

XML

Stock-Based Compensation (Performance Share Awards Activity) (Details)	12 Months Ended
	Dec. 31, 2013
Performance Share Awards [Line Items]
Forfeitures	(10,370)
Performance Shares [Member]
Performance Share Awards [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding, Number	1,634,364
Grants	564,561
Forfeitures	(41,512)
Performance Shares - Payouts	(548,624)
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding, Number	1,608,789

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Stock-Based Compensation (Details Textuals) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule of Stock Based Compensation [Line Items]
Authorized limit of common stock shares	11,500,000
Performance Units Price per Unit	1.00
Expiration Period After Date of Grant	10 years
Award Vesting Period	3 years
Weighted Average Remaining Contractual Term	3 years 9 months 30 days
Options, Vested, Number of Shares	200,844
Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 0
Options, Exercises in Period, Total Intrinsic Value	$ 12	$ 25	$ 20
Stock or Unit Option Plan Expense	0	0.7	2.0
Unrecognized Compensation Cost	55
Weighted Average to be Recognized	11 months 5 days
Employee Stock Option [Member]
Schedule of Stock Based Compensation [Line Items]
Maximum Award Per Employee	500,000
Restricted Stock [Member]
Schedule of Stock Based Compensation [Line Items]
Maximum Award Per Employee	150,000
Unrecognized Compensation Cost	10
Weighted Average to be Recognized	11 months 5 days
Performance Shares [Member]
Schedule of Stock Based Compensation [Line Items]
Maximum Award Per Employee	300,000
Unrecognized Compensation Cost	$ 45
Weighted Average to be Recognized	11 months 5 days
Performance Unit [Member]
Schedule of Stock Based Compensation [Line Items]
Maximum Award Per Employee	1,000,000

XML

Organization and Basis of Presentation (Non Consolidated Variable Interest Entities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Notes receivable	$ 102	$ 112
Variable Interest Entity, NonConsolidated [Member]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Other investments	141	130
Notes receivable	$ 8	$ 6

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Common Stock (Details) (Pension Plan, Defined Benefit [Member], Common Stock [Member], USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended				12 Months Ended
	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Jun. 30, 2012	Dec. 31, 2013
Pension Plan, Defined Benefit [Member] | Common Stock [Member]
Class of Stock [Line Items]
Stock Issued During Period, Shares, Employee Benefit Plan	1,522,301	753,579	750,075	1,334,668
Contribution of Common Stock to Pension Plans Amount Per Share	$ 65.69	$ 66.35	$ 66.66	$ 59.94
Pension Contributions	$ 100	$ 50	$ 50	$ 80	$ 200

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

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

	Changes in Accumulated Other Comprehensive Loss by Component (a)
	For The Year Ended December 31, 2013
	Net Unrealized Gain/(Loss) on Derivatives			Net Unrealized Gain/(Loss) on Investments			Benefit Obligations (b)			Foreign Currency Translation			Total
	(In millions)
Beginning balances December 31, 2012	$	(4	)	$	(8	)	$	(148	)	$	2		$	(158	)
Other comprehensive income (loss) before reclassifications	—			2			13			(2		)	13
Amounts reclassified from accumulated other comprehensive income (loss)	—			—			9			—			9
Net current-period other comprehensive income (loss)	—			2			22			(2		)	22
Ending balances December 31, 2013	$	(4	)	$	(6	)	$	(126	)	$	—		$	(136	)

______________________________________

(a) All amounts are net of tax.

(b) The amounts reclassified from accumulated other comprehensive income (loss) are included in the computation of the net periodic pension and other postretirement benefit costs (see Note 20).

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

The Company has certain intangible assets relating to emission allowances, renewable energy credits and non-utility contracts as shown below:

	December 31,		December 31,
	2013		2012
	(In millions)
Emission allowances	$	2	$	6
Renewable energy credits	51		44
Contract intangible assets	126		139
	179		189
Less accumulated amortization	45		34
Intangible assets, net	134		155
Less current intangible assets	12		20
	$	122	$	135

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]

The following table summarizes the estimated amortization expense expected to be recognized during each year through 2018:

Estimated amortization expense	(In millions)
2014	$	13
2015	$	12
2016	$	11
2017	$	8
2018	$	8

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Retirement Benefits and Trusteed Assets (Details Textuals) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Company Contribution to Employee Savings Plan		4.00%
Company Retiree New Coverage Minimum		$ 3,250
Company Retiree New Coverage Maximum		3,500
Retiree Health Care Allowance will increase at lower of the rate of medical inflation or a set percentage		2.00%
Retiree Health Care Allowance	3,250
Prescription Drug Benefit, Effect of Subsidy on Net Periodic Postretirement Benefit Cost		1,000,000	6,000,000	6,000,000
Grantor Trust Balance		17,000,000	14,000,000
Defined Contribution Plan, Cost Recognized		41,000,000	37,000,000	35,000,000
Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Company contributions		284,000,000	240,000,000
Estimated Future Employer Contributions in Next Fiscal Year		345,000,000
Defined Benefit Plan, Expected Return on Plan Assets		7.75%
Transfers between Level 3 and Level 2		0	0
Transfers between Level 2 and Level 1		0	0
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		4.95%	4.15%	5.00%
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Company contributions		264,000,000	140,000,000
Estimated Future Employer Contributions in Next Fiscal Year		145,000,000
Defined Benefit Plan, Expected Return on Plan Assets		8.00%
Transfers between Level 3 and Level 2		0	0
Transfers between Level 2 and Level 1		0	0
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components		9,000,000
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation		124,000,000
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components		8,000,000
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation		108,000,000
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.30%	4.95%	4.15%	5.00%
Retiree Healthcare Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Cost Recognized		2,000,000	0
DTE Gas Represented Employees [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Company Contribution to Employee Savings Plan		8.00%
Qualified Plans [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Company contributions		$ 277,000,000

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Fair Value (Reconciliation of Level 3 Assets and Liabilities at Fair Value on a Recurring Basis) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	$ (13)	$ 44
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	1	1
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	43	60
Fair Value Net Derivative Asset (Liability) Measured on Recurring Basis Unobservable Inputs Reconciliation Gains and Losses Recorded In Regulatory Assets Liabilities	5	15
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Purchases	(7)	2
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Issues	(1)	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements	(64)	(135)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	(36)	(13)
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	(1)	58
Natural Gas Commodity Contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	(38)	6
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	1	1
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	(32)	(41)
Fair Value Net Derivative Asset (Liability) Measured on Recurring Basis Unobservable Inputs Reconciliation Gains and Losses Recorded In Regulatory Assets Liabilities	0	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Purchases	(8)	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Issues	0	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements	25	(4)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	(52)	(38)
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	(49)	(33)
Electricity Commodity Contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	23	32
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	0	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	75	101
Fair Value Net Derivative Asset (Liability) Measured on Recurring Basis Unobservable Inputs Reconciliation Gains and Losses Recorded In Regulatory Assets Liabilities	0	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Purchases	1	2
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Issues	(1)	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements	(85)	(112)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	13	23
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	48	91
Other Commodity Contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	2	6
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	0	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	0	0
Fair Value Net Derivative Asset (Liability) Measured on Recurring Basis Unobservable Inputs Reconciliation Gains and Losses Recorded In Regulatory Assets Liabilities	5	15
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Purchases	0	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Issues	0	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements	(4)	(19)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	3	2
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	$ 0	$ 0

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Earnings Per Share (Notes)

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Earnings Per Share

EARNINGS PER SHARE

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

	2013		2012		2011
	(In millions, expect per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	661	$	610	$	711
Average number of common shares outstanding	175		171		169
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	453	$	413	$	392
Dividends declared — net restricted shares	1		1		1
Total distributed earnings	$	454	$	414	$	393
Net income less distributed earnings	$	207	$	196	$	318
Distributed (dividends per common share)	$	2.59	$	2.42	$	2.32
Undistributed	1.17		1.14		1.87
Total Basic Earnings per Common Share	$	3.76	$	3.56	$	4.19
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	661	$	610	$	711
Average number of common shares outstanding	175		171		169
Average incremental shares from assumed exercise of options	—		1		1
Common shares for dilutive calculation	175		172		170
Weighted average net restricted shares outstanding	1		1		1
Dividends declared — common shares	$	453	$	413	$	392
Dividends declared — net restricted shares	1		1		1
Total distributed earnings	$	454	$	414	$	393
Net income less distributed earnings	$	207	$	196	$	318
Distributed (dividends per common share)	$	2.59	$	2.42	$	2.32
Undistributed	1.17		1.13		1.86
Total Diluted Earnings per Common Share	$	3.76	$	3.55	$	4.18

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Fair Value (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Assets and liabilities measured and recorded at fair value on a recurring basis

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

	December 31, 2013															December 31, 2012
	Level 1			Level 2			Level 3			Netting (a)			Net Balance			Level 1			Level 2			Level 3			Netting (a)			Net Balance
	(In millions)
Assets:
Cash equivalents (b)	$	10		$	115		$	—		$	—		$	125		$	—		$	123		$	—		$	—		$	123
Nuclear decommissioning trusts	779			412			—			—			1,191			694			343			—			—			1,037
Other investments (c) (d)	92			44			—			—			136			66			44			—			—			110
Derivative assets:
Commodity Contracts:
Natural Gas	273			89			34			(382		)	14			555			66			24			(605		)	40
Electricity	—			261			139			(291		)	109			—			226			134			(258		)	102
Other	33			1			3			(34		)	3			6			3			2			(6		)	5
Total derivative assets	306			351			176			(707		)	126			561			295			160			(869		)	147
Total	$	1,187		$	922		$	176		$	(707	)	$	1,578		$	1,321		$	805		$	160		$	(869	)	$	1,417
Liabilities:
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(277	)	$	(140	)	$	(86	)	$	395		$	(108	)	$	(526	)	$	(73	)	$	(62	)	$	605		$	(56	)
Electricity	—			(272		)	(126		)	269			(129		)	—			(240		)	(111		)	258			(93		)
Other	(32		)	(2		)	—			34			—			(6		)	(1		)	—			6			(1		)
Other derivative contracts (f)	—			(1		)	—			—			(1		)	—			(1		)	—			—			(1		)
Total derivative liabilities	(309		)	(415		)	(212		)	698			(238		)	(532		)	(315		)	(173		)	869			(151		)
Total	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)
Net Assets (liabilities) at the end of the period	$	878		$	507		$	(36	)	$	(9	)	$	1,340		$	789		$	490		$	(13	)	$	—		$	1,266
Assets:
Current	$	277		$	400		$	139		$	(592	)	$	224		$	493		$	372		$	120		$	(754	)	$	231
Noncurrent (e)	910			522			37			(115		)	1,354			828			433			40			(115		)	1,186
Total Assets	$	1,187		$	922		$	176		$	(707	)	$	1,578		$	1,321		$	805		$	160		$	(869	)	$	1,417
Liabilities:
Current	$	(268	)	$	(328	)	$	(177	)	$	578		$	(195	)	$	(466	)	$	(269	)	$	(144	)	$	754		$	(125	)
Noncurrent	(41		)	(87		)	(35		)	120			(43		)	(66		)	(46		)	(29		)	115			(26		)
Total Liabilities	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)
Net Assets (liabilities) at the end of the period	$	878		$	507		$	(36	)	$	(9	)	$	1,340		$	789		$	490		$	(13	)	$	—		$	1,266

_______________________________________

(a) Amounts represent the impact of master netting agreements that allow the Company to net gain and loss positions and cash collateral held or placed with the same counterparties.

(b) At December 31, 2013, available-for-sale securities of $125 million included $109 million and $16 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively. At December 31, 2012, available-for-sale securities of $123 million, included $109 million and $14 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively.

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

(d) Available-for-sale equity securities of $7 million at December 31, 2013 and $5 million at December 31, 2012 are included in Other investments on the Consolidated Statements of Financial Position.

(e) Includes $136 million and $110 million of Other investments that are included in the Consolidated Statements of Financial Position in Other investments at December 31, 2013 and 2012, respectively.

(f) Includes Interest rate contracts and Foreign currency exchange contracts.

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

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

	Year Ended December 31, 2013												Year Ended December 31, 2012
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of December 31	$	(38	)	$	23		$	2		$	(13	)	$	6		$	32		$	6		$	44
Transfers into Level 3	1			—			—			1			1			—			—			1
Total gains (losses):
Included in earnings	(32		)	75			—			43			(41		)	101			—			60
Recorded in regulatory assets/liabilities	—			—			5			5			—			—			15			15
Purchases, issuances and settlements:
Purchases	(8		)	1			—			(7		)	—			2			—			2
Issuances	—			(1		)	—			(1		)	—			—			—			—
Settlements	25			(85		)	(4		)	(64		)	(4		)	(112		)	(19		)	(135		)
Net Assets (Liabilities) as of December 31	$	(52	)	$	13		$	3		$	(36	)	$	(38	)	$	23		$	2		$	(13	)
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at December 31, 2013 and 2012 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(49	)	$	48		$	—		$	(1	)	$	(33	)	$	91		$	—		$	58

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

The following table shows transfers between the levels of the fair value hierarchy for the years ended December 31, 2013 and 2012:

	Year Ended December 31, 2013					Year Ended December 31, 2012
	Level 1	Level 2		Level 3		Level 1	Level 2		Level 3
	(In millions)
Transfers into Level 1 from	$ N/A	$	—	$	—	$ N/A	$	—	$	—
Transfers into Level 2 from	—	N/A		—		—	N/A		—
Transfers into Level 3 from	—	1		N/A		—	1		N/A

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

The following table presents the unobservable inputs related to Level 3 assets and liabilities as of December 31, 2013 and 2012:

	December 31, 2013
Commodity Contracts	Derivative Assets		Derivative Liabilities			Valuation Techniques	Unobservable Input	Range							Weighted Average
	(In millions)
Natural Gas	$	34	$	(86	)	Discounted Cash Flow	Forward basis price (per MMBtu)	$	(0.88	)	—	$	5.07	/MMBtu	$	(0.16	)/MMBtu
Electricity	$	139	$	(126	)	Discounted Cash Flow	Forward basis price (per MWh)	$	(7	)	—	$	15	/MWh	$	3	/MWh

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

Fair Value of Financial Instruments [Table Text Block]

The following table presents the carrying amount and fair value of financial instruments as of December 31, 2013 and 2012:

	December 31, 2013								December 31, 2012
	Carrying		Fair Value						Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Amount		Level 1		Level 2		Level 3
	(In millions)
Notes receivable, excluding capital leases	$	41	$	—	$	—	$	41	$	39	$	—	$	—	$	39
Dividends payable	$	116	$	116	$	—	$	—	$	107	$	107	$	—	$	—
Short-term borrowings	$	131	$	—	$	131	$	—	$	240	$	—	$	240	$	—
Long-term debt	$	8,094	$	425	$	7,551	$	499	$	7,813	$	507	$	7,453	$	933

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

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

	December 31, 2013		December 31, 2012
	(In millions)
Fermi 2	$	1,172	$	1,021
Fermi 1	3		3
Low level radioactive waste	16		13
Total	$	1,191	$	1,037

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

The following table sets forth the gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds:

	Year Ended December 31
	2013			2012			2011
	(In millions)
Realized gains	$	83		$	37		$	46
Realized losses	$	(41	)	$	(31	)	$	(38	)
Proceeds from sales of securities	$	1,118		$	759		$	833

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

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

	December 31, 2013				December 31, 2012
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
	(In millions)
Equity securities	$	730	$	201	$	631	$	122
Debt securities	442		12		399		27
Cash and cash equivalents	19		—		7		—
	$	1,191	$	213	$	1,037	$	149

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Income Taxes (Details Textuals) (USD $)	3 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]
Production Tax Credits Earned In Prior Years But Not Utilized Carried Forward Indefinitely As Alternative Minimum Tax Credits		$ 266,000,000	$ 254,000,000
Deferred Tax Assets State Net Operating Loss and Credit Carry Forwards		43,000,000	37,000,000
Valuation Allowance, Amount		37,000,000	33,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate		2,000,000	3,000,000
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit		1,000,000
Unrecognized Tax Benefits, Interest on Income Taxes Accrued		1,000,000	1,000,000
Unrecognized Tax Benefits, Income Tax Penalties Accrued		0
Unrecognized Tax Benefits, Interest on Income Taxes Expense		0	(1,000,000)	(2,000,000)
Michigan Corporate Income Tax	6.00%
Time Period for the MBT Deferred Tax Asset	1 year
Net impact of Michigan Corporate Income Tax enactment, decrease in deferred tax liabilities attributable to non-utilities	87,000,000
Consistent with Original Treatment of Deferred Tax Liabilities No Cash Flow Impact	$ 0

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Retirement Benefits and Trusteed Assets (OPEB - Postretirement Cost Inclusions) (Details) (Other Postretirement Benefit Plan, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Postretirement Benefit Plan, Defined Benefit [Member]
Other Postretirement Costs [Line Items]
Service cost	$ 47	$ 68	$ 64
Interest cost	88	120	121
Expected return on plan assets	(110)	(92)	(94)
Amortization of Net Loss	64	80	55
Amortization of Prior Service Cost (Credit)	(131)	(27)	(26)
Amortization of net transition asset	0	2	2
Net pension or postretirement cost (benefit)	$ (42)	$ 151	$ 122

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Preferred and Preferenced Securities (Notes)

