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, 2014
¨	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 30, 2014, the aggregate market value of the Registrant’s voting and non-voting common equity held by non-affiliates was approximately $13.3 billion (based on the New York Stock Exchange closing price on such date). There were 177,229,483 shares of common stock outstanding at January 30, 2015.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information in DTE Energy Company’s definitive Proxy Statement for its 2015 Annual Meeting of Common Shareholders to be held May 7, 2015, 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.

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	20
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	21
Item 6.	Selected Financial Data	23
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
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	109
Item 9A.	Controls and Procedures	109
Item 9B.	Other Information	109
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	109
Item 11.	Executive Compensation	109
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	109
Item 13.	Certain Relationships and Related Transactions, and Director Independence	109
Item 14.	Principal Accountant Fees and Services	109
PART IV
Item 15.	Exhibits and Financial Statement Schedule	110
	Signatures	119
EX-3.12
EX-4.287
EX-4.288
EX-10.92
EX-10.93
EX-12.60
EX-21.10
EX-23.28
EX-31.95
EX-31.96
EX-32.95
EX-32.96
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

AFUDC	Allowance for Funds Used During Construction
CFTC	U.S. Commodity Futures Trading Commission
COA	U.S Court of Appeals for the District of Columbia
Company	DTE Energy Company and any subsidiary companies
Customer Choice	Michigan legislation giving customers the option of retail access to alternative suppliers for electricity and natural gas
DOE	U.S. Department of Energy
DTE Electric	DTE Electric Company (a direct wholly owned subsidiary of DTE Energy Company) and subsidiary companies
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
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FOV	Finding of Violation
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
IRS	Internal Revenue Service
MBT	Michigan Business Tax
MCIT	Michigan Corporate Income Tax
MCOA	Michigan Court of Appeals
MDEQ	Michigan Department of Environmental Quality
MGP	Manufactured Gas Plant
MISO	Midcontinent Independent System Operator, Inc.
MPSC	Michigan Public Service Commission
MTM	Mark-to-market
NAV	Net Asset Value
NEIL	Nuclear Electric Insurance Limited
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.
NOV	Notice of Violation
NRC	U.S. Nuclear Regulatory Commission
PLD	City of Detroit's Public Lighting Department
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.

1

DEFINITIONS

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
REF	Reduced Emissions Fuel
SEC	Securities and Exchange Commission
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
TRIA	Terrorism Risk Insurance Extension Act of 2005
TRM	A Transitional Reconciliation Mechanism authorized by the MPSC that allows DTE Electric to recover through rates the deferred net incremental revenue requirement associated with the transition of PLD customers to DTE Electric's distribution system
VEBA	Voluntary Employees Beneficiary Association
VIE	Variable Interest Entity

Units of Measurement
Bcf	Billion cubic feet of natural gas
BTU	Heat value (energy content) of fuel
kWh	Kilowatthour of electricity
Mcf	Thousand cubic feet of gas
MMBtu	One million BTU
MMcf/d	Million cubic feet of gas per day
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 EPA, 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 retail access 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 risk of a major safety incident at an electric or gas distribution, storage or generation facility;

• 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;

• contract disputes, binding arbitration, litigation and related appeals; and

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

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

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Part I

Items 1. and 2. Business and Properties

General

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 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. For financial information by segment for the last three years see Note 20 to the Consolidated Financial Statements in Item 8 of this Report, "Segment and Related Information".

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 principally of DTE Gas, which 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 gas storage and transportation capacity.

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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 renewable 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

	2014		2013		2012
	(In millions)
Residential	$	2,168	$	2,351	$	2,354
Commercial	1,761		1,883		1,898
Industrial	767		799		784
Other (a)	494		45		152
Subtotal	5,190		5,078		5,188
Interconnection sales (b)	93		121		105
Total Revenue	$	5,283	$	5,199	$	5,293

______________________________

(a) Includes revenue associated with under or over recoveries of tracking mechanisms and deferred gain amortization of the previously reversed RDM liability.

(b) 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 30.3 million tons of low-sulfur western coal and approximately 3.5 million tons of Appalachian coal to be delivered from 2015 to 2017. All of these contracts have pricing schedules. We have approximately 91% of our 2015 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. Contracts covering expected vessel transportation requirements for delivery of purchased coal to our generating facilities are currently being negotiated.

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 DTE Electric's property is subject to the lien of a mortgage.

Generating plants owned and in service as of December 31, 2014 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	785	7.5	1979
Monroe (c)	Monroe	3,080	29.5	1971, 1973 and 1974
River Rouge	Wayne	542	5.2	1957 and 1958
St. Clair	St. Clair	1,398	13.4	1953, 1954, 1959, 1961 and 1969
Trenton Channel	Wayne	609	5.8	1949 and 1968
		7,450	71.3
Oil or Gas-fueled Peaking Units	Various	936	9.0	1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric Fermi 2	Monroe	1,124	10.8	1988
Hydroelectric Pumped Storage Ludington (d)	Mason	917	8.9	1973
		10,427	100.0

_______________________________________

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

(b) The Belle River capability represents DTE Electric’s entitlement to 81% of the capacity and energy of the plant. See Note 6 to the Consolidated Financial Statements in Item 8 of this Report, "Jointly Owned Utility Plant".

(c) The Monroe generating plant provided 38% of DTE Electric’s total 2014 power plant generation.

(d) Represents DTE Electric’s 49% interest in Ludington with a total capability of 1,872 MW. See Note 6 to the Consolidated Financial Statements in Item 8 of this Report, "Jointly Owned Utility Plant".

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 1,000 MW of owned or contracted renewable energy generation, principally wind turbines located in Gratiot, Tuscola, Huron and Sanilac counties in Michigan, at December 31, 2014. Approximately 900 MW was in commercial operation at December 31, 2014. DTE Electric expects to meet the 10% renewable portfolio standard in 2015.

DTE Electric expects to retire Trenton Channel Unit 7 (109 MW) in April 2016. Over the next fifteen years, DTE Electric expects to retire additional coal-fired generation and to increase the proportion of its generation mix attributable to natural gas-fired generation and renewables. In January 2015, DTE Electric closed on the acquisition of a 732 MW simple-cycle natural gas facility in Carson City, Michigan (Montcalm County). See Note 22 - Subsequent Event of the Notes to Consolidated Financial Statements in Item 8 of this Report.

DTE Electric owns and operates 675 distribution substations with a capacity of approximately 32,867,000 kilovolt-amperes (kVA) and approximately 432,900 line transformers with a capacity of approximately 23,359,000 kVA.

Circuit miles of electric distribution lines owned and in service as of December 31, 2014:

	Circuit Miles
Operating Voltage-Kilovolts (kV)	Overhead	Underground
4.8 kV to 13.2 kV	27,807	14,647
24 kV	182	682
40 kV	2,290	385
120 kV	60	8
	30,339	15,722

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 7, 8, 11 and 17 to the Consolidated Financial Statements in Item 8 of this Report, "Asset Retirement Obligations", "Regulatory Matters", "Fair Value" and "Commitments and Contingencies".

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.

7

Strategy and Competition

Our electrical generation operations seek to provide the energy needs of our customers in a cost effective manner. With potential capacity constraints in our MISO region, there will be increased dependency on our generation to provide reliable service and price stability for our customers. This generation will require a large investment driven by our aging coal fleet along with increased environmental regulations.

Our distribution operations focus is on distributing energy in a safe, cost effective, and reliable manner to our customers. We seek to increase operational efficiencies to increase our customer satisfaction at an affordable rate.

The electric Customer Choice program in Michigan gives our electric customers the option of retail access to alternative electric suppliers, subject to limits. Customers with retail access to alternative electric suppliers represented approximately 10% of retail sales in 2014, 2013 and 2012 and consisted 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 retail access related migration, mitigating some of the unfavorable effects of electric retail access on our financial performance and full service customer rates. We expect that in 2015 customers with retail access to 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.

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.

GAS

Description

Our Gas segment consists principally of DTE Gas which 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.

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

Revenue by Service

	2014		2013		2012
	(In millions)
Gas sales	$	1,233	$	1,093	$	957
End user transportation	218		212		198
Intermediate transportation	68		59		58
Storage and other	117		110		102
Total Revenue	$	1,636	$	1,474	$	1,315

• 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 retail access 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 high-pressure transportation system to transport the natural gas to storage fields, pipeline interconnections or other locations.

8

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

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.

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 2014. 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 2017.

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	2017
Viking Gas Transmission Company	21	2017
Vector Pipeline L.P.	50	2017
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 1,313,000 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 141 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 DTE Gas's 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 16 to the Consolidated Financial Statements in Item 8 of the Report, "Capital and Operating Leases".

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 8 and 17 to the Consolidated Financial Statements in Item 8 of this Report, "Regulatory Matters" and "Commitments and Contingencies".

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 our storage and transportation services for gas producers, marketers, distribution companies, end-user customers 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. 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	%	47.5-miles of installed 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. In Pennsylvania, our gathering and pipeline assets are subject to the rules and regulations of the Pennsylvania Public Utility Commission. Bluestone Lateral is regulated as a transmission line in the state of New York by the New York Public Service Commission.

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. Gas Storage and Pipelines has an agreement with Southwestern Energy Production Company to support its Bluestone Lateral and Susquehanna gathering system. 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 and Vector expansions and laterals, Bluestone compression and laterals, Susquehanna gathering expansions, and other Marcellus/Utica shale midstream development or partnering opportunities, such as the proposed Nexus pipeline. 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 renewable 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.

On-Site 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 hold ownership interests in and operate five renewable generating plants with a capacity of 228 MWs. 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: 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 and mercury. 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 IRS. 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 2015 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	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 MI, IN, OH & NY	Electric Distribution, Chilled Water, 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 & PA	Electricity and Chilled Water
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

	2014		2013		2012
	(In millions)
Production Tax Credits Generated (Allocated to DTE Energy)
REF	$	84	$	44	$	35
Power Generation	11		8		7
Landfill Gas Recovery	2		1		1
	$	97	$	53	$	43

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 EPA, U.S. Department of Homeland Security, DOE and various state utility commissions.