12 Months Ended

Dec. 31, 2013

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

Preferred and Preference Securities

PREFERRED AND PREFERENCE SECURITIES

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

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

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Fair Value (Fair Value of Financial Instruments) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value of Financial Instruments [Line Items]
Notes Receivable Excudling Capital Leases	$ 41	$ 39
Dividends Payable, Current	116	107
Short-term Debt	131	240
Long-term Debt	8,094	7,813
Fair Value, Inputs, Level 1 [Member]
Fair Value of Financial Instruments [Line Items]
Notes Receivable, Fair Value Disclosure	0	0
Dividends Payable Fair Value Disclosure	116	107
Short-term Debt, Fair Value Disclosure	0	0
Long-term Debt, Fair Value	425	507
Fair Value, Inputs, Level 2 [Member]
Fair Value of Financial Instruments [Line Items]
Notes Receivable, Fair Value Disclosure	0	0
Dividends Payable Fair Value Disclosure	0	0
Short-term Debt, Fair Value Disclosure	131	240
Long-term Debt, Fair Value	7,551	7,453
Fair Value, Inputs, Level 3 [Member]
Fair Value of Financial Instruments [Line Items]
Notes Receivable, Fair Value Disclosure	41	39
Dividends Payable Fair Value Disclosure	0	0
Short-term Debt, Fair Value Disclosure	0	0
Long-term Debt, Fair Value	$ 499	$ 933

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Short-Term Credit Arrangements and Borrowings (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,975
Amounts outstanding	375
Net availability	1,600
DTE Energy [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,375
Amounts outstanding	279
Net availability	1,096
DTE Electric [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	300
Amounts outstanding	0
Net availability	300
DTE Gas [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	300
Amounts outstanding	96
Net availability	204
Letter of Credit [Member]
Line Of Credit Facility [Line Items]
Amounts outstanding	244
Letter of Credit [Member] | DTE Energy [Member]
Line Of Credit Facility [Line Items]
Amounts outstanding	244
Letter of Credit [Member] | DTE Electric [Member]
Line Of Credit Facility [Line Items]
Amounts outstanding	0
Letter of Credit [Member] | DTE Gas [Member]
Line Of Credit Facility [Line Items]
Amounts outstanding	0
Letter of Credit [Member] | Unsecured letter of credit, expiring in May 2014 [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	50
Letter of Credit [Member] | Unsecured letter of credit, expiring in May 2014 [Member] | DTE Energy [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	50
Letter of Credit [Member] | Unsecured letter of credit, expiring in May 2014 [Member] | DTE Electric [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	0
Letter of Credit [Member] | Unsecured letter of credit, expiring in May 2014 [Member] | DTE Gas [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	0
Letter of Credit [Member] | Unsecured letter of credit, expiring in August 2015 [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	125
Letter of Credit [Member] | Unsecured letter of credit, expiring in August 2015 [Member] | DTE Energy [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	125
Letter of Credit [Member] | Unsecured letter of credit, expiring in August 2015 [Member] | DTE Electric [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	0
Letter of Credit [Member] | Unsecured letter of credit, expiring in August 2015 [Member] | DTE Gas [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	0
Revolving Credit Facility [Member] | Unsecured revolving credit facility, expiring April 2018 [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,800
Revolving Credit Facility [Member] | Unsecured revolving credit facility, expiring April 2018 [Member] | DTE Energy [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,200
Revolving Credit Facility [Member] | Unsecured revolving credit facility, expiring April 2018 [Member] | DTE Electric [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	300
Revolving Credit Facility [Member] | Unsecured revolving credit facility, expiring April 2018 [Member] | DTE Gas [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	300
Commercial Paper [Member]
Line Of Credit Facility [Line Items]
Amounts outstanding	131
Commercial Paper [Member] | DTE Energy [Member]
Line Of Credit Facility [Line Items]
Amounts outstanding	35
Commercial Paper [Member] | DTE Electric [Member]
Line Of Credit Facility [Line Items]
Amounts outstanding	0
Commercial Paper [Member] | DTE Gas [Member]
Line Of Credit Facility [Line Items]
Amounts outstanding	$ 96

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Activities
Net Income	$ 668	$ 618	$ 720
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	1,094	1,018	995
Nuclear fuel amortization	38	29	46
Allowance for equity funds used during construction	(15)	(13)	(6)
Deferred income taxes	164	47	220
Loss on sale of non-utility business	0	83	0
Asset (gains) and losses, reserves and impairments, net	(8)	1	(21)
Changes in assets and liabilities:
Accounts receivable, net	(154)	52	71
Inventories	123	35	(129)
Accounts payable	14	40	(23)
Derivative assets and liabilities	107	53	(94)
Accrued pension obligation	(644)	280	432
Accrued postretirement obligation	(526)	(323)	209
Regulatory assets and liabilities	1,269	278	(662)
Other assets	(24)	55	44
Other liabilities	48	(44)	206
Net cash from operating activities	2,154	2,209	2,008
Investing Activities
Plant and equipment expenditures — utility	(1,534)	(1,451)	(1,382)
Plant and equipment expenditures — non-utility	(342)	(369)	(102)
Proceeds from sale of non-utility business	0	255	0
Proceeds from sale of assets	36	38	18
Restricted cash for debt redemption, principally Securitization	(1)	2	(5)
Acquisition, Net of Cash Acquired	0	(198)	0
Proceeds from sale of nuclear decommissioning trust fund assets	1,118	759	833
Investment in nuclear decommissioning trust funds	(1,134)	(764)	(850)
Other	(49)	(41)	(72)
Net cash used for investing activities	(1,906)	(1,769)	(1,560)
Financing Activities
Issuance of long-term debt, net of issuance costs	1,234	759	1,179
Redemption of long-term debt	(961)	(639)	(1,455)
Short-term borrowings, net	(109)	(179)	269
Issuance of common stock	39	39	0
Repurchase of common stock	0	0	(18)
Dividends on common stock	(445)	(407)	(389)
Other	(19)	(16)	(31)
Net cash used for financing activities	(261)	(443)	(445)
Net Increase (Decrease) in Cash and Cash Equivalents	(13)	(3)	3
Cash and Cash Equivalents at Beginning of Period	65	68	65
Cash and Cash Equivalents at End of Period	52	65	68
Supplemental disclosure of cash information
Cash paid (received) for interest (net of interest capitalized)	418	438	485
Cash paid (received) for Income Taxes	121	173	(205)
Supplemental disclosure of non-cash information
Common stock issued for employee benefit and compensation plans	293	155	15
Plant and equipment expenditures in accounts payable	$ 329	$ 235	$ 212

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Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Income and Comprehensive Income [Abstract]
Net Income	$ 668	$ 618	$ 720
Other comprehensive income (loss), net of tax:
Benefit obligations, net of taxes of $13, $(1) and $(5)	22	(2)	(9)
Net unrealized gains on investments during the period, net of taxes of $1, $1 and $—	2	1	0
Foreign currency translation, net of taxes of $(1), $— and $—	(2)	1	0
Other Comprehensive Income (Loss), Net of Tax	22	0	(9)
Comprehensive income	690	618	711
Less: Comprehensive income attributable to noncontrolling interests	7	8	9
Comprehensive income attributable to DTE Energy Company	$ 683	$ 610	$ 702

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Jointly Owned Utility Plant (Notes)

12 Months Ended

Dec. 31, 2013

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

Jointly Owned Utility Plant [Text Block]

JOINTLY OWNED UTILITY PLANT

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

	Belle River			Ludington Hydroelectric Pumped Storage
In-service date	1984-1985			1973
Total plant capacity	1,270		MW	1,872		MW
Ownership interest	(a)			49		%
Investment in property, plant and equipment (in millions)	$	1,702		$	354
Accumulated depreciation (in millions)	$	969		$	170

_______________________________________

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

Belle River

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

Ludington Hydroelectric Pumped Storage

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

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Long-Term Debt (Debt Issuances) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013 Electric [Member] Senior Notes [Member]	Apr. 30, 2013 Gas [Member] Senior Notes [Member]	Mar. 31, 2013 Thirty Years [Member] Electric [Member] Mortgages [Member]	Aug. 31, 2013 Eleven Years [Member] Electric [Member] Mortgages [Member]	Nov. 30, 2013 Ten Years [Member] DTE Energy [Member] Senior Notes [Member]	Sep. 30, 2013 Ten Years [Member] Gas [Member] Mortgages [Member]	Sep. 30, 2013 Twelve Years [Member] Gas [Member] Mortgages [Member]	Sep. 30, 2013 Fifteen Years [Member] Gas [Member] Mortgages [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.40%	5.26%	4.00%	3.65%	3.85%	3.64%	3.74%	3.94%
Debt Instrument, Face Amount	$ 1,245			$ 375	$ 400	$ 300	$ 50	$ 70	$ 50

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Regulatory Matters (Details Textuals) (USD $)	1 Months Ended	3 Months Ended		6 Months Ended	12 Months Ended			1 Months Ended		1 Months Ended	12 Months Ended			6 Months Ended					1 Months Ended		12 Months Ended
	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2010	Dec. 31, 2013	Dec. 31, 2013	Jul. 29, 2013	Jul. 30, 2012	May 31, 2013 Electric [Member]	Dec. 31, 2013 Electric [Member]	May 31, 2013 Gas [Member]	Dec. 31, 2013 Gas [Member]	Dec. 31, 2013 Five Year (Minimum) [Member] Electric [Member]	Dec. 31, 2013 Seven Year (Maximum) [Member] Electric [Member]	Dec. 31, 2013 MPSC [Member] Electric [Member]	Jun. 30, 2013 MPSC [Member] Electric [Member]	Oct. 17, 2013 MPSC [Member] Electric [Member]	Aug. 29, 2013 MPSC [Member] Electric [Member]	Feb. 28, 2013 MPSC [Member] Electric [Member]	Oct. 31, 2013 MPSC [Member] Gas [Member]	Feb. 29, 2012 MPSC [Member] Gas [Member]	Dec. 31, 2013 MPSC [Member] Gas [Member]	Nov. 14, 2013 MPSC [Member] Gas [Member]	May 15, 2013 MPSC [Member] Gas [Member]	Apr. 16, 2013 MPSC [Member] Gas [Member]	Jun. 30, 2012 MPSC [Member] Gas [Member]
Regulatory Assets [Line Items]
Probability of Recovery Through Regulatory Rates for Regulatory Assets and Liabilities					$ 0
Time Period Required by Non-Bypassable Securitization Bond Surcharge to Recover Securitized Regulatory Asset					14 years
Amortization Period of Cost to Achieve Deferral					10 years
Deferral of Investigation and Remediation of Costs Associated with Gas Utilities Former MGP Sites					10 years
Amortization Period for Enterprise Business Systems					10 years
Rate increase previously authorized by the MPSC challeged by Court of Appeals affirmed by the MPSC																8,000,000
Rate increase previously authorized by the MPSC challenged by Court of Appeals reopened by the MPSC																	11,000,000
Transition PLD customers to DTE Electric distribution system												5 years	7 years
EO Reconciliation net over-recovery								26,000,000		7,000,000
Approved performance incentive charges														10,000,000							4,000,000
Approved net recovery of restoration expense tracker mechanism and line clearance tracker																		44,000,000
Approved refund of uncollectible expense true up mechanism for two plan years prior																				9,000,000
Monthly Funding Factor for all Michigan Electric utilities participating in Low Income Energy Assistance Fund						0.0099
REP Surcharge Revenue Recovery				15,000,000											100,000,000
REP Time Period														20 years
PSCR under-recovery from Three Plan Years Prior			52,600,000
Pension Equalization Mechanism Reconciliation surcharge length	1 month
PSCR under-recovery from One Plan Year Prior		87,000,000
PSCR Under-Recovery from Two Plan Years Prior		148,000,000
Fermi 2 Production Level of Full Capacity							68.00%
Maximum of challenged Fermi 2 outage charges									32,000,000
Projected Test Year Period for Gas Rate Case											12 months
MPSC Approved Increase in Annual Gas Rates											19,900,000
Approved recovery of infrastructure recovery mechanism																								77,000,000
UETM Accrual for Over-Recovery																					20,000,000
Period over which approved UETM will be refunded																			12 months
RDM Application Proposed Recovery																						$ 5,200,000			$ 9,000,000
RDM Caps for First Reconciliation Period					1.125%
RDM Cap for Second Period Reconciliation					2.25%
Composite Depreciation Rates																					2.51%		2.29%

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Regulatory Matters (Schedule of Regulatory Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory Assets [Line Items]
Regulatory Assets	$ 2,863	$ 4,417
Regulatory Assets, Current	(26)	(182)
Regulatory Assets, Noncurrent	2,837	4,235
Securitized Regulatory Assets, Noncurrent	231	413
Pension Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	1,660	2,420
Postretirment Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	426
Asset Retirement Obligation Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	394	424
Recoverable Michigan Income Taxes [Member]
Regulatory Assets [Line Items]
Regulatory Assets	286	304
Recoverable Income Taxes related to Securitized Regulatory Assets [Member]
Regulatory Assets [Line Items]
Regulatory Assets	126	226
Cost to Achieve Performance Excellence Process [Member]
Regulatory Assets [Line Items]
Regulatory Assets	75	96
Other Recoverabe Income Taxes [Member]
Regulatory Assets [Line Items]
Regulatory Assets	71	76
Unamortized Loss on Reacquired Debt [Member]
Regulatory Assets [Line Items]
Regulatory Assets	63	63
Environmental Restoration Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	59	58
Enterprise Business Systems Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	13	16
Regulatory Clause Revenues, under-recovered [Member]
Regulatory Assets [Line Items]
Regulatory Assets	9	28
Choice Incentive Mechanism [Member]
Regulatory Assets [Line Items]
Regulatory Assets	3	66
Accrued PSCRandGCR Revenue [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	87
Recoverable Restoration Expense [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	49
Other Assets [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 104	$ 78

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Retirement Benefits and Trusteed Assets (Pension Plan - Fair Value Measurement using Level 3 Inputs) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	$ (1)	$ 58
Pension Plan, Defined Benefit [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	518	464
Realized gains (losses)	18	12
Unrealized gains (losses)	26	7
Purchases	31	283
Sales	(28)	(248)
Ending Balance	565	518
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	41	22
Pension Plan, Defined Benefit [Member] | Hedge Funds and Similar Investments [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	339	296
Realized gains (losses)	0	18
Unrealized gains (losses)	40	(5)
Purchases	16	250
Sales	0	(220)
Ending Balance	395	339
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	38	16
Pension Plan, Defined Benefit [Member] | Private Equity and Other [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	179	168
Realized gains (losses)	18	(6)
Unrealized gains (losses)	(14)	12
Purchases	15	33
Sales	(28)	(28)
Ending Balance	170	179
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	$ 3	$ 6

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Stock-Based Compensation (Stock based compensation by period) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 99	$ 83	$ 66
Tax benefit	38	33	25
Stock-based compensation cost capitalized in property, plant and equipment	$ 15	$ 5	$ 4

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Retirement Benefits and Trusteed Assets (Pension Plan - Assumptions used in Determining the PBO and Net Pension Costs) (Details) (Pension Plan, Defined Benefit [Member])	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plan, Defined Benefit [Member]
Assumptions Used to Determin Projected Benefit Obligations and Net Pension Costs [Line Items]
Assumptions Used Calculating Benefit Obligation, Discount Rate	4.95%	4.15%	5.00%
Assumptions Used Calculating Benefit Obligation, Rate of compensation increase	4.20%	4.20%	4.20%
Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.15%	5.00%	5.50%
Assumptions Used Calculating Net Periodic Benefit Cost, Rate of compensation increase	4.20%	4.20%	4.00%
Assumptions Used Calculating Net Periodic Benefit Cost, Expected long-term rate of return on plan assets	8.25%	8.25%	8.50%

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DEI Document (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Jan. 31, 2014	Jun. 30, 2013
Entity Registrant Name	DTE ENERGY CO
Entity Central Index Key	0000936340
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q4
Amendment Flag	false
Entity Common Stock, Shares Outstanding		177,086,236
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 11.7

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Retirement Benefits and Trusteed Assets (OPEB - Reconciliation of Obligations, Assets and Funded Status of Plans) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Change in Accumulated PostRetirement Benefit Obligation [Line Items]
Regulatory Liabilities	$ (1,164)	$ (1,120)
Regulatory Assets	2,863	4,417
Other Postretirement Benefit Plan, Defined Benefit [Member]
Change in Accumulated PostRetirement Benefit Obligation [Line Items]
Benefit obligation, beginning of year	2,315	2,470
Service cost	47	68	64
Interest cost	88	120	121
Plan amendments	(218)	(264)
Actuarial loss	(267)	5
Medicare Part D subsidy	1	6
Benefits paid	(88)	(90)
Benefit obligation, end of year	1,878	2,315	2,470
Defined Benefit Plan, Fair Value of Plan Assets	1,527	1,153	985
Actual return on plan assets	196	131
Company contributions	264	140
Benefits paid	(86)	(103)
Funded status of the plans	(351)	(1,162)
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	(1)	(2)
Noncurrent liabilities	(350)	(1,160)
Pension and Other Postretirement Defined Benefit Plans, Liabilities	(351)	(1,162)
Net actuarial loss recognized in other comprehensive loss	29	40
Prior service cost (credit) recognized in other comprehensive income	(10)	(14)
Net transition obligation	0	(1)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax	19	25
Net actuarial loss recognized in regulatory assets	321	727
Prior service cost recognized in regulatory assets	(393)	(302)
Net transition obligation	0	1
Regulatory Liabilities	(72)
Regulatory Assets		$ 426

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Asset Retirement Obligations (Notes)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

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

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

A reconciliation of the asset retirement obligations for 2013 follows:

	(In millions)
Asset retirement obligations at December 31, 2012	$	1,719
Accretion	106
Liabilities incurred	5
Liabilities settled	(13		)
Revision in estimated cash flows	10
Asset retirement obligations at December 31, 2013	$	1,827

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

In October 2011, the MPSC approved DTE Electric's request for a reduction to the nuclear decommissioning surcharge under the assumption that it would request an extension of the Fermi 2 license for an additional 20 years beyond the term of the existing license which expires in 2025. DTE Electric expects to request the license extension in 2014. This proposed extension of the license, including the associated impact on spent nuclear fuel, resulted in a revision in estimated cash flows for the Fermi 2 asset retirement obligation of approximately $22 million in 2011. It is estimated that the cost of decommissioning Fermi 2 is $1.6 billion in 2013 dollars and $10 billion in 2045 dollars, using a 6% inflation rate. Approximately $1.6 billion of the asset retirement obligations represent nuclear decommissioning liabilities that are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear plant.

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

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

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Acquisition (Details Textuals) (USD $)	3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012 facilities
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Number of Businesses Acquired		14
Business Combination, Consideration Transferred		$ 294,000,000
Business Combination, Payments to Acquire Businesses, Gross		220,000,000
Business Acquisition, Consideration Transferred, Other		74,000,000
Number of Project Companies Acquired Deemed VIEs that assumed Debt Relates		2
Exposure Loss Related to the Debt Assumed		0
Business Combination, Intangible assets		75,000,000
Amortization Years for Intangible Assets Acquired in a Business Combination		8 years
Revenues of Acquired Business Included in the Company's Consolidated Statement of Operations		30,000,000
Earnings of Acquired Business Included in the Company's Consolidated Statements of Operations		$ 2,000,000
The Period of the Acquired Project Companies Following the Closing included in Results of Operations	3 months
Minimum [Member]
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Equity Method Investment, Ownership Percentage		46.00%
Maximum [Member]
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Equity Method Investment, Ownership Percentage		100.00%

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Asset Retirement Obligations (Details Textuals) (USD $)	12 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2013	Mar. 31, 2011 Fermi 1 [Member]	Jun. 30, 2011 Fermi 1 [Member]	Dec. 31, 2011 Fermi 2 [Member]	Dec. 31, 2013 Fermi 2 [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligations, Liability Not Recognized	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.
Revision in estimated cash flows	$ 10,000,000	$ 19,000,000	$ 20,000,000	$ 22,000,000
Reserve and Impairment of Retirement Obligation			6,000,000
Proposed Extension of Nuclear Plant 2 License					20 years
Estimated decommissioning expenses, current fiscal year dollars					1,600,000,000
Estimated decommissioning expenses, end of extended license dollars					10,000,000,000
Inflation Rate Used to Determine Estimated Decommissioning Expenditures					6.00%
Nuclear Decommissioning Liabilities Funded Through Surcharge and Included In ARO Balance					1,600,000,000
Liabilities Balance upon Completion of Decommissioning	$ 0

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Consolidated Statements of Comprehensive Income (Parenthetical) (Parentheticals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Tax	$ 13	$ (1)	$ (5)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	0	0	0
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax	1	1	0
Other Comprehensive Income (Loss), Foreign Currency Translation Gain (Loss) Arising During Period, Tax	$ (1)	$ 0	$ 0

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Financial and Other Derivative Instruments (Notes)

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedges, Assets [Abstract]

Financial and Other Derivative Instruments

FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

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

The Company’s primary market risk exposure is associated with commodity prices, credit and interest rates. The Company has risk management policies to monitor and manage market risks. The Company uses derivative instruments to manage some of the exposure. The Company uses derivative instruments for trading purposes in its Energy Trading segment. Contracts classified as derivative instruments include power, natural gas, oil and certain coal forwards, futures, options and swaps, and foreign currency exchange contracts. Items not classified as derivatives include natural gas inventory, pipeline transportation contracts, renewable energy credits and natural gas storage assets.

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

Gas — DTE Gas purchases, stores, transports, distributes and sells natural gas and sells storage and transportation capacity. DTE Gas has fixed-priced contracts for portions of its expected gas supply requirements through 2016. Substantially all of these contracts meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. DTE Gas may also sell forward transportation and storage capacity contracts. Forward transportation and storage contracts are generally not derivatives and are therefore accounted for under the accrual method.

Gas Storage and Pipelines — This segment is primarily engaged in services related to the transportation and storage of natural gas. Primarily fixed-priced contracts are used in the marketing and management of transportation and storage services. Generally these contracts are not derivatives and are therefore accounted for under the accrual method.

Power and Industrial Projects — This segment manages and operates energy and pulverized coal projects, coke batteries, reduced emissions fuel projects, landfill gas recovery and power generation assets. Primarily fixed-price contracts are used in the marketing and management of the segment assets. These contracts are generally not derivatives and are therefore accounted for under the accrual method.

Energy Trading — Commodity Price Risk — Energy Trading markets and trades electricity, coal, natural gas physical products and energy financial instruments, and provides energy and asset management services utilizing energy commodity derivative instruments. Forwards, futures, options and swap agreements are used to manage exposure to the risk of market price and volume fluctuations in its operations. These derivatives are accounted for by recording changes in fair value to earnings unless hedge accounting criteria are met.

Energy Trading — Foreign Currency Exchange Risk — Energy Trading has foreign currency exchange forward contracts to economically hedge fixed Canadian dollar commitments existing under natural gas and power purchase and sale contracts and natural gas transportation contracts. The Company enters into these contracts to mitigate price volatility with respect to fluctuations of the Canadian dollar relative to the U.S. dollar. These derivatives are accounted for by recording changes in fair value to earnings unless hedge accounting criteria are met.

Corporate and Other — Interest Rate Risk — The Company uses interest rate swaps, treasury locks and other derivatives to hedge the risk associated with interest rate market volatility. In 2004 and 2000, the Company entered into a series of interest rate derivatives to limit its sensitivity to market interest rate risk associated with the issuance of long-term debt. Such instruments were designated as cash flow hedges. The Company subsequently issued long-term debt and terminated these hedges at a cost that is included in Other comprehensive loss. Amounts recorded in Other comprehensive loss will be reclassified to interest expense through 2033. In 2014, the Company estimates reclassifying less than $1 million of losses to earnings.

Credit Risk — The utility and non-utility businesses are exposed to credit risk if customers or counterparties do not comply with their contractual obligations. The Company maintains credit policies that significantly minimize overall credit risk. These policies include an evaluation of potential customers’ and counterparties’ financial condition, credit rating, collateral requirements or other credit enhancements such as letters of credit or guarantees. The Company generally uses standardized agreements that allow the netting of positive and negative transactions associated with a single counterparty. The Company maintains a provision for credit losses based on factors surrounding the credit risk of its customers, historical trends, and other information. Based on the Company’s credit policies and its December 31, 2013 and 2012 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to have a material adverse effect on the Company’s financial statements.

Derivative Activities

The Company manages its mark-to-market (MTM) risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, it records and manages the energy purchase and sale obligations under its contracts in separate components based on the commodity (e.g. electricity or 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 following describes the categories of activities represented by their operating characteristics and key risks:

• Asset Optimization — Represents derivative activity associated with assets owned and contracted by DTE Energy, including forward natural gas purchases and sales, natural gas transportation and storage capacity. Changes in the value of derivatives in this category typically economically offset changes in the value of underlying non-derivative positions, which do not qualify for fair value accounting. The difference in accounting treatment of derivatives in this category and the underlying non-derivative positions can result in significant earnings volatility.

• Marketing and Origination — Represents derivative activity transacted by originating substantially hedged positions with wholesale energy marketers, producers, end users, utilities, retail aggregators and alternative energy suppliers.

• Fundamentals Based Trading — Represents derivative activity transacted with the intent of taking a view, capturing market price changes, or putting capital at risk. This activity is speculative in nature as opposed to hedging an existing exposure.

• Other — Includes derivative activity at DTE Electric related to FTRs. Changes in the value of derivative contracts at DTE Electric are recorded as Derivative Assets or Liabilities, with an offset to Regulatory Assets or Liabilities as the settlement value of these contracts will be included in the PSCR mechanism when realized.

The following tables present the fair value of derivative instruments as of December 31, 2013 and 2012:

	December 31, 2013					December 31, 2012
	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	—		$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	—	$	(1	)	$	—	$	—
Commodity Contracts:
Natural Gas	396		(503		)	645		(661		)
Electricity	400		(398		)	360		(351		)
Other	37		(34		)	11		(7		)
Total derivatives not designated as hedging instruments:	$	833	$	(936	)	$	1,016	$	(1,019	)
Total derivatives:
Current	$	691	$	(773	)	$	862	$	(879	)
Noncurrent	142		(163		)	154		(141		)
Total derivatives	$	833	$	(936	)	$	1,016	$	(1,020	)

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.

For contracts with certain clearing agents the fair value of derivative instruments is netted against realized positions with the net balance reflected as either 1) a derivative asset or liability or 2) an account receivable or payable. Other than certain clearing agents, accounts receivable and accounts payable that are subject to netting arrangements have not been offset against the fair value of derivative assets and liabilities. Certain contracts that have netting arrangements have not been offset in the Consolidated Statements of Financial Position. The impact of netting these derivative instruments and cash collateral related to such contracts is not material. Only the gross amounts for these derivative instruments are included in the table below.

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 following table presents the netting offsets of derivative assets and liabilities at December 31, 2013 and 2012:

	December 31, 2013									December 31, 2012
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position			Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position
	(In millions)
Derivative assets:
Commodity Contracts:
Natural Gas	$	396		$	(382	)	$	14		$	645		$	(605	)	$	40
Electricity	400			(291		)	109			360			(258		)	102
Other	37			(34		)	3			11			(6		)	5
Total derivative assets	$	833		$	(707	)	$	126		$	1,016		$	(869	)	$	147
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(503	)	$	395		$	(108	)	$	(661	)	$	605		$	(56	)
Electricity	(398		)	269			(129		)	(351		)	258			(93		)
Other	(34		)	34			—			(7		)	6			(1		)
Other derivative liabilities	(1		)	—			(1		)	(1		)	—			(1		)
Total derivative liabilities	$	(936	)	$	698		$	(238	)	$	(1,020	)	$	869		$	(151	)

The following table presents the netting offsets of derivative assets and liabilities at December 31, 2013 and 2012:

	December 31, 2013												December 31, 2012
	Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent			Current			Noncurrent			Current			Noncurrent
	(In millions)
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	691		$	142		$	(773	)	$	(163	)	$	862		$	154		$	(879	)	$	(141	)
Counterparty netting	(566		)	(115		)	566			115			(754		)	(115		)	754			115
Collateral adjustment	(26		)	—			12			5			—			—			—			—
Total derivatives as reported	$	99		$	27		$	(195	)	$	(43	)	$	108		$	39		$	(125	)	$	(26	)

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

	Location of Gain (Loss) Recognized in Income on Derivatives	Gain (Loss) Recognized in Income on Derivatives for Years Ended December 31
Derivatives not Designated as Hedging Instruments		2013			2012
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	(1	)	$	—
Commodity Contracts:
Natural Gas	Operating Revenue	(48		)	(29		)
Natural Gas	Fuel, purchased power and gas	(44		)	25
Electricity	Operating Revenue	82			64
Other	Operating Revenue	—			5
Total		$	(11	)	$	65

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.

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

Commodity	Number of Units
Natural Gas (MMBtu)	795,553,773
Electricity (MWh)	55,658,483
Foreign Currency Exchange ($ CAD)	65,074,206
FTR (MWh)	10,485,618

Various 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, 2013, DTE Energy's contractual obligation in the form of cash or letter of credit in the event of a downgrade to below investment grade, under both hard trigger and soft trigger provisions, was approximately $406 million.

As of December 31, 2013, the Company had approximately $1,176 million of derivatives in net liability positions, for which hard triggers exist. Collateral of approximately $25 million has been posted against such liabilities, including cash and letters of credit. Associated derivative net asset positions for which contractual offset exists were approximately $902 million. The net remaining amount of approximately $249 million is derived from the $406 million noted above.

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Fair Value (Notes)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value

FAIR VALUE

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

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

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

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

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

	December 31, 2013															December 31, 2012
	Level 1			Level 2			Level 3			Netting (a)			Net Balance			Level 1			Level 2			Level 3			Netting (a)			Net Balance
	(In millions)
Assets:
Cash equivalents (b)	$	10		$	115		$	—		$	—		$	125		$	—		$	123		$	—		$	—		$	123
Nuclear decommissioning trusts	779			412			—			—			1,191			694			343			—			—			1,037
Other investments (c) (d)	92			44			—			—			136			66			44			—			—			110
Derivative assets:
Commodity Contracts:
Natural Gas	273			89			34			(382		)	14			555			66			24			(605		)	40
Electricity	—			261			139			(291		)	109			—			226			134			(258		)	102
Other	33			1			3			(34		)	3			6			3			2			(6		)	5
Total derivative assets	306			351			176			(707		)	126			561			295			160			(869		)	147
Total	$	1,187		$	922		$	176		$	(707	)	$	1,578		$	1,321		$	805		$	160		$	(869	)	$	1,417
Liabilities:
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(277	)	$	(140	)	$	(86	)	$	395		$	(108	)	$	(526	)	$	(73	)	$	(62	)	$	605		$	(56	)
Electricity	—			(272		)	(126		)	269			(129		)	—			(240		)	(111		)	258			(93		)
Other	(32		)	(2		)	—			34			—			(6		)	(1		)	—			6			(1		)
Other derivative contracts (f)	—			(1		)	—			—			(1		)	—			(1		)	—			—			(1		)
Total derivative liabilities	(309		)	(415		)	(212		)	698			(238		)	(532		)	(315		)	(173		)	869			(151		)
Total	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)
Net Assets (liabilities) at the end of the period	$	878		$	507		$	(36	)	$	(9	)	$	1,340		$	789		$	490		$	(13	)	$	—		$	1,266
Assets:
Current	$	277		$	400		$	139		$	(592	)	$	224		$	493		$	372		$	120		$	(754	)	$	231
Noncurrent (e)	910			522			37			(115		)	1,354			828			433			40			(115		)	1,186
Total Assets	$	1,187		$	922		$	176		$	(707	)	$	1,578		$	1,321		$	805		$	160		$	(869	)	$	1,417
Liabilities:
Current	$	(268	)	$	(328	)	$	(177	)	$	578		$	(195	)	$	(466	)	$	(269	)	$	(144	)	$	754		$	(125	)
Noncurrent	(41		)	(87		)	(35		)	120			(43		)	(66		)	(46		)	(29		)	115			(26		)
Total Liabilities	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)
Net Assets (liabilities) at the end of the period	$	878		$	507		$	(36	)	$	(9	)	$	1,340		$	789		$	490		$	(13	)	$	—		$	1,266

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(a) Amounts represent the impact of master netting agreements that allow the Company to net gain and loss positions and cash collateral held or placed with the same counterparties.

(b) At December 31, 2013, available-for-sale securities of $125 million included $109 million and $16 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively. At December 31, 2012, available-for-sale securities of $123 million, included $109 million and $14 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively.

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

(d) Available-for-sale equity securities of $7 million at December 31, 2013 and $5 million at December 31, 2012 are included in Other investments on the Consolidated Statements of Financial Position.

(e) Includes $136 million and $110 million of Other investments that are included in the Consolidated Statements of Financial Position in Other investments at December 31, 2013 and 2012, respectively.

(f) Includes Interest rate contracts and Foreign currency exchange contracts.

Cash Equivalents

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

Nuclear Decommissioning Trusts and Other Investments

The nuclear decommissioning trusts and other investments hold debt and equity securities directly and indirectly through institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices in actively traded markets. The 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 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 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 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

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, 2013 and 2012:

	Year Ended December 31, 2013												Year Ended December 31, 2012
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of December 31	$	(38	)	$	23		$	2		$	(13	)	$	6		$	32		$	6		$	44
Transfers into Level 3	1			—			—			1			1			—			—			1
Total gains (losses):
Included in earnings	(32		)	75			—			43			(41		)	101			—			60
Recorded in regulatory assets/liabilities	—			—			5			5			—			—			15			15
Purchases, issuances and settlements:
Purchases	(8		)	1			—			(7		)	—			2			—			2
Issuances	—			(1		)	—			(1		)	—			—			—			—
Settlements	25			(85		)	(4		)	(64		)	(4		)	(112		)	(19		)	(135		)
Net Assets (Liabilities) as of December 31	$	(52	)	$	13		$	3		$	(36	)	$	(38	)	$	23		$	2		$	(13	)
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at December 31, 2013 and 2012 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(49	)	$	48		$	—		$	(1	)	$	(33	)	$	91		$	—		$	58

Derivatives are transferred between levels primarily due to changes in the source data used to construct price curves as a result of changes in market liquidity. Transfers in and transfers out are reflected as if they had occurred at the beginning of the period. The following table shows transfers between the levels of the fair value hierarchy for the years ended December 31, 2013 and 2012:

	Year Ended December 31, 2013					Year Ended December 31, 2012
	Level 1	Level 2		Level 3		Level 1	Level 2		Level 3
	(In millions)
Transfers into Level 1 from	$ N/A	$	—	$	—	$ N/A	$	—	$	—
Transfers into Level 2 from	—	N/A		—		—	N/A		—
Transfers into Level 3 from	—	1		N/A		—	1		N/A

The following table presents the unobservable inputs related to Level 3 assets and liabilities as of December 31, 2013 and 2012:

	December 31, 2013
Commodity Contracts	Derivative Assets		Derivative Liabilities			Valuation Techniques	Unobservable Input	Range							Weighted Average
	(In millions)
Natural Gas	$	34	$	(86	)	Discounted Cash Flow	Forward basis price (per MMBtu)	$	(0.88	)	—	$	5.07	/MMBtu	$	(0.16	)/MMBtu
Electricity	$	139	$	(126	)	Discounted Cash Flow	Forward basis price (per MWh)	$	(7	)	—	$	15	/MWh	$	3	/MWh

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

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

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

Fair Value of Financial Instruments

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

The following table presents the carrying amount and fair value of financial instruments as of December 31, 2013 and 2012:

	December 31, 2013								December 31, 2012
	Carrying		Fair Value						Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Amount		Level 1		Level 2		Level 3
	(In millions)
Notes receivable, excluding capital leases	$	41	$	—	$	—	$	41	$	39	$	—	$	—	$	39
Dividends payable	$	116	$	116	$	—	$	—	$	107	$	107	$	—	$	—
Short-term borrowings	$	131	$	—	$	131	$	—	$	240	$	—	$	240	$	—
Long-term debt	$	8,094	$	425	$	7,551	$	499	$	7,813	$	507	$	7,453	$	933

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

Nuclear Decommissioning Trust Funds

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

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

	December 31, 2013		December 31, 2012
	(In millions)
Fermi 2	$	1,172	$	1,021
Fermi 1	3		3
Low level radioactive waste	16		13
Total	$	1,191	$	1,037

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

	Year Ended December 31
	2013			2012			2011
	(In millions)
Realized gains	$	83		$	37		$	46
Realized losses	$	(41	)	$	(31	)	$	(38	)
Proceeds from sales of securities	$	1,118		$	759		$	833

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

	December 31, 2013				December 31, 2012
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
	(In millions)
Equity securities	$	730	$	201	$	631	$	122
Debt securities	442		12		399		27
Cash and cash equivalents	19		—		7		—
	$	1,191	$	213	$	1,037	$	149

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.