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, on-site energy, renewable power, and REF businesses. We also will continue to pursue opportunities to provide asset management and operations services to third parties. There are limited competitors for our existing disparate businesses who provide similar products and services. Our operations are dependent upon a limited number of customers, and the loss of any one or a few customers could have a material adverse effect on the Power and Industrial Projects business.

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

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We intend to focus on the following areas for growth:

• Obtaining investors 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 2015 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 and gas 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. 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 natural gas contracts are deemed derivatives; whereas, natural gas inventory, contracts for pipeline transportation, renewable energy credits and storage assets are not derivatives. As a result, this segment will 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 CFTC, U.S. Department of Homeland Security and DOE.

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 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 and gas marketers, financial institutions, traders, utilities and other energy providers. The Energy Trading business is dependent upon the availability of capital and an investment grade credit rating. The Company believes it has ample available capital capacity to support Energy Trading activities. We monitor our use of capital closely to ensure that our commitments do not exceed capacity. A material credit restriction would negatively impact our financial performance. Competitors with greater access to capital or at a lower cost may have a competitive advantage. We have risk management and credit processes to monitor and mitigate risk.

CORPORATE AND OTHER

Description

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

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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	$	150	$	—	$	—	$	150
Water	70		—		15		85
Contaminated and other sites	180		25		—		205
Estimated total future expenditures through 2019	$	400	$	25	$	15	$	440
Estimated 2015 expenditures	$	100	$	5	$	10	$	115
Estimated 2016 expenditures	$	40	$	5	$	5	$	50

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. These rulemakings could require additional controls for sulfur dioxide, nitrogen oxides and other hazardous air pollutants over the next few years.

The EPA is implementing regulatory actions under the Clean Air Act to address emissions of greenhouse gases (GHGs) from the utility sector and other sectors of the economy. Among these actions, the EPA is proposing performance standards for emissions of carbon dioxide from new and existing electric generating units (EGUs). The EPA plans to issue a final standard for both new and existing sources by July 2015. The carbon standards for new sources are not expected to have a material impact on the Company, since the Company has no plans to build new coal-fired generation. 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 credits from market sources, higher costs of purchased power, 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 as authorized by the MPSC.

Water - The EPA finalized regulations on cooling water intake in August 2014. DTE Electric is conducting studies to determine the best technology for reducing the environmental impacts of the cooling water intake structures at each of its facilities. DTE Electric may be required to install technologies to reduce the impacts of the cooling water intakes. The EPA has also issued proposed steam electric effluent guidelines. These rules 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 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, will prevent environmental costs from having a material adverse effect on the Company's 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.

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In December 2014, the EPA released a pre-publication version of a rule to regulate coal ash. This rule is based on the continued listing of ash as a non-hazardous waste, and relies on various self-implementation design and performance standards. The rule is still being evaluated and it is not possible to quantify its impact at this time. DTE Electric owns and operates three permitted engineered ash storage facilities to dispose of fly ash from coal fired power plants and operates a number of smaller impoundments at its power plants.

See Notes 8 and 17 to the Consolidated Financial Statements in Item 8 of this Report, "Regulatory Matters" and "Commitments and Contingencies" and Management’s Discussion and Analysis in Item 7 of this Report.

EMPLOYEES

We had approximately 10,000 employees as of December 31, 2014, 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 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 the MPSC 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. MPSC rate orders and energy legislation enacted by the State of Michigan in 2008 have placed a 10% cap on the total potential retail access 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 retail access migration is sensitive to market price and full service electric price changes. We are required under current regulation to provide full service to retail access customers that choose to return, potentially resulting in the need for additional generating capacity.

The MISO regional energy market, including the State of Michigan, is expected to face capacity constraints beginning in 2016 due primarily to the retirement of coal-fired generation caused by increasingly stringent environmental requirements. Significant investment in new natural gas-fired generation and renewables will be required. Under the current regulatory structure, retail access customers do not fund capacity costs potentially impacting electric supply reliability and utility customer affordability.

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.

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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.

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. In addition, while we have a nuclear decommissioning trust fund to finance the decommissioning of our nuclear generating plant, there can be no assurances that such fund will be sufficient to fund the cost of decommissioning.

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.

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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.

Our ability to access capital markets is important.  Our ability to access capital markets is important to operate our businesses and to fund capital investments. 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, reduced emission fuel, renewable energy generation and gas production operations. All production tax credits taken after 2012 are subject to audit by the 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.

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Weather significantly affects operations.  At both utilities, 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. At DTE Electric, 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. DTE Gas can experience higher than anticipated expenses from emergency repairs on its gas distribution infrastructure required as a result of weather related issues.

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.

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 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.

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Failure to attract and retain 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 attract and retain skilled employees. Competition for skilled employees in some areas is high and the inability to attract and retain these employees could adversely affect our business and future operating results. In addition, we have an aging utility workforce and the failure of a successful transfer of knowledge and expertise could negatively impact our operations.

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.

The Company's businesses have safety risks. The Company's electric and gas distribution systems, power plants, gas infrastructure, wind energy equipment and other facilities could be involved in incidents that result in injury or property loss to employees, customers, or the public. Although we have insurance coverage for many potential incidents, depending upon the nature and severity of any incident, the Company could experience financial loss, damage to its reputation, and negative consequences from regulatory agencies or other public authorities.

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

For more information on material legal proceedings and matters related to us and our subsidiaries, see Notes 8 and 17 to the Consolidated Financial Statements in Item 8 of this Report, "Regulatory Matters" and "Commitments and Contingencies".

Item 4. Mine Safety Disclosures

Not applicable.

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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
2014
	First	$	74.61	$	64.84	$	0.6550
	Second	$	79.45	$	72.76	$	0.6550
	Third	$	78.89	$	71.60	$	0.6900
	Fourth	$	90.77	$	75.76	$	0.6900
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

At December 31, 2014, there were 176,991,231 shares of our common stock outstanding. These shares were held by a total of 61,823 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 $470 million in 2014, $445 million in 2013 and $407 million in 2012. 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.

For information on dividend restrictions see Note 15 to the Consolidated Financial Statements in Item 8 of this Report, "Short-Term Credit Arrangements and Borrowings".

All of our equity compensation plans that provide for the annual awarding of stock-based compensation have been approved by shareholders. For additional detail see Note 19 of the Notes to Consolidated Financial Statements in Item 8 of this Report, "Stock-Based Compensation".

See the following table for information as of December 31, 2014.

	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	444,278	$	43.56	3,915,570

21

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, 2014:

	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
10/01/2014 — 10/31/2014	299	$	76.28	—	—	—
11/01/2014 — 11/30/2014	—	—		—	—	—
12/01/2014 — 12/31/2014	947	$	66.03	—	—	—
Total	1,246			—

_______________________________________

(a) Represents shares of common stock purchased on the open market to provide shares to participants under various employee compensation and incentive programs. Also includes shares of common stock withheld to satisfy income tax obligations upon the vesting of restricted stock based on the price in effect at the grant date.

COMPARISON OF CUMULATIVE FIVE YEAR TOTAL RETURN

Total Return To Shareholders

(Includes reinvestment of dividends)

	Annual Return Percentage Year Ended December 31,
Company/Index	2010	2011	2012	2013	2014
DTE Energy Company	9.06	25.76	14.90	14.89	34.61
S&P 500 Index	15.06	2.11	16.00	32.39	13.69
S&P 500 Multi-Utilities Index	11.08	18.41	4.24	17.88	28.94

	Indexed Returns Year Ended December 31,
	Base Period
Company/Index	2009	2010	2011	2012	2013	2014
DTE Energy Company	100	109.06	137.15	157.59	181.06	243.73
S&P 500 Index	100	115.06	117.49	136.30	180.44	205.14
S&P 500 Multi-Utilities Index	100	111.08	131.53	137.10	161.62	208.38

22

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.

	2014		2013		2012			2011			2010
	(In millions, except per share amounts)
Operating Revenues	$	12,301	$	9,661	$	8,791		$	8,858		$	8,525
Net Income Attributable to DTE Energy Company
Income from continuing operations attributable to DTE Energy Company (a)	$	905	$	661	$	666		$	714		$	638
Discontinued operations (b)	—		—		(56		)	(3		)	(8		)
Net Income Attributable to DTE Energy Company	$	905	$	661	$	610		$	711		$	630
Diluted Earnings Per Common Share
Income from continuing operations	$	5.10	$	3.76	$	3.88		$	4.20		$	3.78
Discontinued operations	—		—		(0.33		)	(0.02		)	(0.04		)
Diluted Earnings Per Common Share	$	5.10	$	3.76	$	3.55		$	4.18		$	3.74
Financial Information
Dividends declared per share of common stock	$	2.69	$	2.59	$	2.42		$	2.32		$	2.18
Total assets	$	27,974	$	25,935	$	26,339		$	26,009		$	24,896
Long-term debt, including capital leases	$	8,343	$	7,214	$	7,014		$	7,187		$	7,089
Shareholders’ equity	$	8,327	$	7,921	$	7,373		$	7,009		$	6,722

_______________________________________

(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 2014 operating revenues of approximately $12.3 billion and approximately $28.0 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:

	2014		2013		2012
	(In millions, except per share amounts)
Income from continuing operations attributable to DTE Energy Company	$	905	$	661	$	666
Diluted earnings per common share from continuing operations	$	5.10	$	3.76	$	3.88

The increase in 2014 income from continuing operations attributable to DTE Energy Company is primarily due to higher earnings in the Energy Trading, Electric, Power and Industrial Projects, and Gas Storage and Pipelines segments. The decrease in 2013 income from continuing operations attributable to DTE Energy Company 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.

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 base infrastructure, new generation and environmental compliance capital 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 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 and the issuance of debt. 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 2015-2019 period are estimated at $5.7 billion for base infrastructure, $1.4 billion for new generation and $400 million for environmental compliance. 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 2015-2019 period are estimated at $1 billion for base infrastructure and $600 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 for DTE Gas and authorized the recovery of the cost of service related to $77 million of annual investment in its gas main renewal, meter move out, and pipeline integrity programs. In November 2014, DTE Gas filed an application with the MPSC for approval of an increased infrastructure recovery mechanism surcharge to recover an additional $47 million of annual capital expenditures for its gas main renewal program. DTE Gas plans to seek regulatory approval in general rate case filings for base infrastructure capital expenditures consistent with prior ratemaking treatment.

24

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. mercury, and other 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 spent approximately $2.2 billion through 2014. It is estimated that DTE Electric will make capital expenditures of approximately $100 million in 2015 and up to approximately $30 million of additional capital expenditures through 2019 based on current regulations.

As directed by a June 2013 Presidential Memorandum, the EPA is implementing regulatory actions under the Clean Air Act to address emissions of greenhouse gases (GHGs) from the utility sector and other sectors of the economy. Among these actions, the EPA is proposing performance standards for emissions of carbon dioxide from new and existing electric generating units (EGUs). The new source performance standards for new EGUs were proposed in September 2013 and the standards for existing, reconstructed and modified EGUs were proposed in June 2014. The EPA plans to issue a final standard for both new and existing sources by July 2015 as described in the June 2013 Presidential Memorandum.

DTE Energy is an active participant in working with the EPA and other stakeholders to shape the final performance standards for new and existing power plants. The carbon standards for new sources are not expected to have a material impact on the Company, since the Company has no plans to build new coal-fired generation. 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 credits from market sources, higher costs of purchased power, 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 as authorized by the MPSC.

Increased costs for energy produced from traditional coal-based sources could also increase the economic viability of energy produced from renewable, natural gas-fired generation 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. A June 2014 U.S. Supreme Court decision on the EPA’s authority to regulate GHG emissions under permitting programs of the Clean Air Act is expected to have little effect on DTE Energy since the Supreme Court's decision upholds the EPA’s authority to regulate GHGs at sources that are already subject to permitting due to emissions of conventional pollutants. In addition, the Supreme Court's ruling does not affect the EPA’s current proposed carbon performance standards at new or existing power plants. At the present time, it is not possible to quantify the financial impacts of these climate related regulatory initiatives on DTE Energy or its customers.

See Note 17 to the Consolidated Financial Statements in Item 8 of this Report, "Commitments and Contingencies" 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;

25

• growth of our utility asset base;

• employee engagement;

• cost structure optimization across all business segments;

• 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.

	2014			2013			2012
	(In millions)
Net Income (Loss) Attributable to DTE Energy by Segment:
Electric	$	528		$	484		$	483
Gas	140			143			115
Gas Storage and Pipelines	82			70			61
Power and Industrial Projects	90			66			42
Energy Trading	122			(58		)	12
Corporate and Other	(57		)	(44		)	(47		)
Income From Continuing Operations Attributable to DTE Energy Company	905			661			666
Discontinued Operations	—			—			(56		)
Net Income Attributable to DTE Energy Company	$	905		$	661		$	610

ELECTRIC

Our Electric segment consists principally of DTE Electric.

Electric results are discussed below:

	2014			2013			2012
	(In millions)
Operating Revenues	$	5,283		$	5,199		$	5,293
Fuel and purchased power	1,705			1,668			1,758
Gross Margin	3,578			3,531			3,535
Operation and maintenance	1,332			1,377			1,429
Depreciation and amortization	933			902			827
Taxes other than income	268			261			257
Asset (gains) losses and impairments, net	(1		)	(3		)	(2		)
Operating Income	1,046			994			1,024
Other (Income) and Deductions	222			258			261
Income Tax Expense	296			252			280
Net Income Attributable to DTE Energy Company	$	528		$	484		$	483
Operating Income as a Percent of Operating Revenues	20		%	19		%	19		%

Gross marginincreased by $47 million in 2014 and decreased$4 million in 2013. Revenues associated with certain mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statements of Operations.

26

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

	2014			2013
	(In millions)
Amortization of refundable revenue decoupling/deferred gain	$	63		$	—
Base sales, inclusive of weather effect	(48		)	(54		)
Securitization bond and tax surcharge	(10		)	39
Renewable energy program	20			19
Low income energy assistance surcharge	17			(12		)
Regulatory mechanisms and other	5			4
Increase (decrease) in gross margin	$	47		$	(4	)

	2014	2013	2012
	(In thousands of MWh)
Electric Sales
Residential	14,940	15,273	15,666
Commercial	16,792	16,661	16,832
Industrial	10,199	10,303	9,989
Other	517	942	958
	42,448	43,179	43,445
Interconnection sales (a)	3,630	3,883	2,125
Total Electric Sales	46,078	47,062	45,570
Electric Deliveries
Retail and Wholesale	42,448	43,179	43,445
Electric Customer Choice, including self generators (b)	5,033	5,200	5,197
Total Electric Sales and Deliveries	47,481	48,379	48,642

______________________________

(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 expensedecreased$45 million in 2014 and decreased$52 million in 2013. The decrease in 2014 is primarily due to decreased employee benefit expenses of $68 million, decreased distribution operations expenses of $36 million, and decreased power plant generation expenses of $7 million, partially offset by higher restoration and line clearance expenses of $19 million, increased low income energy assistance of $17 million, and increased energy optimization and renewable energy expenses of $13 million. In addition, 2014 included $17 million of expenses related to the transition of PLD customers to DTE Electric's distribution system effective July 1, 2014. In May 2014, the MPSC approved a TRM that provides for recovery of the deferred net incremental revenue requirement associated with the transition that is reflected in the Depreciation and amortization line in the Consolidated Statement of Operations. The decrease in 2013 is primarily due to decreased employee benefit expenses of $90 million, decreased power plant generation expenses of $14 million and decreased low income energy assistance of $12 million, partially offset by increased restoration and line clearance expenses of $19 million, increased corporate administrative expenses of $17 million, increased uncollectible expenses of $11 million, increased energy optimization and renewable energy expenses of $8 million and increased distribution operations expenses of $8 million.

Depreciation and amortizationexpenseincreased$31 million in 2014 and increased$75 million in 2013. The 2014 increase was due to $42 million of increased expense due to an increased depreciable base, increased amortization of regulatory assets of $3 million, primarily related to Securitization, partially offset by $14 million associated with the TRM. The 2013 increase was due to increased amortization of regulatory assets of $57 million, primarily related to Securitization, and increased depreciation of $18 million due to an increased depreciable base.

Other (income) and deductionsdecreased$36 million in 2014 and decreased$3 million in 2013. The decrease in 2014 was primarily due to decreased interest expenses of $18 million and the 2013 contribution to the DTE Energy Foundation of $18 million. The decrease in 2013 was primarily due to 2012 one time expenses of $11 million related to Michigan ballot proposals and increased investment earnings of $10 million, offset by a contribution to the DTE Energy Foundation of $18 million.

27

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 capital investments 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 retail access. We expect to continue our efforts to improve productivity and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.

In May 2014, DTE Electric filed an application with the NRC requesting a renewal of the license for its Fermi 2 nuclear power plant. DTE Electric has requested a 20-year extension of its original license due to expire in 2025.

In December 2014, DTE Electric filed a rate case with the MPSC requesting an increase in base rates of $370 million based on a projected twelve month period ending June 30, 2016.

GAS

Our Gas segment consists principally of DTE Gas.

Gas results are discussed below:

	2014			2013			2012
	(In millions)
Operating Revenues	$	1,636		$	1,474		$	1,315
Cost of gas	725			624			550
Gross Margin	911			850			765
Operation and maintenance	456			429			385
Depreciation and amortization	99			95			92
Taxes other than income	61			56			54
Operating Income	295			270			234
Other (Income) and Deductions	77			50			69
Income Tax Expense	78			77			50
Net Income Attributable to DTE Energy Company	$	140		$	143		$	115
Operating Income as a Percent of Operating Revenues	18		%	18		%	18		%

Gross marginincreased$61 million in 2014 and increased$85 million in 2013. Revenues associated with certain 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:

	2014			2013
	(In millions)
Weather	$	31		$	72
Infrastructure recovery mechanism	7			3
Home protection program	7			3
Uncollectible tracking mechanism	—			20
Self implementation and rate orders	—			15
Revenue decoupling mechanism	(3		)	(16		)
Midstream storage and transportation revenues	6			(8		)
Other	13			(4		)
Increase in gross margin	$	61		$	85

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	2014	2013	2012
Gas Markets (in Bcf)
Gas sales	138	128	104
End user transportation	167	157	157
	305	285	261
Intermediate transportation	305	300	264
	610	585	525

Operation and maintenanceexpenseincreased$27 million in 2014 and increased$44 million in 2013. The increase in 2014 is primarily due to increased gas operations expenses of $32 million, increased uncollectible expenses of $4 million, and increased corporate administrative expenses of $3 million, partially offset by decreased employee benefit expenses of $10 million and reduced energy optimization expenses of $2 million. The increase in 2013 is primarily due to increased gas operations expenses of $24 million, increased maintenance and repair costs of $14 million, increased transmission costs of $14 million, increased corporate administrative expenses of $8 million and increased uncollectible expenses of $5 million, partially offset by decreased employee benefit expenses of $19 million and decreased energy optimization expenses of $3 million.

Other (income) and deductionsincreased$27 million in 2014 and decreased$19 million in 2013. The increase in 2014 is primarily due to contributions to the DTE Energy Foundation and other charitable organizations in 2014. 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.

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 investments 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:

	2014			2013			2012
	(In millions)
Operating Revenues	$	203		$	132		$	96
Operation and Maintenance	46			25			19
Depreciation and Amortization	34			23			8
Taxes Other Than Income	4			3			3
Asset (Gains) and Losses and Reserves, Net	1			—			3
Operating Income	118			81			63
Other (Income) and Deductions	(19		)	(36		)	(40		)
Income Tax Expense	53			45			39
Net Income	84			72			64
Noncontrolling interest	2			2			3
Net Income Attributable to DTE Energy	$	82		$	70		$	61

Operating revenuesincreased$71 million in 2014 and increased$36 million in 2013. The increases were due primarily to increased volumes on the Bluestone pipeline and additional segments placed in service in the Susquehanna gathering system. Storage revenue also increased due to weather favorability in early 2014, partially offset by lower market rates.

Operation and maintenance expenseincreased$21 million in 2014 and increased$6 million in 2013. The increases were due primarily to increased activity on the Bluestone and Susquehanna projects and increased corporate overheads due to growth of this segment.