Unrealized losses incurred by the Fermi 2 trust are recognized as a Regulatory asset. DTE Electric recognized $31 million and $44 million of unrealized losses as Regulatory assets at December 31, 2013 and 2012, respectively. Since the decommissioning of Fermi 1 is funded by DTE Electric rather than through a regulatory recovery mechanism, there is no corresponding regulatory asset treatment. Therefore, unrealized losses incurred by the Fermi 1 trust are recognized in earnings immediately. There were no unrealized losses recognized in 2013, 2012 and 2011 for Fermi 1.

Other Securities

At December 31, 2013 and 2012, the securities were comprised primarily of money-market and equity securities. During the years ended December 31, 2013 and 2012, no amounts of unrealized losses on available-for-sale securities were reclassified out of other comprehensive income and realized into net income for the periods. Gains related to trading securities held at December 31, 2013, 2012, and 2011 were $22 million, $11 million and $4 million, respectively.

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Supplementary Quarterly Financial Information (Unaudited) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]
Operating Revenue	$ 2,533	$ 2,387	$ 2,225	$ 2,516	$ 2,349	$ 2,190	$ 2,013	$ 2,239	$ 9,661	$ 8,791	$ 8,858
Operating Income (Loss)	241	329	223	410	267	406	294	312	1,203	1,279	1,421
Income (Loss) from Continuing Operations Attributable to Parent					137	226	147	156		666
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent					(56)	1	(1)	0	0	(56)	(3)
Net Income Attributable to DTE Energy Company	$ 124	$ 198	$ 105	$ 234	$ 81	$ 227	$ 146	$ 156	$ 661	$ 610	$ 711
Income (Loss) from Continuing Operations, Per Basic Share					$ 0.79	$ 1.31	$ 0.87	$ 0.91	$ 3.76	$ 3.89	$ 4.21
Income (Loss) from Discontinued Operations, Net of Tax, Per Basic Share					$ (0.32)	$ 0.01	$ (0.01)	$ 0.00	$ 0.00	$ (0.33)	$ (0.02)
Total Basic Earnings per Common Share	$ 0.70	$ 1.13	$ 0.60	$ 1.35	$ 0.47	$ 1.32	$ 0.86	$ 0.91	$ 3.76	$ 3.56	$ 4.19
Income (Loss) from Continuing Operations, Per Diluted Share					$ 0.79	$ 1.30	$ 0.87	$ 0.91	$ 3.76	$ 3.88	$ 4.20
Income (Loss) from Discontinued Operations, Net of Tax, Per Diluted Share					$ (0.32)	$ 0.01	$ (0.01)	$ 0	$ 0.00	$ (0.33)	$ (0.02)
Total Diluted Earnings per Common Share	$ 0.70	$ 1.13	$ 0.60	$ 1.34	$ 0.47	$ 1.31	$ 0.86	$ 0.91	$ 3.76	$ 3.55	$ 4.18

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Long-Term Debt (Notes)

12 Months Ended

Dec. 31, 2013

Long-term Debt, Unclassified [Abstract]

Long-Term Debt

LONG-TERM DEBT

Long-Term Debt

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

	2013			2012
	(In millions)
Mortgage bonds, notes, and other
DTE Energy Debt, Unsecured
6.1% due 2014 to 2033	$	1,297		$	1,298
DTE Electric Taxable Debt, Principally Secured
4.7% due 2014 to 2043	4,286			3,777
DTE Electric Tax-Exempt Revenue Bonds (b)
5.1% due 2014 to 2036	558			707
DTE Gas Taxable Debt, Principally Secured
5.6% due 2014 to 2042	1,029			919
Other Long-Term Debt, Including Non-Recourse Debt	142			153
	7,312			6,854
Less amount due within one year	(694		)	(634		)
	$	6,618		$	6,220
Securitization bonds
6.6% due 2015	$	302		$	479
Less amount due within one year	(197		)	(177		)
	$	105		$	302
Junior Subordinated Debentures
6.5% due 2061	$	280		$	280
5.25% due 2062	200			200
	$	480		$	480

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(a) Weighted average interest rates as of December 31, 2013 are shown below the description of each category of debt.

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

Debt Issuances

In 2013, the following debt was issued:

Company	Month Issued	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March	Mortgage Bonds (a)	4.00	%	2043	$	375
DTE Electric	August	Mortgage Bonds (a)	3.65	%	2024	400
DTE Energy	November	Senior Notes (a)	3.85	%	2023	300
DTE Gas	December	Mortgage Bonds (a)	3.64	%	2023	50
DTE Gas	December	Mortgage Bonds (a)	3.74	%	2025	70
DTE Gas	December	Mortgage Bonds (a)	3.94	%	2028	50
						$	1,245

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

Debt Redemptions

In 2013, the following debt was redeemed:

Company	Month	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March	Securitization Bonds	6.42	%	2013	$	88
DTE Electric	March	Tax Exempt Revenue Bonds (a)	5.30	%	2030	51
DTE Electric	April	Other Long-Term Debt	Various		2013	13
DTE Gas	April	Senior Notes	5.26	%	2013	60
DTE Energy	June	Senior Notes	Variable		2013	300
DTE Electric	September	Securitization Bonds	6.62	%	2013	89
DTE Electric	September	Senior Notes	6.40	%	2013	250
DTE Electric	December	Tax Exempt Revenue Bonds (a)	5.50	%	2030	49
DTE Electric	December	Tax Exempt Revenue Bonds (a)	6.75	%	2038	50
DTE Energy	Various	Other Long-Term Debt	Various		2013	11
						$	961

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

The following table shows the scheduled debt maturities:

	2014		2015		2016		2017		2018		2019 and Thereafter		Total
	(In millions)
Amount to mature	$	891	$	476	$	465	$	9	$	407	$	5,846	$	8,094

Junior Subordinated Debentures

At December 31, 2013, the Company had $280 million of 6.5% Junior Subordinated Debentures due 2061 and $200 million of 5.25% Junior Subordinated Debentures due 2062. The Company has the right to defer interest payments on the debt securities. Should the Company exercise this right, it cannot declare or pay dividends on, or redeem, purchase or acquire, any of its capital stock during the deferral period. Any deferred interest payments will bear additional interest at the rate associated with the related debt issue.

Cross Default Provisions

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

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Regulatory Matters (Notes)

12 Months Ended

Dec. 31, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Matters

REGULATORY MATTERS

Regulation

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

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

Regulatory Assets and Liabilities

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

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

	2013			2012
	(In millions)
Assets
Recoverable pension and other postretirement costs:
Pension	$	1,660		$	2,420
Other postretirement costs	—			426
Asset retirement obligation	394			424
Recoverable Michigan income taxes	286			304
Recoverable income taxes related to securitized regulatory assets	126			226
Cost to achieve Performance Excellence Process	75			96
Other recoverable income taxes	71			76
Unamortized loss on reacquired debt	63			63
Deferred environmental costs	59			58
Enterprise Business Systems costs	13			16
Recoverable revenue decoupling	9			28
Choice incentive mechanism	3			66
Accrued PSCR/GCR revenue	—			87
Recoverable restoration expense	—			49
Other	104			78
	2,863			4,417
Less amount included in current assets	(26		)	(182		)
	$	2,837		$	4,235
Securitized regulatory assets	$	231		$	413

	2013			2012
	(In millions)
Liabilities
Asset removal costs	$	351		$	439
Renewable energy	277			230
Refundable revenue decoupling/deferred gain	127			127
Negative pension offset	84			105
Over recovery of Securitization	72			54
Refundable other postretirement costs	72			—
Accrued PSCR/GCR	65			16
Refundable income taxes	45			56
Energy optimization	31			34
Fermi 2 refueling outage	26			12
Refundable uncollectible expense	12			37
Other	2			10
	$	1,164		$	1,120
Less amount included current liabilities	(302		)	(89		)
	$	862		$	1,031

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

ASSETS

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

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

• Recoverable Michigan income taxes— In July 2007, the Michigan Business Tax (MBT) was enacted by the State of Michigan. State deferred tax liabilities were established for the Company’s utilities, and offsetting regulatory assets were recorded as the impacts of the deferred tax liabilities will be reflected in rates as the related taxable temporary differences reverse and flow through current income tax expense. In May 2011, the MBT was repealed and the Michigan Corporate Income Tax (MCIT) was enacted. The regulatory asset was remeasured to reflect the impact of the MCIT tax rate. (a)

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

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

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

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

• Deferred environmental costs — The MPSC approved the deferral of investigation and remediation costs associated with DTE Gas's former MGP sites. Amortization of deferred costs is over a ten-year period beginning in the year after costs were incurred, with recovery (net of any insurance proceeds) through base rate filings. (a)

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

• Recoverable revenue decoupling — Amounts recoverable from DTE Gas customers for the change in revenue resulting from the difference in weather-adjusted average sales per customer compared to the base level of average sales per customer established by the MPSC. The December 2012 order in DTE Gas's rate case required the RDM be discontinued effective November 1, 2012. The order provided for a new RDM, which began in November 2013.

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

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

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

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

_________________________________

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

LIABILITIES

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

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

• Refundable revenue decoupling / deferred gain — Amounts were originally accrued as refundable to DTE Electric customers for the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established by the MPSC. In 2012, the Michigan Court of Appeals issued a decision reversing the MPSC's decision to authorize a RDM for DTE Electric. The revenue decoupling liability was reversed and, after receiving an order from the MPSC to defer the resulting gain for future amortization, DTE Electric created a regulatory liability representing its obligation to refund the gain. The deferred gain will be amortized into earnings in 2014.

• Negative pension offset — DTE Gas's negative pension costs are not included as a reduction to its authorized rates; therefore, the Company is accruing a regulatory liability to eliminate the impact on earnings of the negative pension expense accrued. This regulatory liability will reverse to the extent DTE Gas’s pension expense is positive in future years.

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

• Refundable other postretirement costs — Accounting rules for other postretirement benefit costs require, among other things, the recognition in other comprehensive income of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. DTE Electric and DTE Gas record the favorable impact of actuarial gains or losses and prior service credits as a regulatory liability since the impact will reduce expense in a future rate setting process as the deferred items are recognized as a component of net periodic benefit costs.

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

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

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

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

• Refundable uncollectible expense (UETM) — DTE Electric and DTE Gas liability for the MPSC approved uncollectible expense tracking mechanism that tracks the difference in the fluctuation in uncollectible accounts and amounts recognized pursuant to the MPSC authorization. The UETM was terminated for DTE Electric in the October 20, 2011 MPSC rate case order and terminated for DTE Gas in the December 20, 2012 MPSC approval of the partial settlement agreement.

2009 Electric Rate Case Filing - Court of Appeals Decision

In April 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. The COA found that the record of evidence in the January 2010 rate order was insufficient to support the MPSC's authorization to recover costs for the advanced metering infrastructure (AMI) program and remanded this matter to the MPSC. On October 17, 2013, the MPSC issued an order affirming the approximately $8 million rate increase authorized in the MPSC's January 2010 rate order for the AMI program and further concluded that the evidence presented after remand supports the authorized cost recovery.

2010 Electric Rate Case Filing - Court of Appeals Decision

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 AMI program and remanded this matter to the MPSC. The MPSC had approved an approximately $11 million rate increase related to the AMI program in the October 2011 order. DTE Electric is currently operating its AMI program pursuant to the MPSC's approval set forth in the October 2011 order. On August 29, 2013, the MPSC reopened the 2010 electric rate case for the limited purpose of addressing the COA's opinion on AMI. The Company is unable to predict the outcome of this matter or the timing of its resolution.

Transition of the City of Detroit's Public Lighting Department's (PLD) Customers to DTE Electric's Distribution System

Accounting Authority

On June 28, 2013, DTE Electric filed an application for accounting authority to defer certain costs associated with the transition of the City of Detroit's PLD customers to the DTE Electric distribution system over a five to seven year system conversion period. The Company requested authority to defer as a regulatory asset, all net incremental revenue requirement associated with the transition. The net incremental revenue requirement includes costs to install meters and attach customers; system and customer facility upgrades and repairs; and the difference between DTE Electric's tariff rates and any transitional rates approved in the future. On July 11, 2013, the MPSC approved DTE Electric's request to defer, for accounting purposes, the net incremental revenue requirement.

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 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.

Transitional Reconciliation Mechanism (TRM)

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 be requesting recovery, in subsequent PSCR cases, of PLD transmission delivery service costs incurred while DTE Electric 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 recoverable in the PSCR, the Company requested recovery as part of the TRM.

Energy Optimization (EO) Plans

The EO plan is designed to help 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 2013, DTE Electric and DTE Gas filed separate applications for approval of their respective reconciliations of their 2012 EO plan expenses. DTE Electric’s EO reconciliation included a cumulative $26 million net over-recovery and DTE Gas’s EO reconciliation included a cumulative $7 million net over-recovery for their 2012 EO plans. DTE Electric and DTE Gas proposed that the calculated over-recoveries for 2012 be carried forward into 2013 and used as beginning balances for the 2013 reconciliations. On December 6, 2013, the MPSC approved settlement agreements of the DTE Electric and DTE Gas 2012 EO reconciliations that carried forward to 2013 the 2012 over-recoveries. In addition, the MPSC authorized performance incentive surcharges, over a 12-month period effective January 1, 2014, of approximately $10 million and $4 million for DTE Electric and DTE Gas, respectively.

In July 2013, DTE Electric and DTE Gas filed separate applications with the MPSC for the biennial review of their EO plans. On December 19, 2013, the MPSC approved settlement agreements for the EO plans of DTE Electric and DTE Gas.

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

In January 2012, DTE Electric filed an application with the MPSC for approval of the reconciliation of its 2011 RETM and LCT. The Company's 2011 restoration expenses were higher than the amount provided in rates. Accordingly, DTE Electric requested net recovery of approximately $44 million. On February 28, 2013, the MPSC approved a settlement agreement and authorized a $44 million net surcharge to recover the costs over a three-month period beginning April 1, 2013.

DTE Electric Uncollectible Expense True-Up Mechanism (UETM)

In February 2012, DTE Electric filed an application with the MPSC for approval of its UETM for 2011 requesting authority to refund approximately $9 million consisting of costs related to 2011 uncollectible expense. On February 28, 2013, the MPSC approved a settlement agreement and authorized a $9 million credit to refund the over-recovery over a one month period beginning April 1, 2013.

Low Income Energy Assistance Fund (LIEAF)

On July 1, 2013, Michigan Public Act 95 was signed into law and created the LIEAF. The legislation allows the use of a LIEAF funding factor to be determined by the MPSC and assessed on all customer classes of Michigan electric utilities to fund the LIEAF. On July 29, 2013, the MPSC adopted a funding factor of $0.99 per meter per month for all Michigan electric utilities that are participating in the program, including DTE Electric, effective with the September 2013 billing month. The surcharge billed by DTE Electric is remitted to the State of Michigan for subsequent distribution through a grant process to social service agencies and utilities to assist low income customers.

Renewable Energy Plan (REP)

In June 2013, DTE Electric filed an application for the biennial review and approval of its amended REP with the MPSC requesting authority to reduce its annual surcharge revenue recovery from approximately $100 million to $15 million. The proposed level is appropriate to continue to properly implement DTE Electric’s 20-year REP, designed to deliver cleaner, renewable electric generation to its customers, to further diversify DTE Electric’s and the State of Michigan’s sources of electric supply, and to address the state and national goals of increasing energy independence. On December 19, 2013, the MPSC approved DTE Electric’s amended REP.

Power Supply Cost Recovery Proceedings

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

2010 PSCR Year - On April 25, 2013, the MPSC approved the 2010 PSCR net under-recovery of $52.6 million and the recovery of this amount as part of the 2011 PSCR reconciliation. The order also approved DTE Electric's Pension Equalization Mechanism reconciliation and authorized a one month surcharge in June 2013 and approved the recovery of the over-refund of the self-implemented rate increase related to the 2009 electric rate case filing as part of the 2011 PSCR reconciliation.

2012 PSCR Year - In March 2013, DTE Electric filed the 2012 PSCR reconciliation calculating a net under-recovery of approximately $87 million that includes an under-recovery of approximately $148 million for the 2011 PSCR year. The reconciliation includes purchased power costs related to the manual shutdown of our Fermi 2 nuclear power plant in June 2012 caused by the failure of one of the plant's two non-safety related feed-water pumps. The plant was restarted on July 30, 2012, which restored production to nominal 68% of full capacity. In September 2013, the repair to the plant was completed and production was returned to full capacity. DTE Electric was able to purchase sufficient power from MISO to continue to provide uninterrupted service to our customers. Certain intervenors in the reconciliation case have challenged the recovery of up to $32 million of the Fermi-related purchased power costs. Resolution of this matter is expected in 2014.

2012 Gas Rate Case Filing

DTE Gas filed a rate case on April 20, 2012 based on a projected test year for the twelve-month period ending October 31, 2013. On December 20, 2012, the MPSC approved a partial settlement agreement and authorized the Company to increase its annual gas revenues by $19.9 million for service rendered on and after January 1, 2013. The partial settlement agreement did not resolve the proposal for an infrastructure recovery mechanism (IRM) designed to recover DTE Gas' projected costs over a five-year period related to its gas main renewal, pipeline integrity and meter move out programs. On April 16, 2013, the MPSC issued an order approving the IRM and authorized the recovery of the cost of service related to $77 million of annual investment in the programs beginning in May 2013. The IRM will adjust annually in July for the incremental investment each year, after a limited hearing on the reconciliation of the prior year capital expenditures. When DTE Gas files a rate case, all capital invested as part of the IRM will be rolled into rate base and recovery would continue through base rates as part of a base rate case filing. As part of any future rate case, DTE Gas may propose to implement an updated IRM to address the recovery of future infrastructure investments.

DTE Gas UETM

In March 2013, DTE Gas filed an application with the MPSC for approval of its UETM reconciliation for 2012 requesting authority to refund approximately $20 million. On September 10, 2013, the MPSC approved a settlement agreement approving the requested 2012 UETM refund over a twelve-month period beginning in October 2013.

DTE Gas Revenue Decoupling Mechanism (RDM)

In October 2012, DTE Gas filed an application with the MPSC for approval of its RDM reconciliation for the period July 1, 2011 through June 30, 2012. The application requests authority to adjust existing retail gas rates so as to collect a net amount of approximately $9 million, plus interest. On March 15, 2013, the MPSC approved a settlement agreement and authorized the implementation of surcharges during the billing months of April 2013 through March 2014.

In May 2013, DTE Gas filed an application with the MPSC for approval of its RDM reconciliation for the period July 1, 2012 through October 31, 2012. DTE Gas's RDM application proposed the recovery of a net under-recovery of approximately $5.2 million. On November 14, 2013, the MPSC approved a settlement agreement and authorized the implementation of surcharges during the billing months of December 2013 through March 2014.

The December 2012 order in DTE Gas's rate case required the RDM be discontinued effective November 1, 2012. The order also provided for a new RDM for the period November 1, 2013 through October 31, 2014. The new RDM decouples weather normalized distribution revenue inside caps. The caps are tied to expected conservation targets: 1.125% in the first reconciliation period and 2.25% for the second and future periods.

DTE Gas Depreciation Filing

In compliance with an MPSC order, DTE Gas filed a depreciation case in June 2012. On May 15, 2013, the MPSC approved a settlement agreement increasing DTE Gas’s composite depreciation rates from 2.29% to 2.51%, effective on the same date as the MPSC-approved rates are effective in DTE Gas’s next general rate case. The Company cannot predict when DTE Gas will file its next rate case.

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Property, Plant and Equipment (Summary of Property by Classification) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Non-utility and other	$ 2,292	$ 1,960
Property, plant and equipment, Total	25,123	23,631
Less Accumulated Depreciation, Depletion and Amortization - Nonutility and Other	(767)	(676)
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	(9,323)	(8,947)
Property, plant and equipment	15,800	14,684
Electric Generation Equipment [Member]
Property, Plant and Equipment [Line Items]
Property Plant and Equipment - Generation	11,127	10,383
Less Accumulated Depreciation, Depletion and Amortization - Generation	(4,004)	(3,880)
Electric Distribution [Member]
Property, Plant and Equipment [Line Items]
Property Plant and Equipment - Distribution	7,603	7,306
Less Accumulated Depreciation, Depletion and Amortization - Distribution	(2,947)	(2,837)
Electric Generation, Transmission and Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Plant in Service	18,730	17,689
Total Utility Accumulated Depreciation, Depletion and Amortization	(6,951)	(6,717)
Gas Distribution [Member]
Property, Plant and Equipment [Line Items]
Property Plant and Equipment - Distribution	2,834	2,704
Less Accumulated Depreciation, Depletion and Amortization - Distribution	(1,129)	(1,057)
Storage [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Storage	431	426
Less Accumulated Depreciation, Depletion and Amortization - Storage	(138)	(132)
Other [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Other	836	852
Less Accumulated Depreciation, Depletion and Amortization - Other	(338)	(365)
Gas Distribution and Storage [Member]
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Plant in Service	4,101	3,982
Total Utility Accumulated Depreciation, Depletion and Amortization	$ (1,605)	$ (1,554)

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Discontinued Operations (Notes)

12 Months Ended

Dec. 31, 2013

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

DISCONTINUED OPERATIONS

Sale of Unconventional Gas Production Business

In December 2012, the Company sold its 100% equity interest in its Unconventional Gas Production business which consisted of gas and oil production assets in the western Barnett and Marble Falls shale areas of Texas. The sale resulted in gross proceeds of approximately $255 million, which resulted in a pre-tax loss of approximately $83 million ($55 million after tax). The activity of the discontinued business is shown below. The amounts exclude general corporate overhead costs, and related tax effects, and no portion of corporate interest costs were allocated to discontinued operations.

	2012			2011
	(In millions)
Operating Revenues	$	55		$	39
Operation and Maintenance	24			16
Depreciation, Depletion and Amortization	23			18
Taxes Other Than Income	4			3
Asset (Gains) and Losses, Net	83			—
	134			37
Operating Income (Loss)	(79		)	2
Other (Income) and Deductions	6			6
Loss Before Income Taxes	(85		)	(4		)
Income Tax Expense (Benefit)	(29		)	(1		)
Net Loss Attributable to DTE Energy Company	$	(56	)	$	(3	)

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Significant Accounting Policies (Accumulated Other Comprehensive Income (Loss)) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (158)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	13
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	9
Other Comprehensive Income (Loss), Net of Tax	22	0	(9)
Accumulated Other Comprehensive Income (Loss), Net of Tax	(136)	(158)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax	(4)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0
Other Comprehensive Income (Loss), Net of Tax	0
Accumulated Other Comprehensive Income (Loss), Net of Tax	(4)
Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax	(8)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	2
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0
Other Comprehensive Income (Loss), Net of Tax	2	1
Accumulated Other Comprehensive Income (Loss), Net of Tax	(6)	(8)
Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax	(148)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	13
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	9
Other Comprehensive Income (Loss), Net of Tax	22	(2)	(9)
Accumulated Other Comprehensive Income (Loss), Net of Tax	(126)	(148)
Accumulated Translation Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax	2
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(2)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0
Other Comprehensive Income (Loss), Net of Tax	(2)	1
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ 0	$ 2

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Capital and Operating Leases (Future Minimum Lease Payments under Non-Cancelable Leases) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Capital Leases of Lessee [Abstract]
Capital Leases, Future Minimum Payments Due, Next Twelve Months	$ 8
Capital Leases, Future Minimum Payments Due in Two Years	8
Capital Leases, Future Minimum Payments Due in Three Years	3
Capital Leases, Future Minimum Payments Due in Four Years	0
Capital Leases, Future Minimum Payments Due in Five Years	0
Capital Leases, Future Minimum Payments Due Thereafter	0
Capital Leases, Future Minimum Payments Due	19
Capital Leases, Less imputed interest	1
Capital Leases, Present value of net minimum lease payments	18
Capital Leases, Less current portion	7
Capital lease obligations	11	12
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	35
Operating Leases, Future Minimum Payments Due in Two Years	31
Operating Leases, Future Minimum Payments, Due in Two Years	27
Operating Leases, Future Minimum Payments, Due in Four Years	25
Operating Leases, Future Minimum Payments, Due in Five Years	20
Operating Leases, Future Minimum Payments, Due Thereafter	92
Operating Leases, Future Minimum Payments Due	$ 230

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Goodwill (Notes)

12 Months Ended

Dec. 31, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill Disclosure

GOODWILL

The Company has goodwill resulting from purchase business combinations.

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

	2013		2012
	(In millions)
Balance as of January 1	$	2,018	$	2,020
Goodwill attributable to sale of Unconventional Gas Production business	—		(2		)
Balance at December 31	$	2,018	$	2,018

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Acquisition (Notes)

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Business Combination Disclosure [Text Block]

ACQUISITION

In the fourth quarter of 2012, the Company closed on the purchase of a portfolio of fourteen on-site energy projects from subsidiaries of Duke Energy Corporation and GDF Suez Energy North America, Inc. This acquisition provided a growth opportunity for the Company's Power and Industrial Projects segment that leverages its extensive energy-related operating experience and project management capabilities.

The purchase of equity interests ranged from 46 percent to 100 percent of the project companies for a total purchase price of approximately $294 million, which consisted of $220 million paid in cash and assumption of approximately $74 million of debt. The debt assumed related to two project companies which have been deemed variable interest entities. DTE, however, was determined not to be the primary beneficiary and thus the VIEs' assets and liabilities are not included in the Company's Consolidated Statements of Financial Position. Therefore, the assumed debt was not included in the purchase price allocation table below. There was no exposure to loss related to the debt assumed as the customer of the project companies is obligated to pay the loans in the event of default or termination. The following table summarizes the fair value of the assets acquired and liabilities assumed as of the closing date:

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

The intangible assets recorded as a result of the acquisition pertained to existing contracts and agreements, which were valued at approximately $75 million as of the closing date. The intangible assets are amortized on a straight line basis over a weighted-average amortization period of approximately eight years. The Company did not record any goodwill due to the acquisition.

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

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Stock-Based Compensation (Performance Share Awards Compensation Expense) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Compensation Expense Recorded [Line Items]
Compensation expense	$ 99	$ 83	$ 66
Performance Shares [Member]
Compensation Expense Recorded [Line Items]
Compensation expense	77	71	53
Cash settlements	9	4	3
Stock settlements	$ 56	$ 41	$ 25

XML

Property, Plant and Equipment (Notes)

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure

PROPERTY, PLANT AND EQUIPMENT

Summary of property by classification as of December 31:

	2013			2012
Property, Plant and Equipment	(In millions)
DTE Electric
Generation	$	11,127		$	10,383
Distribution	7,603			7,306
Total DTE Electric	18,730			17,689
DTE Gas
Distribution	2,834			2,704
Storage	431			426
Other	836			852
Total DTE Gas	4,101			3,982
Non-utility and other	2,292			1,960
Total	25,123			23,631
Less Accumulated Depreciation, Depletion and Amortization
DTE Electric
Generation	(4,004		)	(3,880		)
Distribution	(2,947		)	(2,837		)
Total DTE Electric	(6,951		)	(6,717		)
DTE Gas
Distribution	(1,129		)	(1,057		)
Storage	(138		)	(132		)
Other	(338		)	(365		)
Total DTE Gas	(1,605		)	(1,554		)
Non-utility and other	(767		)	(676		)
Total	(9,323		)	(8,947		)
Net Property, Plant and Equipment	$	15,800		$	14,684

The Allowance for Funds used During Construction (AFUDC) capitalized was approximately $23 million and $20 million during 2013 and 2012, respectively.

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

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

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

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

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

Capitalized software costs amortization expense was $71 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 $668 million and $384 million, respectively. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2012 were $608 million and $313 million, respectively.

Gross property under capital leases was $35 million and $32 million at December 31, 2013 and 2012, respectively. Accumulated amortization of property under capital leases was $21 million and $20 million at December 31, 2013 and 2012, respectively.

XML

Fair Value (Assets and Liabilities Recorded at Fair Value on a Recurring Basis) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative liabilities [Abstract]
Derivative Liabilities, Current	$ (195)	$ (125)
Derivative Liabilities, Noncurrent	(43)	(26)
Fair Value, Measurements, Recurring [Member]
Assets [Abstract]
Cash and Cash Equivalents, Fair Value Disclosure	125	123
Nuclear decommissioning trusts	1,191	1,037
Other investments	136	110
Derivative assets [Abstract]
Derivative Assets	126	147
Assets, Fair Value Disclosure	1,578	1,417
Derivative liabilities [Abstract]
Derivative Liabilities	(238)	(151)
Derivative Liabilities, Current	(195)	(125)
Derivative Liabilities, Noncurrent	(43)	(26)
Fair Value, Net Asset (Liability)	1,340	1,266
Fair Value, Measurements, Recurring [Member] | Current Asset [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	224	231
Fair Value, Measurements, Recurring [Member] | Non Current Asset [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	1,354	1,186
Fair Value, Measurements, Recurring [Member] | Natural Gas Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	14	40
Derivative liabilities [Abstract]
Derivative Liabilities	(108)	(56)
Fair Value, Measurements, Recurring [Member] | Electricity Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	109	102
Derivative liabilities [Abstract]
Derivative Liabilities	(129)	(93)
Fair Value, Measurements, Recurring [Member] | Other Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	3	5
Derivative liabilities [Abstract]
Derivative Liabilities	0	(1)
Fair Value, Measurements, Recurring [Member] | Other Contract [Member]
Derivative liabilities [Abstract]
Derivative Liabilities	(1)	(1)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets [Abstract]
Cash and Cash Equivalents, Fair Value Disclosure	10	0
Nuclear decommissioning trusts	779	694
Other investments	92	66
Derivative assets [Abstract]
Derivative Assets	306	561
Assets, Fair Value Disclosure	1,187	1,321
Derivative liabilities [Abstract]
Derivative Liabilities	(309)	(532)
Derivative Liabilities, Current	(268)	(466)
Derivative Liabilities, Noncurrent	(41)	(66)
Fair Value, Net Asset (Liability)	878	789
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Current Asset [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	277	493
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Non Current Asset [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	910	828
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Natural Gas Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	273	555
Derivative liabilities [Abstract]
Derivative Liabilities	(277)	(526)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Electricity Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	0	0
Derivative liabilities [Abstract]
Derivative Liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Other Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	33	6
Derivative liabilities [Abstract]
Derivative Liabilities	(32)	(6)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Other Contract [Member]
Derivative liabilities [Abstract]
Derivative Liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets [Abstract]
Cash and Cash Equivalents, Fair Value Disclosure	115	123
Nuclear decommissioning trusts	412	343
Other investments	44	44
Derivative assets [Abstract]
Derivative Assets	351	295
Assets, Fair Value Disclosure	922	805
Derivative liabilities [Abstract]
Derivative Liabilities	(415)	(315)
Derivative Liabilities, Current	(328)	(269)
Derivative Liabilities, Noncurrent	(87)	(46)
Fair Value, Net Asset (Liability)	507	490
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Current Asset [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	400	372
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Non Current Asset [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	522	433
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Natural Gas Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	89	66
Derivative liabilities [Abstract]
Derivative Liabilities	(140)	(73)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Electricity Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	261	226
Derivative liabilities [Abstract]
Derivative Liabilities	(272)	(240)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Other Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	1	3
Derivative liabilities [Abstract]
Derivative Liabilities	(2)	(1)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Other Contract [Member]
Derivative liabilities [Abstract]
Derivative Liabilities	(1)	(1)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets [Abstract]
Cash and Cash Equivalents, Fair Value Disclosure	0	0
Nuclear decommissioning trusts	0	0
Other investments	0	0
Derivative assets [Abstract]
Derivative Assets	176	160
Assets, Fair Value Disclosure	176	160
Derivative liabilities [Abstract]
Derivative Liabilities	(212)	(173)
Derivative Liabilities, Current	(177)	(144)
Derivative Liabilities, Noncurrent	(35)	(29)
Fair Value, Net Asset (Liability)	(36)	(13)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Current Asset [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	139	120
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Non Current Asset [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	37	40
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	34	24
Derivative liabilities [Abstract]
Derivative Liabilities	(86)	(62)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Electricity Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	139	134
Derivative liabilities [Abstract]
Derivative Liabilities	(126)	(111)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Other Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	3	2
Derivative liabilities [Abstract]
Derivative Liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Other Contract [Member]
Derivative liabilities [Abstract]
Derivative Liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Netting Adjustments [Member]
Assets [Abstract]
Cash and Cash Equivalents, Fair Value Disclosure	0	0
Nuclear decommissioning trusts	0	0
Other investments	0	0
Derivative assets [Abstract]
Derivative Assets	(707)	(869)
Assets, Fair Value Disclosure	(707)	(869)
Derivative liabilities [Abstract]
Derivative Liabilities	698	869
Derivative Liabilities, Current	578	754
Derivative Liabilities, Noncurrent	120	115
Fair Value, Net Asset (Liability)	9	0
Fair Value, Measurements, Recurring [Member] | Netting Adjustments [Member] | Current Asset [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	(592)	(754)
Fair Value, Measurements, Recurring [Member] | Netting Adjustments [Member] | Non Current Asset [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	(115)	(115)
Fair Value, Measurements, Recurring [Member] | Netting Adjustments [Member] | Natural Gas Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	(382)	(605)
Derivative liabilities [Abstract]
Derivative Liabilities	395	605
Fair Value, Measurements, Recurring [Member] | Netting Adjustments [Member] | Electricity Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	(291)	(258)
Derivative liabilities [Abstract]
Derivative Liabilities	269	258
Fair Value, Measurements, Recurring [Member] | Netting Adjustments [Member] | Other Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	(34)	(6)
Derivative liabilities [Abstract]
Derivative Liabilities	34	6
Fair Value, Measurements, Recurring [Member] | Netting Adjustments [Member] | Other Contract [Member]
Derivative liabilities [Abstract]
Derivative Liabilities	$ 0	$ 0

XML

Retirement Benefits and Trusteed Assets (Pension Plan - Target Allocations of Plan Assets) (Details) (Pension Plan, Defined Benefit [Member])	12 Months Ended
	Dec. 31, 2013
Pension Plan Target Allocations of Plan Assets [Line Items]
Target Allocation Percentage of Assets	1
US Large Cap Equity Securities [Member]
Pension Plan Target Allocations of Plan Assets [Line Items]
Target Allocation Percentage of Assets	0.22
US Small Cap and Mid Cap Equity Securities [Member]
Pension Plan Target Allocations of Plan Assets [Line Items]
Target Allocation Percentage of Assets	0.05
Non US Equity Securities [Member]
Pension Plan Target Allocations of Plan Assets [Line Items]
Target Allocation Percentage of Assets	0.2
Fixed Income Securities [Member]
Pension Plan Target Allocations of Plan Assets [Line Items]
Target Allocation Percentage of Assets	0.25
Hedge Funds and Similar Investments [Member]
Pension Plan Target Allocations of Plan Assets [Line Items]
Target Allocation Percentage of Assets	0.2
Private Equity and Other [Member]
Pension Plan Target Allocations of Plan Assets [Line Items]
Target Allocation Percentage of Assets	0.08