29

Depreciation and amortizationexpenseincreased$11 million in 2014 and increased$15 million in 2013. The increases were due primarily to the growth of the Bluestone and Susquehanna projects.

Other (income) and deductionsdecreased$17 million in 2014 and decreased$4 million in 2013. The decreases were due to decreased earnings from a pipeline investment and increased intercompany interest expense. The earnings from the pipeline investment were negatively impacted by a revenue deferral for depreciation collected in FERC-approved tariff rates in excess of depreciation expense.

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. We will continue to look for additional investment opportunities and other storage and pipeline projects at favorable prices. The capacity expansion of Bluestone lateral pipeline in Susquehanna County, Pennsylvania and Broome County, New York, is progressing as planned. In 2014, we added a new compressor facility and 3.5 miles of 24-inch pipeline loop, expanding the system to 47.5 miles of pipe in service. Expansion activities over the next twelve months include a second compressor facility and approximately 6 miles of additional pipeline loop to accommodate increased shipper demand. Through our long term agreement with Southwestern Energy Production Company, we believe Bluestone lateral and Susquehanna gathering system are strategically positioned for future growth of the Marcellus shale.

Progress continues on preliminary development activities on the proposed Nexus pipeline, a transportation path for natural gas from the Utica shale in Ohio to Michigan and Ontario. During 2014, several producers signed agreements as shippers, indicating their firm volume commitment subject to certain conditions customary in the pipeline industry. We are planning to have a partnership interest in the Nexus pipeline.

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 REF and sell electricity from renewable energy projects.

Power and Industrial Projects results are discussed below:

	2014			2013			2012
	(In millions)
Operating Revenues	$	2,289		$	1,950		$	1,823
Operation and maintenance	2,281			1,914			1,788
Depreciation and amortization	77			72			65
Taxes other than income	15			15			16
Asset (gains) losses and impairments, net	(12		)	(4		)	(5		)
Operating Loss	(72		)	(47		)	(41		)
Other (Income) and Deductions	(66		)	(73		)	(44		)
Income Taxes
Expense (Benefits)	(3		)	8			—
Production Tax Credits	(97		)	(53		)	(44		)
	(100		)	(45		)	(44		)
Net Income	94			71			47
Noncontrolling Interests	4			5			5
Net Income Attributable to DTE Energy Company	$	90		$	66		$	42

Operating revenuesincreased$339 million in 2014 and increased$127 million in 2013. The 2014 increase is primarily due to a $354 million increase associated with higher volumes from REF projects and a $32 million increase associated with the start-up of a renewable power project, partially offset by a $46 million decrease due primarily to lower coal prices associated with the steel business. The 2013 increase is primarily due to a $161 million increase associated with higher volumes from REF projects 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.

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Operation and maintenanceexpenseincreased$367 million in 2014 and increased$126 million in 2013. The 2014 increase is primarily due to a $365 million increase associated with higher volumes from REF projects, a $23 million increase associated with the start-up of a renewable power project and a $20 million increase due to higher volumes, maintenance and general administrative expenses in the steel business, partially offset by a $46 million decrease due primarily to lower coal prices associated with the steel business. The 2013 increase is primarily due to a $173 million increase associated with higher volumes from REF projects 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.

Depreciation and amortization expense increased by $5 million in 2014 and increased by $7 million in 2013. The 2014 increase is primarily due to $4 million associated with the start-up of a renewable power project. 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.

Asset (gains) and losses, reserves and impairments, netincreased by $8 million in 2014 and decreased by $1 million in 2013. The 2014 increase was due primarily to a gain associated with a sale of an on-site project in 2014 and an asset impairment recorded in the prior year.

Other (income) and deductionsdecreased by $7 million in 2014 and increased$29 million in 2013 due primarily to variations in volumes of refined coal produced at REF sites with investors, and in 2014, lower equity earnings at various projects.

Production tax creditsincreased by $44 million in 2014 and increased$9 million in 2013 primarily due to higher production volumes of refined coal that resulted in higher tax credits at REF projects.

Outlook— The Company has constructed and placed in service nine REF facilities including five 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. We intend to relocate an underutilized facility, located at a DTE Electric site, to an alternative coal-fired power plant which may provide increased production and emission reduction opportunities in future years.

We expect sustained production levels of metallurgical coke and pulverized coal supplied to steel industry customers for 2015. Substantially all of the metallurgical coke margin is maintained under long-term contracts. We have five renewable power generation facilities in operation. Our on-site energy services will continue to be delivered in accordance with the terms of long-term contracts. 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 and natural gas 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.

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Energy Trading results are discussed below:

	2014		2013			2012
	(In millions)
Operating Revenues	$	3,762	$	1,771		$	1,109
Fuel, purchased power and gas	3,478		1,782			1,011
Gross Margin	284		(11		)	98
Operation and maintenance	70		72			66
Depreciation and amortization	1		1			2
Taxes other than income	4		4			3
Operating Income (Loss)	209		(88		)	27
Other (Income) and Deductions	10		8			8
Income Tax Expense (Benefit)	77		(38		)	7
Net Income (Loss) Attributable to DTE Energy Company	$	122	$	(58	)	$	12

Operating revenues and Fuel, purchased power and gas were impacted by an increase in gas volumes and prices, primarily in our gas structured strategy for the year ended December 31, 2014.

Gross marginincreased$295 million in 2014 and decreased$109 million in 2013. The overall increase in gross margin in 2014 was primarily due to timing from MTM adjustments on certain transactions in our gas structured strategy.

The increase in gross margin in 2014 represents a $92 million increase in realized margins and a $203 million increase in unrealized margins. The $92 million increase in realized margins is due to $149 million of favorable results, primarily in our gas structured and gas transportation strategies, offset by $57 million of unfavorable results, primarily in our power full requirements, gas full requirements and gas trading strategies. The $203 million increase in unrealized margins is due to $211 million of favorable results, primarily in our gas structured and gas full requirements strategies, offset by $8 million of unfavorable results, primarily in our power full requirements strategy.

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.

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 2014 we saw significant decreases in gas prices, and in the fourth quarter of 2013 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. Included in the $149 million of favorable realized results for the year ended December 31, 2014 in our gas strategies is $65 million of timing related losses recognized in 2013 that reversed as the underlying contracts were settled. Included in the $211 million of favorable unrealized results for the year ended December 31, 2014 in our gas strategies is $102 million of timing related gains which will reverse in future periods, and the absence of $89 million of timing related losses in 2013. We anticipate that approximately $50 million of unrealized gains will reverse during 2015 as the underlying contracts settle.

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.

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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, 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 2014net loss of $57 million represented an increase of $13 million from the 2013net loss of $44 million due primarily to increased impairments of investments and increased deferred tax expense related to New York state income tax reform enacted March 31, 2014. The 2013net loss of $44 million represented an improvement of $3 million from the 2012net loss of $47 million due primarily to decreased impairments of investments.

See Note 9 to the Consolidated Financial Statements in Item 8 of this Report, "Income Taxes".

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 4 to the Consolidated Financial Statements in Item 8 of this Report, "Discontinued Operations".

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. We expect that cash from operations in 2015 will be approximately $1.7 billion, or approximately $100 million lower than 2014, due primarily to decreased surcharge collections. We anticipate base level utility capital investments, environmental, renewable and energy optimization expenditures, expenditures for non-utility businesses and contributions to equity method investments in 2015 of approximately $2.6 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.

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	2014			2013			2012
	(In millions)
Cash and Cash Equivalents
Cash Flow From (Used For)
Operating activities:
Net Income	$	911		$	668		$	618
Depreciation, depletion and amortization	1,145			1,094			1,018
Nuclear fuel amortization	48			38			29
Allowance for equity funds used during construction	(21		)	(15		)	(13		)
Deferred income taxes	356			164			47
Loss on sale of non-utility business	—			—			83
Asset (gains) losses and impairments, net	(4		)	(8		)	1
Working capital and other	(596		)	213			426
Net cash from operating activities	1,839			2,154			2,209
Investing activities:
Plant and equipment expenditures — utility	(1,784		)	(1,534		)	(1,451		)
Plant and equipment expenditures — non-utility	(265		)	(342		)	(369		)
Proceeds from sale of non-utility business	—			—			255
Proceeds from sale of assets	45			36			38
Acquisition, net of cash acquired	—			—			(198		)
Other	(56		)	(66		)	(44		)
Net cash used for investing activities	(2,060		)	(1,906		)	(1,769		)
Financing activities:
Issuance of long-term debt, net of issuance costs	1,736			1,234			759
Redemption of long-term debt	(1,237		)	(961		)	(639		)
Short-term borrowings, net	267			(109		)	(179		)
Issuance of common stock	—			39			39
Repurchase of common stock	(52		)	—			—
Dividends on common stock	(470		)	(445		)	(407		)
Other	(27		)	(19		)	(16		)
Net cash from (used for) financing activities	217			(261		)	(443		)
Net Increase (Decrease) in Cash and Cash Equivalents	$	(4	)	$	(13	)	$	(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, changes in working capital, and operating costs.

Cash from operations decreased$315 million in 2014. The reduction in operating cash flow reflects an increase in cash expenditures for 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 decreased$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).

The change in working capital items in 2014 primarily related to fuel inventories, derivative assets and liabilities, and regulatory assets and liabilities, partially offset by the change in accounts receivable, net, accounts payable, and pension and other postretirement liabilities. 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.

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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 increased$154 million in 2014 due primarily to increased capital expenditures by our utility businesses, partially offset by decreased capital expenditures by our non-utility business and increased proceeds from sale of assets.

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

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 53%, to ensure it is consistent with our objective to have a strong investment grade debt rating.

Net cash from financing activities increased$478 million in 2014. The increase was primarily attributable to increases in short-term borrowings and issuances of long-term debt, partially offset by increased redemptions of long-term debt, repurchases of common stock and increased dividends on common stock.

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

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 $300 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 $1.5 billion of available liquidity at December 31, 2014, consisting of cash and amounts available under unsecured revolving credit agreements.

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We expect to issue equity of approximately $200 million in 2015 through our dividend reinvestment plan and pension and other employee benefit plans.