XML

Property, Plant and Equipment (Average Estimated Useful Life of Each Major Class) (Details)	12 Months Ended
	Dec. 31, 2013
Electric [Member]
Public Utility Property, Plant and Equipment [Line Items]
Useful Life - Generation	40 years
Useful Life - Distribution	41 years
Gas [Member]
Public Utility Property, Plant and Equipment [Line Items]
Useful Life - Distribution	50 years
Useful Life - Storage	53 years

XML

Fair Value (Transfers between Levels of the Fair Value Hierarchy) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Fair Value Transfers Between Level 1, Level 2 and Level 3 [Line Items]
Fair Value Transfer from Level 1 to Level 2, Amount	$ 0	$ 0
Fair Value Transfer from Level 1 to Level 3, Amount	0	0
Fair Value Transfer from Level 2 to Level 1, Amount	0	0
Fair Value Transfer from Level 2 to Level 3, Amount	1	1
Fair Value Transfer from Level 3 to Level 1, Amount	0	0
Fair Value Transfer from Level 3 to Level 2, Amount	$ 0	$ 0

XML

Long-Term Debt (Long Term Debt Outstanding and Weighted Average Interest Rates) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Long-term Debt, Total	$ 8,094	$ 7,813
Long Term Debt excluding Securitization, Debentures and Capital Leases	7,312	6,854
Less Amount of Long-term Debt due within one year	(694)	(634)
Long-term Debt, Excluding Current Maturities	6,618	6,220
Long-term Securitization Bond	302	479
Less Amount of Securitization Bonds due within one year	(197)	(177)
Securitization bonds, Excluding Current Maturities	105	302
Junior Subordinated Notes, Noncurrent	480	480
Securitization Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	6.60%
Debt Instrument, Maturity Date	Mar. 15, 2015
Junior Subordinated Debentures [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	6.50%
Debt Instrument, Maturity Date	Dec. 01, 2061
Junior Subordinated Notes, Noncurrent	280	280
Junior Subordinated Debentures 1 [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.25%
Debt Instrument, Maturity Date	Dec. 01, 2062
Junior Subordinated Notes, Noncurrent	200	200
DTE Energy [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	6.10%
Debt Instrument, Maturity Date Range, Start	May 15, 2014
Debt Instrument, Maturity Date Range, End	Apr. 15, 2033
Long-term Debt, Total	1,297	1,298
DTE Electric [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	4.70%
Debt Instrument, Maturity Date Range, Start	Mar. 31, 2014
Debt Instrument, Maturity Date Range, End	Apr. 01, 2043
Long-term Debt, Total	4,286	3,777
DTE Electric [Member] | Tax Exempt Revenue Bonds [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.10%
Debt Instrument, Maturity Date Range, Start	Apr. 01, 2014
Debt Instrument, Maturity Date Range, End	Dec. 01, 2036
Long-term Debt, Total	558	707
DTE Gas [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.60%
Debt Instrument, Maturity Date Range, Start	May 01, 2014
Debt Instrument, Maturity Date Range, End	Dec. 15, 2042
Long-term Debt, Total	1,029	919
DTE Gas [Member] | Long Term Debt, Other [Member]
Debt Instrument [Line Items]
Long-term Debt, Total	$ 142	$ 153

XML

Significant Accounting Policies (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Significant Accounting Policies [Line Items]
Other Nonoperating Income	$ 201,000,000	$ 173,000,000	$ 117,000,000
Receivables Due Date	21 days
Threshold Period Past Due for Write-off of Trade Accounts Receivable	150 days
Specific Review of Probable Future Collections Based on Receivable Balances in Excess of Pre Specified Days	30 days
Unbilled Revenues included in Customer Accounts Receivable	1,542,000,000	1,336,000,000
Accrued Expense Related to Fermi 2 Refueling Outages	26,000,000	12,000,000
Period Expenses Related To Fermi 2 Refueling Outages Are Accrued	18 months
Amortization of Intangible Assets	14,000,000	6,000,000	5,000,000
Excise Sales Tax Net Impact on Statement of Operations	0
Charitable Contributions to a Foundation	18,000,000	21,000,000	21,000,000
Minimum [Member]
Significant Accounting Policies [Line Items]
Notes Receivable Considered Delinquent Period	60 days
Finite Lived Asset Useful Life	1 year
Maximum [Member]
Significant Accounting Policies [Line Items]
Notes Receivable Considered Delinquent Period	120 days
Finite Lived Asset Useful Life	28 years
Unbilled Revenues [Member]
Significant Accounting Policies [Line Items]
Unbilled Revenues included in Customer Accounts Receivable	815,000,000	686,000,000
Public Utilities, Inventory, Natural Gas [Member]
Significant Accounting Policies [Line Items]
LIFO Inventory Amount	4,000,000	37,000,000
Excess of Replacement Costs over Stated LIFO Value	170,000,000	113,000,000
Power and Industrial Projects [Member]
Significant Accounting Policies [Line Items]
Other Nonoperating Income	$ 81,000,000	$ 63,000,000	$ 15,000,000

XML

Regulatory Matters Regulatory Matters (Schedule of Regulatory Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 1,164	$ 1,120
Regulatory Liability, Current	(302)	(89)
Regulatory Liability, Noncurrent	862	1,031
Asset Removal Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	351	439
Renewable Energy [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	277	230
Refundable Revenue Decoupling [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	127	127
Pension Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	84	105
Over Recovery of Securitization [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	72	54
Refundable postretirement costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	72	0
Accrued PSCR GCR Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	65	16
Refundable Income Taxes [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	45	56
Energy Optimization [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	31	34
Refueling Outage [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	26	12
Refundable Uncollectible Expense [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	12	37
Other Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 2	$ 10

XML

Retirement Benefits and Trusteed Assets (OPEB - Fair Value Measurements) (Details) (Other Postretirement Benefit Plan, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 1,527	$ 1,153	$ 985
Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	883	665
Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	384	283
Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	260	205
Short-term investments [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	5	3
Short-term investments [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	5	1
Short-term investments [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	2
Short-term investments [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
US Large Cap Equity Securities [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	302	192
US Large Cap Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	302	189
US Large Cap Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	3
US Large Cap Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
US Small Cap and Mid Cap Equity Securities [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	147	105
US Small Cap and Mid Cap Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	147	105
US Small Cap and Mid Cap Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
US Small Cap and Mid Cap Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Non US Equity Securities [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	291	237
Non US Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	282	230
Non US Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	9	7
Non US Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fixed income securities [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	367	285
Fixed income securities [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	17	38
Fixed income securities [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	350	247
Fixed income securities [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Hedge Funds and Similar Investments [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	314	245
Hedge Funds and Similar Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	130	102
Hedge Funds and Similar Investments [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	25	24
Hedge Funds and Similar Investments [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	159	119
Private Equity and Other [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	101	86
Private Equity and Other [Member] | Fair Value, Inputs, Level 1 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Private Equity and Other [Member] | Fair Value, Inputs, Level 2 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Private Equity and Other [Member] | Fair Value, Inputs, Level 3 [Member]
Schedule of Defined Benefit Plans Fair Value Hierachy Level Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 101	$ 86

XML

Organization and Basis of Presentation (Tables)

12 Months Ended

Dec. 31, 2013

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

Schedule of Variable Interest Entities [Table Text Block]

	December 31, 2013						December 31, 2012
	Securitization		Other		Total		Securitization		Other		Total
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	12	$	12	$	—	$	10	$	10
Restricted cash	100		8		108		102		7		109
Accounts receivable	34		16		50		34		7		41
Inventories	—		118		118		—		141		141
Other current assets	—		1		1		—		1		1
Property, plant and equipment	—		99		99		—		93		93
Securitized regulatory assets	231		—		231		413		—		413
Other assets	4		8		12		7		11		18
	$	369	$	262	$	631	$	556	$	270	$	826
LIABILITIES
Accounts payable and accrued current liabilities	$	7	$	23	$	30	$	11	$	14	$	25
Current portion long-term debt, including capital leases	196		9		205		177		8		185
Current regulatory liabilities	43		—		43		50		—		50
Other current liabilities	—		4		4		—		4		4
Mortgage bonds, notes and other	—		21		21		—		25		25
Securitization bonds	105		—		105		302		—		302
Capital lease obligations	—		7		7		—		11		11
Other long-term liabilities	8		2		10		7		2		9
	$	359	$	66	$	425	$	547	$	64	$	611

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

	December 31, 2013		December 31, 2012
	(In millions)
Other investments	$	141	$	130
Notes receivable	$	8	$	6

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Segment Information (Financial Data) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]
Operating Revenue	$ 2,533	$ 2,387	$ 2,225	$ 2,516	$ 2,349	$ 2,190	$ 2,013	$ 2,239	$ 9,661	$ 8,791	$ 8,858
Depreciation, Depletion and Amortization									1,094	1,018	995
Interest Income									(9)
Interest Expense									436	440	488
Income Taxes									254	286	268
Net Income Attributable to DTE Energy Company	124	198	105	234	81	227	146	156	661	610	711
Total Assets	25,935				26,339				25,935	26,339	26,009
Goodwill	2,018				2,018				2,018	2,018	2,020
Capital Expenditures									1,876	1,820	1,484
Electric [Member]
Segment Reporting Information [Line Items]
Depreciation, Depletion and Amortization									902	827	818
Interest Income									(1)	(1)	(1)
Interest Expense									268	272	289
Income Taxes									252	280	265
Net Income Attributable to DTE Energy Company									484	483	434
Total Assets	17,508				17,755				17,508	17,755	17,567
Goodwill	1,208				1,208				1,208	1,208	1,208
Capital Expenditures									1,325	1,230	1,203
Gas [Member]
Segment Reporting Information [Line Items]
Depreciation, Depletion and Amortization									95	92	89
Interest Income									(7)	(7)	(7)
Interest Expense									58	59	64
Income Taxes									77	50	60
Net Income Attributable to DTE Energy Company									143	115	110
Total Assets	3,938				4,059				3,938	4,059	4,065
Goodwill	743				745				743	745	745
Capital Expenditures									209	221	179
Gas Storage and Pipelines [Member]
Segment Reporting Information [Line Items]
Depreciation, Depletion and Amortization									23	8	6
Interest Income									(7)	(8)	(5)
Interest Expense									18	8	7
Income Taxes									45	39	35
Net Income Attributable to DTE Energy Company									70	61	57
Total Assets	824				668				824	668	538
Goodwill	24				22				24	22	22
Capital Expenditures									245	233	16
Power and Industrial Projects [Member]
Segment Reporting Information [Line Items]
Depreciation, Depletion and Amortization									72	65	60
Interest Income									(6)	(7)	(8)
Interest Expense									27	37	32
Income Taxes									(45)	(44)	11
Net Income Attributable to DTE Energy Company									66	42	38
Total Assets	1,067				991				1,067	991	789
Goodwill	26				26				26	26	26
Capital Expenditures									93	83	56
Energy Trading [Member]
Segment Reporting Information [Line Items]
Depreciation, Depletion and Amortization									1	2	3
Interest Income									0	0	0
Interest Expense									8	8	9
Income Taxes									(38)	7	34
Net Income Attributable to DTE Energy Company									(58)	12	52
Total Assets	623				629				623	629	612
Goodwill	17				17				17	17	17
Capital Expenditures									3	1	1
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Depreciation, Depletion and Amortization									1	1	1
Interest Income									(51)	(52)	(47)
Interest Expense									120	121	145
Income Taxes									(37)	(46)	(136)
Net Income Attributable to DTE Energy Company									(44)	(47)	23
Total Assets	2,945				3,074				2,945	3,074	2,605
Goodwill	0				0				0	0	0
Capital Expenditures									1	3	0
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Depreciation, Depletion and Amortization									0	0	0
Interest Income									63	65	58
Interest Expense									(63)	(65)	(58)
Income Taxes									0	0	(1)
Net Income Attributable to DTE Energy Company									0	0	0
Total Assets	(970)				(837)				(970)	(837)	(485)
Goodwill	0				0				0	0	0
Capital Expenditures									0	0	0
Segment, Continuing Operations [Member]
Segment Reporting Information [Line Items]
Depreciation, Depletion and Amortization										995	977
Interest Income										(10)	(10)
Interest Expense										440	488
Income Taxes										286	268
Net Income Attributable to DTE Energy Company										666	714
Total Assets					26,339					26,339	25,691
Goodwill					2,018					2,018	2,018
Capital Expenditures										1,771	1,455
Segment, Discontinued Operations [Member]
Segment Reporting Information [Line Items]
Net Income Attributable to DTE Energy Company										(56)	(3)
Total Assets					0					0	318
Goodwill					0					0	2
Capital Expenditures										49	29
Operating Segments [Member] | Electric [Member]
Segment Reporting Information [Line Items]
Operating Revenue									5,199	5,293	5,154
Operating Segments [Member] | Gas [Member]
Segment Reporting Information [Line Items]
Operating Revenue									1,474	1,315	1,505
Operating Segments [Member] | Gas Storage and Pipelines [Member]
Segment Reporting Information [Line Items]
Operating Revenue									132	96	91
Operating Segments [Member] | Power and Industrial Projects [Member]
Segment Reporting Information [Line Items]
Operating Revenue									1,950	1,823	1,129
Operating Segments [Member] | Energy Trading [Member]
Segment Reporting Information [Line Items]
Operating Revenue									1,771	1,109	1,276
Operating Segments [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating Revenue									3	3	4
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenue, Net									(868)	(848)	(301)
Intersegment Eliminations [Member] | Electric [Member]
Segment Reporting Information [Line Items]
Revenue, Net									(26)	(29)	(33)
Intersegment Eliminations [Member] | Gas [Member]
Segment Reporting Information [Line Items]
Revenue, Net									(4)	(4)	(2)
Intersegment Eliminations [Member] | Gas Storage and Pipelines [Member]
Segment Reporting Information [Line Items]
Revenue, Net									(3)	(6)	(8)
Intersegment Eliminations [Member] | Power and Industrial Projects [Member]
Segment Reporting Information [Line Items]
Revenue, Net									(816)	(801)	(238)
Intersegment Eliminations [Member] | Energy Trading [Member]
Segment Reporting Information [Line Items]
Revenue, Net									(43)	(43)	(70)
Intersegment Eliminations [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Revenue, Net									24	37	50
Intersegment Eliminations [Member] | Segment, Discontinued Operations [Member]
Segment Reporting Information [Line Items]
Revenue, Net									$ 0	$ (2)	$ 0

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Long-term Purchase Commitment [Table Text Block]

The Company estimates that these commitments will be approximately $8.6 billion from 2014 through 2051 as detailed in the following table:

	(In millions)
2014	$	2,617
2015	1,195
2016	643
2017	345
2018	311
2019 — 2051	3,487
	$	8,598

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Common Stock (Notes)

12 Months Ended

Dec. 31, 2013

Stockholders' Equity Note [Abstract]

Schedule of Stock by Class [Table Text Block]

COMMON STOCK

Common Stock

During 2013 and 2012, the Company contributed the following amounts of DTE Energy Common stock to the DTE Energy Company Affiliates Employee Benefit Plans Master Trust:

Date	Number of Shares	Price Per Share		Amount
				(In millions)
March 12, 2013	750,075	$	66.66	$	50
June 12, 2013	753,579	$	66.35	50
September 12, 2013	1,522,301	$	65.69	100
				$	200
June 18, 2012	1,334,668	$	59.94	$	80

The shares for all the contributions were valued at the closing market price of DTE Energy common stock on 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.

Dividends

Certain of the Company’s credit facilities contain a provision requiring the Company to maintain a total funded debt to capitalization ratio, as defined in the agreements, of no more than 0.65 to 1, which has the effect of limiting the amount of dividends the Company can pay in order to maintain compliance with this provision. See Note 17 for a definition of this ratio. The effect of this provision was to restrict the payment of approximately $166 million at December 31, 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.

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Retirement Benefits and Trusteed Assets (Pension Plan - Pension Cost Inclusions) (Details) (Pension Plan, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 94	$ 82	$ 69
Interest cost	192	204	202
Expected return on plan assets	(266)	(244)	(246)
Amortization of Net Loss	208	176	142
Amortization of Prior Service Cost (Credit)	0	0	3
Special termination benefits	0	2	2
Net pension or postretirement cost (benefit)	$ 228	$ 220	$ 172

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Capital and Operating Leases (Notes)

12 Months Ended

Dec. 31, 2013

Capital and Operating Leases [Abstract]

Capital and Operating Leases

CAPITAL AND OPERATING LEASES

Lessee — The Company leases various assets under capital and operating leases, including coal railcars, office buildings, a warehouse, computers, vehicles and other equipment. The lease arrangements expire at various dates through 2046.