At the discretion of management, and depending upon financial market conditions, we anticipate making 2015 contributions to the pension plans of up to $180 million and up to $200 million to the other postretirement benefit plans. The planned contributions will be made in cash or a combination of cash and DTE Energy common stock.

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 require 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 required 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, 2014, DTE Energy's contractual obligation to post collateral 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 $349 million.

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 8, 9, 13, 15 and 18 to the Consolidated Financial Statements in Item 8 of this Report, "Regulatory Matters", "Income Taxes", "Long-Term Debt", "Short-Term Credit Arrangements and Borrowings" and "Retirement Benefits and Trusteed Assets".

Contractual Obligations

The following table details our contractual obligations for debt redemptions, leases, purchase obligations and other long-term obligations as of December 31, 2014:

	Total		2015		2016-2017		2018-2019		2020 and Beyond
	(In millions)
Long-term debt:
Mortgage bonds, notes and other (a)	$	8,035	$	161	$	474	$	834	$	6,566
Securitization bonds	105		105		—		—		—
Junior subordinated debentures	480		—		—		—		480
Capital lease obligations	11		8		3		—		—
Interest	6,660		455		711		712		4,782
Operating leases	219		42		62		37		78
Electric, gas, fuel, transportation and storage purchase obligations (b)	8,896		2,326		1,971		895		3,704
Other long-term obligations (c)(d)(e)	119		57		30		13		19
Total obligations	$	24,525	$	3,154	$	3,251	$	2,491	$	15,629

_______________________________________

(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 $9 million.

(d) Excludes other long-term liabilities of $192 million not directly derived from contracts or other agreements.

(e) At December 31, 2014, 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 18 to the Consolidated Financial Statements in Item 8 of this Report, "Retirement Benefits and Trusteed Assets".

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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. DTE Energy’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.

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 8 to the Consolidated Financial Statements in Item 8 of this Report, "Regulatory Matters".

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.

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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, 2014 and 2013. 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 11 and 12 to the Consolidated Financial Statements in Item 8 of this Report, "Fair Value" and "Financial and Other Derivative Instruments".

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, 2014 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.

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As of October 1, 2014 Valuation Date:

Reporting Unit	Goodwill		Fair Value Reduction % (a)		Discount Rate		Terminal Multiple (b)	Valuation Methodology (c)
	(In millions)
Electric	$	1,208	38	%	7	%	9.5x	DCF, assuming stock sale
Gas	743		26	%	6	%	10.5x	DCF, assuming stock sale
Power and Industrial Projects (d)	26		59	%	8	%	10.0x	DCF, assuming asset sale (e)
Gas Storage and Pipelines	24		78	%	7	%	12.5x	DCF, assuming asset sale
Energy Trading	17		45	%	10	%	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 2015-2019 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.

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.

39

We had pension costs of $179 million in 2014, $228 million in 2013 and $220 million in 2012. Other postretirement benefit costs (credit) were $(123) million in 2014, $(42) million in 2013 and $151 million in 2012. Pension and other postretirement benefit costs (credit) for 2014 are calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on our plan assets of 7.75% for our pension plans and 8% for our other postretirement benefit plans. 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 2015 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 maintaining our long-term rate of return assumptions for our pension plans and our other postretirement plans at 7.75% and 8%, respectively for 2015. We believe these rates are reasonable assumptions for the long-term rate of return on our plan assets for 2015 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 2014 contributed to our investment performance resulting in unrecognized net gains. As of December 31, 2014, we had $78 million of cumulative gains that remain to be recognized in the calculation of the MRV of pension assets related to investment performance in 2014, 2013 and 2012. 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.

The discount rate that we utilize for determining future pension and other postretirement benefit obligations is based on a yield curve approach and a review of bonds that receive one of the two highest ratings given by a recognized rating agency. The yield curve approach matches projected pension plan and other postretirement benefit payment streams with bond portfolios reflecting actual liability duration unique to our plans. The discount rate determined on this basis decreased to 4.12% for the pension plans and 4.1% for the other postretirement plans at December 31, 2014 from 4.95% at December 31, 2013.

The mortality assumptions that we used to determine the pension and other postretirement benefit obligations as of December 31, 2014, were updated to incorporate the RP-2014 mortality table issued by the Society of Actuaries in 2014 with the MP-2014 generational projection scale, with variations by type of plan and participant's union status and employment status.

We estimate that our 2015 total pension costs will approximate $218 million compared to $179 million in 2014 primarily due to lower discount rates and changes to the mortality tables, partially offset by greater than expected 2014 returns. Our 2015 other postretirement benefit credit will approximate $(98) million compared to $(123) million in 2014 due to lower than expected returns, lower discount rate and changes to the mortality tables, partially offset by the continued impact of plan design changes and favorable retiree medical utilization trends. Our health care trend rate for pre-65 participants assumes 7.5% for 2015, and 7% for 2016 and 2017, 6.5% for 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 2015 and 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, and 4.5% in 2024 and beyond. Future actual pension and other postretirement benefit costs (credit) 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 2014 pension costs by approximately $33 million. Lowering the discount rate and the salary increase assumptions by one percentage point would have increased our 2014 pension costs by approximately $18 million. Lowering the expected long-term rate of return on our plan assets by one percentage point would have decreased our 2014 other postretirement credit by approximately $15 million. Lowering the discount rate assumption by one percentage point would have decreased our 2014 other postretirement credit by approximately $24 million. Lowering the health care cost trend assumptions by one percentage point would have increased our other postretirement credit for 2014 by approximately $7 million.

40

The value of our qualified pension and other postretirement benefit plan assets was $5.5 billion at December 31, 2014 and $5.2 billion at December 31, 2013. At December 31, 2014, our qualified pension plans were underfunded by $1.17 billion and our other postretirement benefit plans were underfunded by $517 million. The 2014 funding levels generally declined due to decreased discount rates and a change in the mortality tables.

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 $188 million in 2014 and $277 million in 2013. 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 $180 million in 2015 and up to $875 million over the next five years. We made other postretirement benefit plan contributions of $24 million in 2014 and $264 million in 2013. 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 $200 million contribution to our other postretirement plans in 2015 and, subject to MPSC funding requirements, up to $250 million over the next five years. The planned contributions will be made in cash or a combination of cash and DTE Energy common stock.

See Note 18 to the Consolidated Financial Statements in Item 8 of this Report, "Retirement Benefits and Trusteed Assets".

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 $10 million for property damage, $7 million for general liability, $9 million for workers’ compensation and $7 million for auto liability. 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, 2014, this IBNR liability was approximately $32 million.

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, 2014 and 2013 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 9 to the Consolidated Financial Statements in Item 8 of this Report, "Income Taxes".

NEW ACCOUNTING PRONOUNCEMENTS

See Note 3 to the Consolidated Financial Statements in Item 8 of this Report, "New Accounting Pronouncements".

41

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 contracts, renewable energy credits and storage assets. See Notes 11 and 12 to the Consolidated Financial Statements in Item 8 of this Report, "Fair Value" and "Financial and Other Derivative Instruments".

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 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 11 to the Consolidated Financial Statements in Item 8 of this Report, "Fair Value".

The following tables provide details on changes in our MTM net asset (or liability) position during 2014:

	Total
	(In millions)
MTM at December 31, 2013	$	(112	)
Reclassify to realized upon settlement	94
Changes in fair value recorded to income	79
Amounts recorded to unrealized income	173
Changes in fair value recorded in regulatory liabilities	8
Change in collateral held by (for) others	28
Option premiums received and other	(10		)
MTM at December 31, 2014	$	87

The table below shows the maturity of our MTM positions. The positions from 2018 and beyond principally represent longer tenor gas structured transactions:

Source of Fair Value	2015			2016			2017			2018 and Beyond		Total Fair Value
	(In millions)
Level 1	$	(3	)	$	(7	)	$	(3	)	$	—	$	(13	)
Level 2	48			4			5			—		57
Level 3	(3		)	6			—			21		24
MTM before collateral adjustments	$	42		$	3		$	2		$	21	68
Collateral adjustments												19
MTM at December 31, 2014												$	87

42

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Price Risk

The Electric and Gas businesses have commodity price risk, primarily related to the purchases of coal, natural gas, uranium and electricity. 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, storage sales and transportation services 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.

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.

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.

43

The following table displays the credit quality of our trading counterparties as of December 31, 2014:

	Credit Exposure Before Cash Collateral		Cash Collateral			Net Credit Exposure
	(In millions)
Investment Grade (a)
A− and Greater	$	203	$	—		$	203
BBB+ and BBB	229		—			229
BBB−	61		—			61
Total Investment Grade	493		—			493
Non-investment grade (b)	2		—			2
Internally Rated — investment grade (c)	240		(1		)	239
Internally Rated — non-investment grade (d)	16		(1		)	15
Total	$	751	$	(2	)	$	749

_______________________________________

(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, a division of McGraw-Hill Companies, Inc. (Standard & Poor’s). The five largest counterparty exposures, combined, for this category represented approximately 14% 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 14% 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, 2014, we had a floating rate debt-to-total debt ratio of approximately 4.6% (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 April 2019.

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, 2014 and 2013 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, 2014 and 2013:

	Assuming a 10% Increase in Rates						Assuming a 10% Decrease in Rates
	As of December 31,						As of December 31,
Activity	2014			2013			2014		2013			Change in the Fair Value of
	(In millions)
Gas contracts	$	(4	)	$	(21	)	$	5	$	21		Commodity contracts
Power contracts	$	—		$	14		$	—	$	(13	)	Commodity contracts
Interest rate risk	$	(336	)	$	(291	)	$	356	$	309		Long-term debt
Foreign currency exchange risk	$	—		$	—		$	—	$	—		Forward contracts
Discount rates	$	—		$	—		$	—	$	—		Commodity contracts

For further discussion of market risk, see Management's Discussion and Analysis in Item 7 of this Report and Note 12 to the Consolidated Financial Statements in Item 8 of this Report, "Financial and Other Derivative Instruments".