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

	Capital Leases		Operating Leases
	(In millions)
2014	$	8	$	35
2015	8		31
2016	3		27
2017	—		25
2018	—		20
Thereafter	—		92
Total minimum lease payments	$	19	$	230
Less imputed interest	1
Present value of net minimum lease payments	18
Less current portion	7
Non-current portion	$	11

Rental expense for operating leases was $34 million in 2013, $36 million in 2012, and $40 million in 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, 2013, were as follows:

	(In millions)
2014	$	12
2015	12
2016	12
2017	12
2018	12
Thereafter	19
Total minimum future lease receipts	79
Residual value of leased pipeline	40
Less unearned income	(40		)
Net investment in capital lease	79
Less current portion	(5		)
	$	74

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Income Taxes (Components of Income Tax Expense) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Components of Income Tax Expense (Benefit) [Abstract]
Federal income tax expense (benefit)	$ 74	$ 190	$ 27
State and other income tax expense (benefit)	16	49	21
Total current income taxes expense (benefit)	90	239	48
Federal deferred income tax expense (benefit)	122	39	318
State and other income tax deferred expense (benefit)	42	8	(98)
Total deferred income taxes exepense (benefit)	164	47	220
Income Tax Expense (Benefit)	254	286	268
Income tax expense (benefit) from Discontinued Operations	0	(29)	(1)
Income Tax Expense (Benefit) including Discontinued Operations	$ 254	$ 257	$ 267

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Short-Term Credit Arrangements and Borrowings (Tables)

12 Months Ended

Dec. 31, 2013

Short-term Debt [Abstract]

Schedule of Line of Credit Facilities [Table Text Block]

The availability under the facilities in place at December 31, 2013 is shown in the following table:

	DTE Energy		DTE Electric		DTE Gas		Total
	(In millions)
Unsecured letter of credit facility, expiring in May 2014	$	50	$	—	$	—	$	50
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Unsecured revolving credit facility, expiring April 2018	1,200		300		300		1,800
	1,375		300		300		1,975
Amounts outstanding at December 31, 2013:
Commercial paper issuances	35		—		96		131
Letters of credit	244		—		—		244
	279		—		96		375
Net availability at December 31, 2013	$	1,096	$	300	$	204	$	1,600

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Long-Term Debt (Scheduled Debt Maturities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Maturities of Long-term Debt [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 891
Long-term Debt, Maturities, Repayments of Principal in Year Two	476
Long-term Debt, Maturities, Repayments of Principal in Year Three	465
Long-term Debt, Maturities, Repayments of Principal in Year Four	9
Long-term Debt, Maturities, Repayments of Principal in Year Five	407
Long-term Debt, Maturities, Repayments of Principal after Year Five	5,846
Long-term Debt, Total	$ 8,094	$ 7,813

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Table Text Block]

Summary of property by classification as of December 31:

	2013			2012
Property, Plant and Equipment	(In millions)
DTE Electric
Generation	$	11,127		$	10,383
Distribution	7,603			7,306
Total DTE Electric	18,730			17,689
DTE Gas
Distribution	2,834			2,704
Storage	431			426
Other	836			852
Total DTE Gas	4,101			3,982
Non-utility and other	2,292			1,960
Total	25,123			23,631
Less Accumulated Depreciation, Depletion and Amortization
DTE Electric
Generation	(4,004		)	(3,880		)
Distribution	(2,947		)	(2,837		)
Total DTE Electric	(6,951		)	(6,717		)
DTE Gas
Distribution	(1,129		)	(1,057		)
Storage	(138		)	(132		)
Other	(338		)	(365		)
Total DTE Gas	(1,605		)	(1,554		)
Non-utility and other	(767		)	(676		)
Total	(9,323		)	(8,947		)
Net Property, Plant and Equipment	$	15,800		$	14,684

Useful Life [Table Text Block]

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

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

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Preferred and Preferenced Securities (Details) (USD $)	Dec. 31, 2013
DTE Energy [Member]
Preferred and Preferenced Securities [Line Items]
Preferred Stock, Par Value Per Share	$ 0
Preferred Stock, Shares Authorized	5,000,000
DTE Electric [Member]
Preferred and Preferenced Securities [Line Items]
Preferred Stock, Par Value Per Share	$ 100
Preferred Stock, Shares Authorized	6,747,484
Preference Stock, Par Value Per Share	$ 1
Preference Stock, Shares Authorized	30,000,000
DTE Gas [Member]
Preferred and Preferenced Securities [Line Items]
Preferred Stock, Par Value Per Share	$ 1
Preferred Stock, Shares Authorized	7,000,000
Preference Stock, Par Value Per Share	$ 1
Preference Stock, Shares Authorized	4,000,000

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Consolidated Statements of Financial Position (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current Assets
Cash and cash equivalents	$ 52	$ 65
Restricted cash, principally Securitization	123	122
Accounts receivable (less allowance for doubtful accounts of $55 and $62, respectively)
Customer	1,542	1,336
Other	127	126
Inventories
Fuel and gas	363	527
Materials and supplies	265	234
Derivative assets	99	108
Regulatory assets	26	182
Other	209	215
Total Current Assets	2,806	2,915
Investments
Nuclear decommissioning trust funds	1,191	1,037
Other	603	554
Total Investments	1,794	1,591
Property
Property, plant and equipment	25,123	23,631
Less accumulated depreciation, depletion and amortization	(9,323)	(8,947)
Property, plant and equipment, net	15,800	14,684
Other Assets
Goodwill	2,018	2,018
Regulatory assets	2,837	4,235
Securitized regulatory assets	231	413
Intangible assets	122	135
Notes receivable	102	112
Derivative assets	27	39
Other	198	197
Total Noncurrent Assets	5,535	7,149
Total Assets	25,935	26,339
Current Liabilities
Accounts payable	962	848
Accrued interest	90	93
Dividends payable	116	107
Short-term borrowings	131	240
Current portion long-term debt, including capital leases	898	817
Derivative liabilities	195	125
Regulatory liabilities	302	89
Other	495	449
Total Current Liabilities	3,189	2,768
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	6,618	6,220
Securitization bonds	105	302
Junior subordinated debentures	480	480
Capital lease obligations	11	12
Total Long-Term Debt (net of current portion)	7,214	7,014
Other Liabilities
Deferred income taxes	3,321	3,191
Regulatory liabilities	862	1,031
Asset retirement obligations	1,827	1,719
Unamortized investment tax credit	47	56
Derivative liabilities	43	26
Accrued pension liability	653	1,498
Accrued postretirement liability	350	1,160
Nuclear decommissioning	178	159
Other	297	306
Total Noncurrent Liabilities	7,578	9,146
Equity
Common stock, without par value, 400,000,000 shares authorized, 177,087,230 and 172,351,680 shares issued and outstanding, respectively	3,907	3,587
Retained earnings	4,150	3,944
Accumulated other comprehensive loss	(136)	(158)
Total DTE Energy Company Equity	7,921	7,373
Noncontrolling interests	33	38
Total Equity	7,954	7,411
Total Liabilities and Equity	$ 25,935	$ 26,339

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Jointly Owned Utility Plant (Detail Textuals)	Dec. 31, 2013 facilities
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant Number of Plants	2
Belle River Unit 1 [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	63.00%
Belle River Facilities used jointly by Belle River and St. Clair Power Plants [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	81.00%
Belle River [Member]
Jointly Owned Utility Plant Interests [Line Items]
Joint Owners Percentage of the Total Capacity Energy and Related Responsibilities	19.00%
Belle River Unit 2 [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	75.00%
Ludington [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	49.00%
Joint Owners Percentage of the Total Capacity Energy and Related Responsibilities	51.00%

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Significant Accounting Policies (Notes)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Significant Accounting Policies

SIGNIFICANT ACCOUNTING POLICIES

Revenues

Revenues from the sale and delivery of electricity, and the sale, delivery and storage of natural gas are recognized as services are provided. DTE Electric and DTE Gas record revenues for electricity and gas provided but unbilled at the end of each month. Rates for DTE Electric and DTE Gas include provisions to adjust billings for fluctuations in fuel and purchased power costs, cost of natural gas and certain other costs. Revenues are adjusted for differences between actual costs subject to reconciliation and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are recorded on the Consolidated Statements of Financial Position and are recovered or returned to customers through adjustments to the billing factors.

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

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

Other Income

Other income is recognized for non-operating income such as equity earnings, interest and dividends, allowance for funds using during construction and contract services. Power & Industrial Projects also recognizes Other income in connection with the sale of membership interests in reduced emissions fuel facilities to investors. In exchange for the cash received, the investors will receive a portion of the economic attributes of the facilities, including income tax attributes. The transactions are not treated as a sale of membership interests for financial reporting purposes. Other income is considered earned when refined coal is produced and tax credits are generated. Power & Industrial Projects recognized approximately $81 million, $63 million, and $15 million of Other income for the years ended December 31, 2013, 2012, and 2011, respectively.

Accounting for ISO Transactions

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

Energy Trading participates in the energy markets through various independent system operators and regional transmission organizations (ISOs and RTOs). These markets require that Energy Trading submits hourly day-ahead, real-time bids and offers for energy at locations across each region. 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 trading contracts which are presented on a net basis in Operating Revenues in the Consolidated Statements of Operations.

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

Comprehensive Income (Loss)

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 tables, amounts recorded to accumulated other comprehensive loss for the year ended December 31, 2013 include unrealized gains and losses from derivatives accounted for as cash flow hedges, unrealized gains and losses on available-for-sale securities, the Company’s interest in 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.

	Changes in Accumulated Other Comprehensive Loss by Component (a)
	For The Year Ended December 31, 2013
	Net Unrealized Gain/(Loss) on Derivatives			Net Unrealized Gain/(Loss) on Investments			Benefit Obligations (b)			Foreign Currency Translation			Total
	(In millions)
Beginning balances December 31, 2012	$	(4	)	$	(8	)	$	(148	)	$	2		$	(158	)
Other comprehensive income (loss) before reclassifications	—			2			13			(2		)	13
Amounts reclassified from accumulated other comprehensive income (loss)	—			—			9			—			9
Net current-period other comprehensive income (loss)	—			2			22			(2		)	22
Ending balances December 31, 2013	$	(4	)	$	(6	)	$	(126	)	$	—		$	(136	)

______________________________________

(a) All amounts are net of tax.

(b) The amounts reclassified from accumulated other comprehensive income (loss) are included in the computation of the net periodic pension and other postretirement benefit costs (see Note 20).

Cash Equivalents and Restricted Cash

Cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with remaining maturities of three months or less. Restricted cash consists of funds held to satisfy requirements of certain debt, primarily Securitization bonds, and partnership operating agreements. Restricted cash designated for interest and principal payments within one year is classified as a current asset.

Receivables

Accounts receivable are primarily composed of trade receivables and unbilled revenue. Our accounts receivable are stated at net realizable value.

The allowance for doubtful accounts for DTE Electric and DTE Gas is generally calculated using the aging approach that utilizes rates developed in reserve studies. We establish an allowance for uncollectible accounts based on historical losses and management’s assessment of existing economic conditions, customer trends, and other factors. Customer accounts are generally considered delinquent if the amount billed is not received by the due date, which is typically in 21 days, however, factors such as assistance programs may delay aggressive action. We assess late payment fees on trade receivables based on past-due terms with customers. Customer accounts are written off when collection efforts have been exhausted. The time period for write-off is 150 days after service has been terminated.

The customer allowance for doubtful accounts for our other businesses is calculated based on specific review of probable future collections based on receivable balances in excess of 30 days.

Unbilled revenues of $815 million and $686 million are included in customer accounts receivable at December 31, 2013 and 2012, respectively.

Notes Receivable

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

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

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

Inventories

The Company generally values inventory at average cost.

Natural gas inventory of $4 million and $37 million as of December 31, 2013 and 2012, respectively, at DTE Gas is determined using the last-in, first-out (LIFO) method. At December 31, 2013, the replacement cost of gas remaining in storage exceeded the LIFO cost by $170 million. At December 31, 2012, the replacement cost of gas remaining in storage exceeded the LIFO cost by $113 million.

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

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

Utility property at DTE Electric and DTE Gas is depreciated over its estimated useful life using straight-line rates approved by the MPSC.

Non-utility property is depreciated over its estimated useful life using the straight-line and units of production methods.

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

Approximately $26 million and $12 million of expenses related to Fermi 2 refueling outages were accrued at December 31, 2013 and 2012, respectively. Amounts are accrued on a pro-rata basis, generally over an 18-month period, that coincides with scheduled refueling outages at Fermi 2. This accrual of outage costs matches the regulatory recovery of these costs in rates set by the MPSC. See Note 11.

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

Long-Lived Assets

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

Intangible Assets

The Company has certain intangible assets relating to emission allowances, renewable energy credits and non-utility contracts as shown below:

	December 31,		December 31,
	2013		2012
	(In millions)
Emission allowances	$	2	$	6
Renewable energy credits	51		44
Contract intangible assets	126		139
	179		189
Less accumulated amortization	45		34
Intangible assets, net	134		155
Less current intangible assets	12		20
	$	122	$	135

Emission allowances and renewable energy credits are charged to expense, using average cost, as the allowances and credits are consumed in the operation of the business. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 1 to 28 years. Intangible assets amortization expense was $14 million in 2013, $6 million in 2012 and $5 million in 2011.

The following table summarizes the estimated amortization expense expected to be recognized during each year through 2018:

Estimated amortization expense	(In millions)
2014	$	13
2015	$	12
2016	$	11
2017	$	8
2018	$	8

Excise and Sales Taxes

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

Deferred Debt Costs

The costs related to the issuance of long-term debt are deferred and amortized over the life of each debt issue. In accordance with MPSC regulations applicable to the Company’s electric and gas utilities, the unamortized discount, premium and expense related to 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.

Investments in Debt and Equity Securities

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

Government Grants

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 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.

DTE Energy Foundation

Charitable contributions to the DTE Energy Foundation were $18 million, $21 million, and $21 million for the years ended December 31, 2013, 2012 and 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.

Other Accounting Policies

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

Note	Title
3	Fair Value
4	Financial and Other Derivative Instruments
10	Asset Retirement Obligations
11	Regulatory Matters
12	Income Taxes
21	Stock-based Compensation

XML

Organization and Basis of Presentation (Consolidated Variable Interest Entities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Assets [Abstract]
Cash and cash equivalents	$ 52	$ 65	$ 68	$ 65
Restricted cash	123	122
Accounts receivable	1,542	1,336
Other current assets	209	215
Property, plant and equipment	15,800	14,684
Securitized regulatory assets	231	413
Other assets	198	197
Total Assets	25,935	26,339	26,009
Liabilities [Abstract]
Current portion long-term debt, including capital leases	898	817
Current regulatory liabilities	302	89
Other current liabilities	495	449
Mortgage bonds, notes and other	6,618	6,220
Securitization bonds	105	302
Capital lease obligations	11	12
Other long term liabilities	297	306
Variable Interest Entity Securitization [Member]
Assets [Abstract]
Cash and cash equivalents	0	0
Restricted cash	100	102
Accounts receivable	34	34
Inventories	0	0
Other current assets	0	0
Property, plant and equipment	0	0
Securitized regulatory assets	231	413
Other assets	4	7
Total Assets	369	556
Liabilities [Abstract]
Accounts payable and accrued current liabilities	7	11
Current portion long-term debt, including capital leases	196	177
Current regulatory liabilities	43	50
Other current liabilities	0	0
Mortgage bonds, notes and other	0	0
Securitization bonds	105	302
Capital lease obligations	0	0
Other long term liabilities	8	7
Total Liabilities	359	547
Variable Interest Entity, Primary Beneficiary [Member]
Assets [Abstract]
Cash and cash equivalents	12	10
Restricted cash	8	7
Accounts receivable	16	7
Inventories	118	141
Other current assets	1	1
Property, plant and equipment	99	93
Securitized regulatory assets	0	0
Other assets	8	11
Total Assets	262	270
Liabilities [Abstract]
Accounts payable and accrued current liabilities	23	14
Current portion long-term debt, including capital leases	9	8
Current regulatory liabilities	0	0
Other current liabilities	4	4
Mortgage bonds, notes and other	21	25
Securitization bonds	0	0
Capital lease obligations	7	11
Other long term liabilities	2	2
Total Liabilities	66	64
Consolidated Variable Interest Entity [Member]
Assets [Abstract]
Cash and cash equivalents	12	10
Restricted cash	108	109
Accounts receivable	50	41
Inventories	118	141
Other current assets	1	1
Property, plant and equipment	99	93
Securitized regulatory assets	231	413
Other assets	12	18
Total Assets	631	826
Liabilities [Abstract]
Accounts payable and accrued current liabilities	30	25
Current portion long-term debt, including capital leases	205	185
Current regulatory liabilities	43	50
Other current liabilities	4	4
Mortgage bonds, notes and other	21	25
Securitization bonds	105	302
Capital lease obligations	7	11
Other long term liabilities	10	9
Total Liabilities	$ 425	$ 611

XML

Discontinued Operations (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Divestiture of Businesses	$ 0	$ 255	$ 0
Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal of Equity Interest In Segment Percentage		100.00%
Proceeds from Divestiture of Businesses		255
Discontinued Operation, Loss from Disposal of Discontinued Operation, before Income Tax		83
Discontinued Operation, Loss on Disposal of Discontinued Operation, Net of Tax		55
Allocation of Corporate Interest Costs	$ 0

XML

Long-Term Debt (Details Textuals) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Junior Subordinated Notes, Noncurrent	$ 480	$ 480
Junior Subordinated Debentures [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	6.50%
Junior Subordinated Notes, Noncurrent	280	280
Junior Subordinated Debentures 1 [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.25%
Junior Subordinated Notes, Noncurrent	$ 200	$ 200

XML

Fair Value (Fair Value of Nuclear Decommissioning Trust Fund Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	$ 1,191	$ 1,037
Fermi 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	1,172	1,021
Fermi 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	3	3
Low level radioactive waste [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	16	13
Nuclear Decommissioning Trust Fund [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	$ 1,191	$ 1,037

XML

Commitments and Contingencies (Notes)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

Environmental

Electric

Air - DTE Electric is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze, mercury, and other air pollution. These rules have led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, mercury and other emissions. To comply with these requirements, DTE Electric has spent approximately $2 billion through 2013. The Company estimates DTE Electric will make capital expenditures of approximately $280 million in 2014 and up to approximately $1.2 billion of additional capital expenditures through 2021 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and 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. 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 CAIR in place. The EPA's petition seeking a rehearing of the U.S. Court of Appeals' decision regarding the CSAPR was denied on January 24, 2013. On June 24, 2013, the U.S. Supreme Court granted the EPA's petition asking the Court to review the D.C. Circuit Court's decision on CSAPR. A ruling by the Supreme Court is expected in 2014. Notwithstanding the appeal filed with the Supreme Court, the EPA and a number of states have started working on the framework of revised CSAPR regulations which we anticipate to be proposed in the next few years.

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 MATS rule requires reductions of mercury and other hazardous air pollutants beginning in 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 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 have been economical for FGD installations to 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. In June 2010, the EPA issued a NOV/FOV making similar allegations related to a 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 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. On March 28, 2013, the Court of Appeals 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 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.

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

On March 13, 2013, the Sierra Club filed suit against DTE Energy and DTE Electric alleging violations of the Clean Air Act at four of DTE Electric's coal-fired power plants. The plaintiffs allege 1,4996-minute periods of excess opacity of air emissions from 2007-2012 at those facilities. The suit asks that the 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 amended complaint in the first quarter of 2014. The resolution of this matter is not expected to have a material effect on the 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. 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 proposed revised steam electric effluent 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, 2013 and 2012, the Company had $8 million and $9 million, respectively, accrued for remediation. Any 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 three permitted engineered ash storage facilities to dispose of fly ash from coal fired power 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.

Gas

Contaminated Sites — Gas segment, owned or previously owned, 15 former MGP sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites. Cleanup activities associated with these sites will be conducted over the next several years. The MPSC has established a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites. As of December 31, 2013 and 2012, the Company had $28 million and $29 million, accrued for remediation, respectively. Any change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows. The Company anticipates the cost amortization methodology approved by the MPSC for DTE Gas, which allows DTE Gas to amortize the MGP costs over a ten-year period beginning with the year subsequent to the year the MGP costs were incurred and the cost deferral and rate recovery mechanism for Citizens approved by the City of Adrian, will prevent environmental costs from having a material adverse impact on the Company’s results of operations.

Non-utility

The Company’s non-utility 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 received two NOVs from the Pennsylvania Department of Environmental Protection (PADEP) in 2010 alleging violations of the permit for the Pennsylvania coke battery facility in connection with coal pile storm water runoff. The Company has implemented best management practices to address this issue. The Company recently received a permit to upgrade its existing waste water treatment system and is currently seeking a permit from the PADEP to upgrade its wastewater treatment technology to a biological treatment facility. The Company expects to spend less than $3 million on the existing waste water treatment system to comply with existing water discharge requirements and to upgrade its coal pile storm water runoff management program.

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

Other

In March 2011, the EPA finalized a new set of regulations regarding the identification of non-hazardous secondary materials that are considered solid waste, industrial boiler and process heater maximum achievable control technologies (IBMACT) for major and area sources, and commercial/industrial solid waste incinerator new source performance standard and emission guidelines (CISWI). The effective dates of the major source IBMACT and CISWI regulations were stayed and a re-proposal was issued by the EPA in December 2011. Final IBMACT and CISWI were issued by the EPA in December 2012. The Company is developing compliance plans to upgrade or convert existing industrial boilers to natural gas and to perform required energy assessments in compliance with the applicable new standards. Capital costs for the boiler conversions and the expenses for the one-time energy assessments are not expected to be material.

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 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 gathering stage and any required emission reductions for DTE Energy sources to meet the standard cannot be estimated currently.

Nuclear Operations

Property Insurance

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

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

DTE Electric has $500 million in primary coverage and $2.25 billion of excess coverage for stabilization, decontamination, debris removal, repair and/or replacement of property and decommissioning. The combined coverage limit for total property damage is $2.75 billion, subject to a $1 million deductible. 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 $34 million per event if the loss associated with any one event at any nuclear plant should exceed the accumulated funds available to NEIL.

Public Liability Insurance

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 $127.3 million could be levied against each licensed nuclear facility, but not more than $19 million per year per facility. Thus, deferred premium charges could be levied against all owners of licensed nuclear facilities in the event of a nuclear incident at any of these facilities.

Nuclear Fuel Disposal Costs

In accordance with the Federal Nuclear Waste Policy Act of 1982, DTE Electric has a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. DTE Electric is obligated to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold. The fee is a component of nuclear fuel expense. The DOE's Yucca Mountain Nuclear Waste Repository program for the acceptance and disposal of spent nuclear fuel was terminated in 2011. DTE Electric currently employs a spent nuclear fuel storage strategy utilizing a fuel pool. The Company continues to develop its on-site dry cask storage facility and has scheduled the initial offload from the spent fuel pool 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 February 2013, the U.S. Court of Appeals for the District of Columbia (COA) granted a motion to reopen the fee adequacy litigation to review the DOE's latest fee adequacy report which was released in January 2013. In November 2013, the COA issued a decision ordering the DOE to submit a proposal to Congress to reduce the nuclear waste fee to zero until the DOE enacts an alternative nuclear waste management plan. In January 2014, the DOE submitted such a proposal to Congress that will take effect in 90 legislative calendar days, absent legislative action to the contrary. Simultaneously, the DOE filed a petition for rehearing of the November 2013 decision with the COA. DTE Electric continues to pay fees to the U.S. government's nuclear waste fund pending further developments in this proceeding.

Synthetic Fuel Guarantees

The Company discontinued the operations of its synthetic fuel production facilities throughout the United States as of December 31, 2007. The Company provided certain guarantees and indemnities in conjunction with the sales of interests in its synfuel facilities. The guarantees cover potential commercial, environmental, oil price and tax-related obligations and will survive until 90 days after expiration of all applicable statutes of limitations. The Company estimates that its maximum potential liability under these guarantees at December 31, 2013 is approximately $1.1 billion. Payment under these guarantees is considered remote.

Reduced Emissions Fuel Guarantees

The Company has provided certain guarantees and indemnities in conjunction with the sales of interests in its reduced emissions fuel facilities. The guarantees cover potential commercial, environmental, and tax-related obligations and will survive until 90 days after expiration of all applicable statutes of limitations. The Company estimates that its maximum potential liability under these guarantees at December 31, 2013 is approximately $144 million. Payment under these guarantees is considered remote.

Other Guarantees

In certain limited circumstances, the Company enters into contractual guarantees. The Company may guarantee another entity’s obligation in the event it fails to perform. The Company may provide guarantees in certain indemnification agreements. Finally, the Company may provide indirect guarantees for the indebtedness of others. The Company’s guarantees are not individually material with maximum potential payments totaling $60 million at December 31, 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, 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.

Labor Contracts

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.

Purchase Commitments    

As of December 31, 2013, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments, renewable energy contracts and energy trading contracts. The Company estimates that these commitments will be approximately $8.6 billion from 2014 through 2051 as detailed in the following table:

	(In millions)
2014	$	2,617
2015	1,195
2016	643
2017	345
2018	311
2019 — 2051	3,487
	$	8,598

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

Bankruptcies

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 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 Company's utilities provide services to the city of 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 impact on its financial results.

Other Contingencies

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

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

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Retirement Benefits and Trusteed Assets (Pension Plan - Reconciliation of Obligations, Assets and Funded Status of Plans) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Regulatory Assets	$ 2,863	$ 4,417
Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Accumulated benefit obligation, end of year	4,068	4,349
Benefit obligation, beginning of year	4,729	4,195
Service cost	94	82	69
Interest cost	192	204	202
Plan amendments	(3)	0
Actuarial loss	(400)	474
Special termination benefits	0	2	2
Benefits paid	(232)	(228)
Benefit obligation, end of year	4,380	4,729	4,195
Plan assets at fair value, beginning of the year	3,223	2,886
Actual return on plan assets	445	325
Company contributions	284	240
Plan assets at fair value, end of the year	3,720	3,223	2,886
Funded status of the plans	(660)	(1,506)
Current liabilities	(7)	(8)
Noncurrent liabilities	(653)	(1,498)
Pension and Other Postretirement Defined Benefit Plans, Liabilities	(660)	(1,506)
Net actuarial loss recognized in other comprehensive loss	174	205
Prior service cost (credit) recognized in other comprehensive income	(1)	(2)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax	173	203
Net actuarial loss recognized in regulatory assets	1,654	2,413
Prior service cost recognized in regulatory assets	6	7
Regulatory Assets	$ 1,660	$ 2,420

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Retirement Benefits and Trusteed Assets (OPEB - Fair Value Measurements using Level 3 Inputs) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	$ (1)	$ 58
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	205	155
Realized gains (losses)	2	(5)
Unrealized gains (losses)	21	14
Purchases	41	122
Sales	(9)	(81)
Ending Balance	260	205
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	23	8
Other Postretirement Benefit Plan, Defined Benefit [Member] | Hedge Funds and Similar Investments [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	119	95
Realized gains (losses)	0	6
Unrealized gains (losses)	14	0
Purchases	26	86
Sales	0	(68)
Ending Balance	159	119
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	14	6
Other Postretirement Benefit Plan, Defined Benefit [Member] | Private Equity and Other [Member]
Defined Benefit Plans Fair Value Measurements Using Significant Unobservale Inputs [Line Items]
Beginning Balance	86	60
Realized gains (losses)	2	(11)
Unrealized gains (losses)	7	14
Purchases	15	36
Sales	(9)	(13)
Ending Balance	101	86
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	$ 9	$ 2

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Retirement Benefits and Trusteed Assets (OPEB - Benefits related to Qualified and Nonqualified Pension Plans Expected to be paid in the Next Ten Years) (Details) (Other Postretirement Benefit Plan, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Other Postretirement Benefit Plan, Defined Benefit [Member]
Benefits Expected to be Paid Over the Next Five Years and Thereafter [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in next twelve months	$ 103
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	110
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	115
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	123
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	130
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	724
Total Expected Future Benefit Payments	$ 1,305

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Financial and Other Derivative Instruments (Netting Offsets of Derivative Assets and Liabilites) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Netting Offsets of Derivative Assets and Liabilities [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 833	$ 1,016
Derivative Asset, Fair Value, Gross Liability	(707)	(869)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	126	147
Derivative Liability, Fair Value, Gross Liability	(936)	(1,020)
Derivative Liability, Fair Value, Gross Asset	698	869
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(238)	(151)
Natural Gas Commodity Contract [Member]
Netting Offsets of Derivative Assets and Liabilities [Line Items]
Derivative Asset, Fair Value, Gross Asset	396	645
Derivative Asset, Fair Value, Gross Liability	(382)	(605)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	14	40
Derivative Liability, Fair Value, Gross Liability	(503)	(661)
Derivative Liability, Fair Value, Gross Asset	395	605
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(108)	(56)
Electricity Commodity Contract [Member]
Netting Offsets of Derivative Assets and Liabilities [Line Items]
Derivative Asset, Fair Value, Gross Asset	400	360
Derivative Asset, Fair Value, Gross Liability	(291)	(258)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	109	102
Derivative Liability, Fair Value, Gross Liability	(398)	(351)
Derivative Liability, Fair Value, Gross Asset	269	258
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(129)	(93)
Other Commodity Contract [Member]
Netting Offsets of Derivative Assets and Liabilities [Line Items]
Derivative Liability, Fair Value, Gross Liability	(34)	(7)
Derivative Liability, Fair Value, Gross Asset	34	6
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	(1)
Other Contract [Member]
Netting Offsets of Derivative Assets and Liabilities [Line Items]
Derivative Asset, Fair Value, Gross Asset	37	11
Derivative Asset, Fair Value, Gross Liability	(34)	(6)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	3	5
Derivative Liability, Fair Value, Gross Liability	(1)	(1)
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ (1)	$ (1)

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Goodwill (Tables)

12 Months Ended

Dec. 31, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill [Table Text Block]

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

	2013		2012
	(In millions)
Balance as of January 1	$	2,018	$	2,020
Goodwill attributable to sale of Unconventional Gas Production business	—		(2		)
Balance at December 31	$	2,018	$	2,018

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Income Taxes (Notes)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

Income Tax Summary

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

	2013			2012			2011
	(In millions)
Income before income taxes	$	922		$	960		$	991
Income tax expense at 35% statutory rate	$	323		$	336		$	347
Production tax credits	(68		)	(49		)	(6		)
Investment tax credits	(6		)	(6		)	(6		)
Depreciation	(4		)	(4		)	(4		)
AFUDC - Equity	(5		)	(4		)	(1		)
Employee Stock Ownership Plan dividends	(4		)	(4		)	(4		)
Domestic production activities deduction	(14		)	(14		)	(7		)
State and local income taxes, net of federal benefit	37			37			37
Enactment of Michigan Corporate Income Tax, net of federal expense	—			—			(87		)
Other, net	(5		)	(6		)	(1		)
Income tax expense	$	254		$	286		$	268
Effective income tax rate	27.5		%	29.8		%	27.0		%

Components of income tax expense were as follows:

	2013		2012			2011
	(In millions)
Current income tax expense (benefit)
Federal	$	74	$	190		$	27
State and other income tax	16		49			21
Total current income taxes	90		239			48
Deferred income tax expense (benefit)
Federal	122		39			318
State and other income tax	42		8			(98		)
Total deferred income taxes	164		47			220
Total income taxes from continuing operations	254		286			268
Discontinued operations	—		(29		)	(1		)
Total	$	254	$	257		$	267

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:

	2013			2012
	(In millions)
Property, plant and equipment	$	(3,372	)	$	(3,389	)
Securitized regulatory assets	(127		)	(256		)
Alternative minimum tax credit carry-forwards	266			254
Merger basis differences	18			42
Pension and benefits	(30		)	(33		)
Other comprehensive loss	—			101
Derivative assets and liabilities	—			66
State net operating loss and credit carry-forwards	43			37
Other	(110		)	41
	(3,312		)	(3,137		)
Less valuation allowance	(37		)	(33		)
	$	(3,349	)	$	(3,170	)
Current deferred income tax assets (liabilities)	$	(28	)	$	21
Long-term deferred income tax liabilities	(3,321		)	(3,191		)
	$	(3,349	)	$	(3,170	)
Deferred income tax assets	$	1,808		$	1,038
Deferred income tax liabilities	(5,157		)	(4,208		)
	$	(3,349	)	$	(3,170	)

Production tax credits earned in prior years but not utilized totaled $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 $43 million and $37 million at December 31, 2013 and 2012, respectively. The state net operating loss and credit carry-forwards expire from 2014 through 2033. The Company has recorded valuation allowances at December 31, 2013 and 2012 of approximately $37 million and $33 million, respectively, with respect to these deferred tax assets. In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.

Uncertain Tax Positions

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

	2013			2012			2011
	(In millions)
Balance at January 1	$	11		$	48		$	28
Additions for tax positions of prior years	—			—			27
Reductions for tax positions of prior years	—			(2		)	(4		)
Additions for tax positions of current year	—			1			1
Settlements	—			(30		)	(3		)
Lapse of statute of limitations	(1		)	(6		)	(1		)
Balance at December 31	$	10		$	11		$	48

The Company had $2 million and $3 million of unrecognized tax benefits at December 31, 2013 and at 2012, respectively, that, if recognized, would favorably impact its effective tax rate. During the next twelve months, it is reasonably possible that the statute of limitation will expire on various state tax returns. As a result, the Company believes that it is possible that there will be a decrease in unrecognized tax benefits of up to $1 million within the next twelve months.

The Company recognizes interest and penalties pertaining to income taxes in Interest expense and Other expenses, respectively, on its Consolidated Statements of Operations. Accrued interest pertaining to income taxes totaled $1 million and $1 million at December 31, 2013 and 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 2011, respectively.

In 2013, the Company settled a federal tax audit for the 2011 tax year, which resulted in the recognition of a nominal amount of unrecognized tax benefits. The Company's federal income tax returns for 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.

Michigan Corporate Income Tax (MCIT)

In May 2011, the Michigan Business Tax (MBT) was repealed and the MCIT was enacted and became effective January 1, 2012. The MCIT subjects corporations with business activity in Michigan to a 6% tax rate on an apportioned income tax base and eliminates the modified gross receipts tax and nearly all credits available under the MBT. The MCIT also eliminated the future deductions allowed under MBT that enabled companies to establish a one-time deferred tax asset upon enactment of the MBT to offset deferred tax liabilities that resulted from enactment of the MBT.

As a result of the enactment of the MCIT, the net state deferred tax liability was remeasured to reflect the impact of the MCIT tax rate on cumulative temporary differences expected to reverse after the effective date. The net impact of this remeasurement was a reduction of the net deferred tax assets attributable to our regulated utilities, partially offset by a decrease in deferred tax liabilities attributable to our non-utilities of $87 million primarily due to a lower apportionment factor from inclusion of non-utility entities in DTE Energy's unitary Michigan tax return and was recognized as a reduction to income tax expense in 2011.

No recognition of these non-cash transactions have been reflected in the Consolidated Statements of Cash Flows.

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Earnings Per Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Basic Earnings per Share
Net Income Attributable to DTE Energy Company	$ 124	$ 198	$ 105	$ 234	$ 81	$ 227	$ 146	$ 156	$ 661	$ 610	$ 711
Average number of common shares outstanding									175	171	169
Weighted average net restricted shares outstanding									1	1	1
Dividends declared, Common Stock									453	413	392
Dividends declared, Net restricted shares									1	1	1
Total distributed earnings									454	414	393
Net income less distributed earnings, Basic									207	196	318
Distributed (dividends per common share)									$ 2.59	$ 2.42	$ 2.32
Undistributed									$ 1.17	$ 1.14	$ 1.87
Total Basic Earnings per Common Share	$ 0.70	$ 1.13	$ 0.60	$ 1.35	$ 0.47	$ 1.32	$ 0.86	$ 0.91	$ 3.76	$ 3.56	$ 4.19
Diluted Earnings per Share
Net Income Attributable to DTE Energy Company	124	198	105	234	81	227	146	156	661	610	711
Common shares for dilutive calculation									175	171	169
Average incremental shares from assumed exercise of options									0	1	1
Weighted Average Number Common shares for dilutive calculation									175	172	170
Weighted average net restricted shares outstanding									1	1	1
Dividends declared, Common Stock									453	413	392
Dividends declared, Net restricted shares									1	1	1
Total distributed earnings									454	414	393
Undistributed									$ 207	$ 196	$ 318
Distributed (dividends per common share)									$ 2.59	$ 2.42	$ 2.32
Earnings Per Share, Diluted, Undistributed									$ 1.17	$ 1.13	$ 1.86
Total Diluted Earnings per Common Share	$ 0.70	$ 1.13	$ 0.60	$ 1.34	$ 0.47	$ 1.31	$ 0.86	$ 0.91	$ 3.76	$ 3.55	$ 4.18