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 Financial Position	51
Consolidated Statements of Cash Flows	53
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. New Accounting Pronouncements	61
Note 4. Discontinued Operations	62
Note 5. Property, Plant and Equipment	63
Note 6. Jointly Owned Utility Plant	64
Note 7. Asset Retirement Obligations	64
Note 8. Regulatory Matters	65
Note 9. Income Taxes	70
Note 10. Earnings Per Share	72
Note 11. Fair Value	73
Note 12. Financial and Other Derivative Instruments	78
Note 13. Long-Term Debt	83
Note 14. Preferred and Preference Securities	85
Note 15. Short-Term Credit Arrangements and Borrowings	85
Note 16. Capital and Operating Leases	86
Note 17. Commitments and Contingencies	87
Note 18. Retirement Benefits and Trusteed Assets	92
Note 19. Stock-Based Compensation	103
Note 20. Segment and Related Information	105
Note 21. Supplementary Quarterly Financial Information (Unaudited)	108
Note 22. Subsequent Event	108
Financial Statement Schedule
Schedule II — Valuation and Qualifying Accounts	118

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, 2014, 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, 2014. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (2013 COSO) in Internal Control - Integrated Framework. Based on this assessment, management concluded that, as of December 31, 2014, 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, 2014 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, 2014 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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014in 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, 2014, based on criteria established in Internal Control - Integrated Framework (2013 COSO) issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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 13, 2015

48

DTE Energy Company

Consolidated Statements of Operations

	Year Ended December 31,
	2014			2013			2012
	(In millions, except per share amounts)
Operating Revenues	$	12,301		$	9,661		$	8,791
Operating Expenses
Fuel, purchased power and gas	5,879			4,055			3,296
Operation and maintenance	3,347			2,978			2,892
Depreciation, depletion and amortization	1,145			1,094			995
Taxes other than income	352			340			332
Asset (gains) losses and impairments, net	(12		)	(9		)	(3		)
	10,711			8,458			7,512
Operating Income	1,590			1,203			1,279
Other (Income) and Deductions
Interest expense	429			436			440
Interest income	(10		)	(9		)	(10		)
Other income	(196		)	(201		)	(173		)
Other expenses	92			55			62
	315			281			319
Income Before Income Taxes	1,275			922			960
Income Tax Expense	364			254			286
Income from Continuing Operations	911			668			674
Loss from Discontinued Operations, net of tax	—			—			(56		)
Net Income	911			668			618
Less: Net Income Attributable to Noncontrolling Interests	6			7			8
Net Income Attributable to DTE Energy Company	$	905		$	661		$	610
Basic Earnings per Common Share
Income from continuing operations	$	5.11		$	3.76		$	3.89
Loss from discontinued operations, net of tax	—			—			(0.33		)
Total	$	5.11		$	3.76		$	3.56
Diluted Earnings per Common Share
Income from continuing operations	$	5.10		$	3.76		$	3.88
Loss from discontinued operations, net of tax	—			—			(0.33		)
Total	$	5.10		$	3.76		$	3.55
Weighted Average Common Shares Outstanding
Basic	177			175			171
Diluted	177			175			172
Dividends Declared per Common Share	$	2.69		$	2.59		$	2.42

See Notes to Consolidated Financial Statements

49

DTE Energy Company

Consolidated Statements of Comprehensive Income

	Year Ended December 31,
	2014			2013			2012
	(In millions)
Net Income	$	911		$	668		$	618
Other comprehensive income (loss), net of tax:
Benefit obligations, net of taxes of $(9), $13 and $(1), respectively	(18		)	22			(2		)
Net unrealized gains on investments during the period, net of taxes of $1, $1 and $1, respectively	1			2			1
Foreign currency translation, net of taxes of $(2), $(1) and $—, respectively	(2		)	(2		)	1
Other comprehensive income (loss)	(19		)	22			—
Comprehensive income	892			690			618
Less comprehensive income attributable to noncontrolling interests	6			7			8
Comprehensive income attributable to DTE Energy Company	$	886		$	683		$	610

See Notes to Consolidated Financial Statements

50

DTE Energy Company

Consolidated Statements of Financial Position

	December 31,
	2014			2013
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	48		$	52
Restricted cash, principally Securitization	120			123
Accounts receivable (less allowance for doubtful accounts of $54 and $55, respectively)
Customer	1,504			1,542
Other	94			127
Inventories
Fuel and gas	512			363
Materials and supplies	292			265
Derivative assets	128			99
Regulatory assets	76			26
Other	313			209
	3,087			2,806
Investments
Nuclear decommissioning trust funds	1,241			1,191
Other	628			603
	1,869			1,794
Property
Property, plant and equipment	26,538			25,123
Less accumulated depreciation, depletion and amortization	(9,718		)	(9,323		)
	16,820			15,800
Other Assets
Goodwill	2,018			2,018
Regulatory assets	3,651			2,837
Securitized regulatory assets	34			231
Intangible assets	102			122
Notes receivable	90			102
Derivative assets	44			27
Other	259			198
	6,198			5,535
Total Assets	$	27,974		$	25,935

See Notes to Consolidated Financial Statements

51

DTE Energy Company

Consolidated Statements of Financial Position — (Continued)

	December 31,
	2014			2013
	(In millions, except shares)
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	973		$	962
Accrued interest	86			90
Dividends payable	122			116
Short-term borrowings	398			131
Current portion long-term debt, including capital leases	274			898
Derivative liabilities	77			195
Regulatory liabilities	153			302
Other	494			495
	2,577			3,189
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	7,860			6,618
Securitization bonds	—			105
Junior subordinated debentures	480			480
Capital lease obligations	3			11
	8,343			7,214
Other Liabilities
Deferred income taxes	3,776			3,321
Regulatory liabilities	667			862
Asset retirement obligations	1,962			1,827
Unamortized investment tax credit	41			47
Derivative liabilities	8			43
Accrued pension liability	1,280			653
Accrued postretirement liability	515			350
Nuclear decommissioning	182			178
Other	281			297
	8,712			7,578
Commitments and Contingencies (Notes 8 and 17)
Equity
Common stock, without par value, 400,000,000 shares authorized, 176,991,231 and 177,087,230 shares issued and outstanding, respectively	3,904			3,907
Retained earnings	4,578			4,150
Accumulated other comprehensive loss	(155		)	(136		)
Total DTE Energy Company Equity	8,327			7,921
Noncontrolling interests	15			33
Total Equity	8,342			7,954
Total Liabilities and Equity	$	27,974		$	25,935

See Notes to Consolidated Financial Statements

52

DTE Energy Company

Consolidated Statements of Cash Flows

	Year Ended December 31,
	2014			2013			2012
	(In millions)
Operating Activities
Net Income	$	911		$	668		$	618
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	1,145			1,094			1,018
Nuclear fuel amortization	48			38			29
Allowance for equity funds used during construction	(21		)	(15		)	(13		)
Deferred income taxes	356			164			47
Loss on sale of non-utility business	—			—			83
Asset (gains) losses and impairments, net	(4		)	(8		)	1
Changes in assets and liabilities:
Accounts receivable, net	48			(154		)	52
Inventories	(177		)	123			35
Accounts payable	128			14			40
Accrued pension obligation	627			(644		)	280
Accrued postretirement obligation	165			(526		)	(323		)
Derivative assets and liabilities	(199		)	107			53
Regulatory assets and liabilities	(1,177		)	1,269			278
Other assets	(30		)	(24		)	55
Other liabilities	19			48			(44		)
Net cash from operating activities	1,839			2,154			2,209
Investing Activities
Plant and equipment expenditures — utility	(1,784		)	(1,534		)	(1,451		)
Plant and equipment expenditures — non-utility	(265		)	(342		)	(369		)
Proceeds from sale of non-utility business	—			—			255
Proceeds from sale of assets	45			36			38
Acquisition, net of cash acquired	—			—			(198		)
Proceeds from sale of nuclear decommissioning trust fund assets	1,146			1,118			759
Investment in nuclear decommissioning trust funds	(1,156		)	(1,134		)	(764		)
Other	(46		)	(50		)	(39		)
Net cash used for investing activities	(2,060		)	(1,906		)	(1,769		)
Financing Activities
Issuance of long-term debt, net of issuance costs	1,736			1,234			759
Redemption of long-term debt	(1,237		)	(961		)	(639		)
Short-term borrowings, net	267			(109		)	(179		)
Issuance of common stock	—			39			39
Repurchase of common stock	(52		)	—			—
Dividends on common stock	(470		)	(445		)	(407		)
Other	(27		)	(19		)	(16		)
Net cash from (used for) financing activities	217			(261		)	(443		)
Net Decrease in Cash and Cash Equivalents	(4		)	(13		)	(3		)
Cash and Cash Equivalents at Beginning of Period	52			65			68
Cash and Cash Equivalents at End of Period	$	48		$	52		$	65
Supplemental disclosure of cash information
Cash paid (received) for:
Interest (net of interest capitalized)	$	415		$	418		$	438
Income taxes	$	(35	)	$	121		$	173
Supplemental disclosure of non-cash investing and financing activities
Plant and equipment expenditures in accounts payable	$	212		$	329		$	235

See Notes to Consolidated Financial Statements

53

DTE Energy Company

Consolidated Statements of Changes in Equity

									Accumulated
									Other			Non-
	Common Stock					Retained			Comprehensive			Controlling
	Shares		Amount			Earnings			Income (Loss)			Interest			Total
	(Dollars in millions, shares in thousands)
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
Benefit obligations, net of tax	—		—			—			(2		)	—			(2		)
Net change in unrealized losses on investments, net of tax	—		—			—			1			—			1
Foreign currency translation, 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
Benefit obligations, net of tax	—		—			—			22			—			22
Net change in unrealized losses on investments, net of tax	—		—			—			2			—			2
Foreign currency translation, 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
Net Income	—		—			905			—			6			911
Dividends declared on common stock	—		—			(476		)	—			—			(476		)
Repurchase of common stock	(713	)	(52		)	—			—			—			(52		)
Benefit obligations, net of tax	—		—			—			(18		)	—			(18		)
Net change in unrealized losses on investments, net of tax	—		—			—			1			—			1
Foreign currency translation, net of tax									(2		)				(2		)
Stock-based compensation, distributions to noncontrolling interests and other	617		49			(1		)	—			(24		)	24
Balance, December 31, 2014	176,991		$	3,904		$	4,578		$	(155	)	$	15		$	8,342

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

• DTE Gas is 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 the CFTC.

References in this Report to “we”, “us”, “our”, “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.

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 plants. 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 consolidated when the Company is the primary beneficiary. In addition, we have interests in certain VIEs through which we share control of all significant activities for those entities with our partners, and therefore are accounted for under the equity method.

55

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The Company has variable interests in VIEs through certain of its long-term purchase and sale contracts. As of December 31, 2014, the carrying amount of assets and liabilities in the Consolidated Statements of Financial Position that relate to its variable interests under long-term purchase and sale contracts are predominately related to working capital accounts and generally represent the amounts owed by or to the Company for the deliveries associated with the current billing cycle under the contracts. The Company has not provided any significant 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 and sale 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, 2014 and 2013. 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, 2014						December 31, 2013
	Securitization		Other		Total		Securitization		Other		Total
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	7	$	7	$	—	$	12	$	12
Restricted cash	96		8		104		100		8		108
Accounts receivable	26		15		41		34		16		50
Inventories	—		67		67		—		118		118
Property, plant and equipment, net	—		81		81		—		99		99
Securitized regulatory assets	34		—		34		231		—		231
Other current and long-term assets	1		6		7		4		9		13
	$	157	$	184	$	341	$	369	$	262	$	631
LIABILITIES
Accounts payable and accrued current liabilities	$	3	$	8	$	11	$	7	$	23	$	30
Current portion long-term debt, including capital leases	105		10		115		196		9		205
Current regulatory liabilities	32		—		32		43		—		43
Mortgage bonds, notes and other	—		15		15		—		21		21
Securitization bonds	—		—		—		105		—		105
Capital lease obligations	—		3		3		—		7		7
Other current and long-term liabilities	9		6		15		8		6		14
	$	149	$	42	$	191	$	359	$	66	$	425

Amounts for non-consolidated VIEs as of December 31, 2014 and 2013 are as follows:

	December 31, 2014		December 31, 2013
	(In millions)
Other investments	$	134	$	141
Notes receivable	$	15	$	8

56

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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.

For further discussion of recovery mechanisms authorized by the MPSC see Note 8 to the Consolidated Financial Statements, "Regulatory Matters".

Non-utility businesses recognize revenues as services are provided and products are delivered. For discussion of derivative contracts see Note 12 to the Consolidated Financial Statements, "Financial and Other Derivative Instruments".

Other Income

Other income is recognized for non-operating income such as equity earnings, allowance for equity funds used 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 $78 million, $81 million and $63 million of Other income for the years ended December 31, 2014, 2013 and 2012, 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.

Changes in Accumulated Other Comprehensive 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. The amounts recorded to accumulated other comprehensive loss include unrealized gains and losses from derivatives accounted for as cash flow hedges, unrealized gains and losses on available-for-sale securities and 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 foreign currency translation adjustments.

57

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The following table summarizes the changes in Accumulated other comprehensive loss by component for the years ended December 31, 2014 and 2013:

	Changes in Accumulated Other Comprehensive Loss by Component (a)
	Net Unrealized Gain/(Loss) on Derivatives			Net Unrealized Gain/(Loss) on Investments			Benefit Obligations (b)			Foreign Currency Translation			Total
	(In millions)
Balance, January 1, 2013	$	(4	)	$	(8	)	$	(148	)	$	2		$	(158	)
Other comprehensive income (loss) before reclassifications	—			2			13			(2		)	13
Amounts reclassified from accumulated other comprehensive income	—			—			9			—			9
Net current-period other comprehensive income (loss)	—			2			22			(2		)	22
Balance, December 31, 2013	$	(4	)	$	(6	)	$	(126	)	$	—		$	(136	)
Other comprehensive income (loss) before reclassifications	—			1			(25		)	(2		)	(26		)
Amounts reclassified from accumulated other comprehensive income	—			—			7			—			7
Net current-period other comprehensive income (loss)	—			1			(18		)	(2		)	(19		)
Balance, December 31, 2014	$	(4	)	$	(5	)	$	(144	)	$	(2	)	$	(155	)

______________________________________

(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 18 to the Consolidated Financial Statements "Retirement Benefits and Trusteed Assets").

Cash, 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 $773 million and $815 million are included in customer accounts receivable at December 31, 2014 and 2013, 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.

58

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 $43 million and $4 million as of December 31, 2014 and 2013, respectively, at DTE Gas is determined using the last-in, first-out (LIFO) method. At December 31, 2014, the replacement cost of gas remaining in storage exceeded the LIFO cost by $110 million. At December 31, 2013, the replacement cost of gas remaining in storage exceeded the LIFO cost by $170 million.

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

Property is stated at cost and includes construction-related labor, materials, overheads and AFUDC for utility property. 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 $16 million and $26 million of expenses related to Fermi 2 refueling outages were accrued at December 31, 2014 and 2013, respectively. Amounts are accrued on a pro-rata basis, generally over an 18-month period, that coincides with scheduled refueling outages at Fermi 2. This accrual of outage costs matches the regulatory recovery of these costs in rates set by the MPSC. See Note 8 to the Consolidated Financial Statements, "Regulatory Matters".

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, 2014		December 31, 2013
	(In millions)
Emission allowances	$	1	$	2
Renewable energy credits	45		51
Contract intangible assets	122		126
	168		179
Less accumulated amortization	57		45
Intangible assets, net	111		134
Less current intangible assets	9		12
	$	102	$	122

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 27 years. Intangible assets amortization expense was $12 million in 2014, $14 million in 2013 and $6 million in 2012.

The following table summarizes the estimated amortization expense expected to be recognized during each year through 2019:

Estimated amortization expense	(In millions)
2015	$	12
2016	$	11
2017	$	8
2018	$	8
2019	$	6

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 11 of the Consolidated Financial Statements, "Fair Value".

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 $25 million, $18 million and $21 million for the years ended December 31, 2014, 2013 and 2012, 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.

Other Accounting Policies

See the following notes for other accounting policies impacting the Company’s Consolidated Financial Statements:

Note	Title
7	Asset Retirement Obligations
8	Regulatory Matters
9	Income Taxes
11	Fair Value
12	Financial and Other Derivative Instruments
19	Stock-Based Compensation

NOTE 3 — NEW ACCOUNTING PRONOUNCEMENTS

In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers. The objectives of this ASU are to improve upon revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and timing of recognition. The core principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. This ASU also requires expanded qualitative and quantitative disclosures regarding the nature, amount, timing, and uncertainty of revenues and cash flows arising from contracts with customers. The revenue standard is effective for the first interim period within annual reporting periods beginning after December 15, 2016 and is to be applied retrospectively. Early adoption is not permitted. The Company is currently assessing the impact of this ASU on its Consolidated Financial Statements.

61

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 4 — 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
	(In millions)
Operating Revenues	$	55
Operation and maintenance	24
Depreciation, depletion and amortization	23
Taxes other than income	4
Asset (gains) losses, net	83
	134
Operating Loss	(79		)
Other (Income) and Deductions	6
Loss Before Income Taxes	(85		)
Income Tax Benefit	(29		)
Net Loss Attributable to DTE Energy Company	$	(56	)

62

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 5 — PROPERTY, PLANT AND EQUIPMENT

Summary of property by classification as of December 31:

	2014			2013
	(In millions)
Property, Plant and Equipment
DTE Electric
Generation	$	11,641		$	11,127
Distribution	8,164			7,603
Total DTE Electric	19,805			18,730
DTE Gas
Distribution	2,946			2,834
Storage	448			431
Other	863			836
Total DTE Gas	4,257			4,101
Non-utility and other	2,476			2,292
Total	26,538			25,123
Less Accumulated Depreciation, Depletion and Amortization
DTE Electric
Generation	(4,149		)	(4,004		)
Distribution	(3,067		)	(2,947		)
Total DTE Electric	(7,216		)	(6,951		)
DTE Gas
Distribution	(1,130		)	(1,129		)
Storage	(142		)	(138		)
Other	(363		)	(338		)
Total DTE Gas	(1,635		)	(1,605		)
Non-utility and other	(867		)	(767		)
Total	(9,718		)	(9,323		)
Net Property, Plant and Equipment	$	16,820		$	15,800

AFUDC and interest capitalized was approximately $37 million and $33 million for the years ended December 31, 2014 and 2013, respectively.

The composite depreciation rate for DTE Electric was approximately 3.4% in 2014 and 2013 and 3.3% in 2012. The composite depreciation rate for DTE Gas was 2.4% in 2014, 2013 and 2012. The average estimated useful life for each major class of utility property, plant and equipment as of December 31, 2014 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 range 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.

63

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Capitalized software costs amortization expense was $77 million in 2014, $71 million in 2013 and $68 million in 2012. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2014 were $668 million and $335 million, respectively. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2013 were $611 million and $323 million, respectively.

Gross property under capital leases was $35 million at December 31, 2014 and 2013. Accumulated amortization of property under capital leases was $27 million and $21 million at December 31, 2014 and 2013, respectively.

NOTE 6 — JOINTLY OWNED UTILITY PLANT

DTE Electric has joint ownership interest in two power plants, Belle River and Ludington Hydroelectric Pumped Storage. DTE Electric’s share of direct expenses of the jointly owned plants are included in Fuel, 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, 2014 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)	$	1,742		$	412
Accumulated depreciation (in millions)	$	993		$	175

_______________________________________

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

Belle River

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

Ludington Hydroelectric Pumped Storage

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

NOTE 7 — ASSET RETIREMENT OBLIGATIONS

The Company has a legal retirement obligation for the decommissioning costs for its Fermi 1 and Fermi 2 nuclear plants, dismantlement of facilities located on leased property and various other operations. The Company has conditional retirement obligations for 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.

64

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

A reconciliation of the asset retirement obligations for 2014 follows:

	(In millions)
Asset retirement obligations at December 31, 2013	$	1,827
Accretion	112
Liabilities incurred	11
Liabilities settled	(12		)
Revision in estimated cash flows	24
Asset retirement obligations at December 31, 2014	$	1,962

Approximately $1.7 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. For additional discussion of Nuclear decommissioning trust fund assets see Note 11 to the Consolidated Financial Statements, "Fair Value".

NOTE 8 — 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.

65

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

	2014			2013
	(In millions)
Assets
Recoverable pension and other postretirement costs:
Pension	$	2,284		$	1,660
Other postretirement costs	234			—
Asset retirement obligation	448			394
Recoverable Michigan income taxes	267			286
Unamortized loss on reacquired debt	67			63
Other recoverable income taxes	66			71
Accrued PSCR/GCR revenue	61			—
Deferred environmental costs	59			59
Cost to achieve Performance Excellence Process	54			75
Recoverable income taxes related to securitized regulatory assets	19			126
Removal costs asset	15			—
Transitional Reconciliation Mechanism	14			—
Other	139			129
	3,727			2,863
Less amount included in current assets	(76		)	(26		)
	$	3,651		$	2,837
Securitized regulatory assets	$	34		$	231

Liabilities
Removal costs liability	$	308		$	351
Renewable energy	227			277
Over recovery of Securitization	71			72
Refundable revenue decoupling/deferred gain	67			127
Negative pension offset	67			84
Refundable income taxes	33			45
Energy optimization	24			31
Fermi 2 refueling outage	16			26
Refundable other postretirement costs	—			72
Accrued PSCR/GCR refund	—			65
Other	7			14
	$	820		$	1,164
Less amount included current liabilities	(153		)	(302		)
	$	667		$	862

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's 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.

66

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 service 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 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 MCIT was enacted. The regulatory asset was remeasured to reflect the impact of the MCIT tax rate. (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.

• 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)

• 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.

• 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)

• 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.

• 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, which ended in December 2014, was in place to recover the income tax over a fourteen-year period. (a)

• Removal costs asset — Receivable for the recovery of asset removal expenditures in excess of amounts collected from customers.

• Transitional Reconciliation Mechanism (TRM) — The MPSC approved the recovery of the deferred net incremental revenue requirement associated with the transition of PLD customers to DTE Electric's distribution system, effective July 1, 2014. Annual reconciliations will be filed and surcharges will be implemented to recover approved amounts. (a)

• 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, which ended in December 2014, was in place to recover the securitized regulatory asset over a fourteen-year period.

_________________________________

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

67

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

LIABILITIES

• Removal costs liability — 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.

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

• 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 MCOA 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 is being amortized into earnings in 2014 and 2015.

• 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.

• 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 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.

2014 Electric Rate Case Filing

DTE Electric filed a rate case with the MPSC on December 19, 2014 requesting an increase in base rates of $370 million based on a projected twelve-month period ending June 30, 2016. The requested increase in base rates is due primarily to an increase in net plant resulting from infrastructure investments, plant acquisitions, environmental compliance and reliability improvement projects. The rate filing also included projected changes in sales, working capital, operation and maintenance expenses, return on equity and capital structure. New rates could be self-implemented in July 2015, with a final order expected in December 2015.

2010 Electric Rate Case Filing - Court of Appeals Decision

In July 2013, the MCOA issued a decision relating to an appeal of the October 2011 MPSC order in DTE Electric's October 2010 rate case filing. The MCOA 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. In August 2013, the MPSC reopened the 2010 electric rate case for the limited purpose of addressing the MCOA's opinion on AMI. On November 6, 2014, the MPSC issued an order affirming the recovery of costs associated with the AMI program.

68

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Customer360 Accounting Authority

In July 2014, DTE Electric filed an application for accounting authority to defer certain costs associated with implementing Customer360, which is an integrated software application that enables improved interface among customer service, billing, meter reading, credit and collections, device management, account management, and retail access. The estimated implementation cost of Customer360 is approximately $215 million and DTE Electric proposed an amortization period of 15 years. On September 26, 2014, the MPSC approved the accounting request.

Refundable Revenue Decoupling / Deferred Gain Amortization

In September 2012, the MPSC approved DTE Electric's accounting application to defer for future amortization the gain resulting from the reversal of the Company's $127 million regulatory liability associated with the operation of the RDM. The approved application provided for the amortization of the regulatory liability to income, at a monthly rate of approximately $10.6 million, beginning January 2014. On April 1, 2014, the MPSC approved DTE Electric's accounting application to suspend the amortization of the RDM regulatory liability as of June 30, 2014 and to complete the amortization over the period January 2015 to June 2015. If DTE Electric's base rates are increased prior to July 1, 2015, the Company will cease amortization and refund to customers the remaining unamortized balance of the regulatory liability.

Transition of PLD Customers to DTE Electric's Distribution System

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 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 May 13, 2014, the MPSC approved the TRM as requested and also ordered DTE Electric to include in the TRM the 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. The meter installation phase of the transition was completed in June 2014. On July 1, 2014, former PLD customers became customers of DTE Electric.

PSCR 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.

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 approximately 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 2 related purchased power costs. Resolution of this matter is expected in 2015.

DTE Gas Infrastructure Recovery Mechanism (IRM)

In November 2014, DTE Gas filed an application with the MPSC for approval of an increased IRM surcharge to recover an additional $47 million of annual capital expenditures in 2016 and 2017 for its gas main renewal program. Resolution of this matter is anticipated in 2015.

69

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 9 — 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:

	2014			2013			2012
	(In millions)
Income before income taxes	$	1,275		$	922		$	960
Income tax expense at 35% statutory rate	$	446		$	323		$	336
Production tax credits	(119		)	(68		)	(49		)
Investment tax credits	(6		)	(6		)	(6		)
Depreciation	(4		)	(4		)	(4		)
AFUDC - Equity	(7		)	(5		)	(4		)
Employee Stock Ownership Plan dividends	(4		)	(4		)	(4		)
Domestic production activities deduction	—			(14		)	(14		)
State and local income taxes, net of federal benefit	51			37			37
Enactment of New York Corporate Income Tax Legislation, net of federal benefit	8			—			—
Other, net	(1		)	(5		)	(6		)
Income tax expense	$	364		$	254		$	286
Effective income tax rate	28.5		%	27.5		%	29.8		%

Components of income tax expense were as follows:

	2014			2013		2012
	(In millions)
Current income tax expense (benefit)
Federal	$	(16	)	$	74	$	190
State and other income tax	24			16		49
Total current income taxes	8			90		239
Deferred income tax expense
Federal	289			122		39
State and other income tax	67			42		8
Total deferred income taxes	356			164		47
Total income taxes from continuing operations	364			254		286
Discontinued operations	—			—		(29		)
Total	$	364		$	254	$	257

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.

70

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

	2014			2013
	(In millions)
Property, plant and equipment	$	(3,832	)	$	(3,372	)
Securitized regulatory assets	(2		)	(127		)
Tax credit carry-forwards	296			266
Pension and benefits	(152		)	(30		)
State net operating loss and credit carry-forwards	39			43
Other	(19		)	(92		)
	(3,670		)	(3,312		)
Less valuation allowance	(31		)	(37		)
	$	(3,701	)	$	(3,349	)
Current deferred income tax assets (liabilities)	$	75		$	(28	)
Long-term deferred income tax liabilities	(3,776		)	(3,321		)
	$	(3,701	)	$	(3,349	)
Deferred income tax assets	$	861		$	934
Deferred income tax liabilities	(4,562		)	(4,283		)
	$	(3,701	)	$	(3,349	)

Tax credit carry forwards include $29 million of general business credits that expire through 2034 and $267 million of alternative minimum tax credits that may be carried forward indefinitely. The alternative minimum tax credits are production tax credits earned prior to 2006 but not utilized. The majority of these alternative minimum tax credits were generated from projects that had received a private letter ruling (PLR) from the 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 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 $39 million and $43 million at December 31, 2014 and 2013, respectively. The state net operating loss and credit carry-forwards expire from 2015 through 2034. The Company has recorded valuation allowances at December 31, 2014 and 2013 of approximately $31 million and $37 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:

	2014			2013			2012
	(In millions)
Balance at January 1	$	10		$	11		$	48
Reductions for tax positions of prior years	—			—			(2		)
Additions for tax positions of current year	—			—			1
Settlements	—			—			(30		)
Lapse of statute of limitations	(1		)	(1		)	(6		)
Balance at December 31	$	9		$	10		$	11

The Company had $2 million of unrecognized tax benefits at December 31, 2014 and 2013, 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 $6 million within the next twelve months.

71

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 at December 31, 2014 and 2013. The Company had no accrued penalties pertaining to income taxes. The Company recognized interest expense (income) related to income taxes of a nominal amount in 2014 and 2013 and $(1) million in 2012.

In 2014, the Company settled a federal tax audit for the 2012 tax year. The Company's federal income tax returns for 2013 and subsequent years remain subject to examination by the IRS. The Company's MBT and MCIT 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.

NOTE 10 — 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:

	2014		2013		2012
	(In millions, expect per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	905	$	661	$	610
Average number of common shares outstanding	177		175		171
Weighted average net restricted shares outstanding	—		1		1
Dividends declared — common shares	$	475	$	453	$	413
Dividends declared — net restricted shares	1		1		1
Total distributed earnings	$	476	$	454	$	414
Net income less distributed earnings	$	429	$	207	$	196
Distributed (dividends per common share)	$	2.69	$	2.59	$	2.42
Undistributed	2.42		1.17		1.14
Total Basic Earnings per Common Share	$	5.11	$	3.76	$	3.56
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	905	$	661	$	610
Average number of common shares outstanding	177		175		171
Average incremental shares from assumed exercise of options	—		—		1
Common shares for dilutive calculation	177		175		172
Weighted average net restricted shares outstanding	—		1		1
Dividends declared — common shares	$	475	$	453	$	413
Dividends declared — net restricted shares	1		1		1
Total distributed earnings	$	476	$	454	$	414
Net income less distributed earnings	$	429	$	207	$	196
Distributed (dividends per common share)	$	2.69	$	2.59	$	2.42
Undistributed	2.41		1.17		1.13
Total Diluted Earnings per Common Share	$	5.10	$	3.76	$	3.55

72

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 11 — 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, 2014 and 2013. 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.

73

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2014 and 2013:

	December 31, 2014															December 31, 2013
	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)	$	13		$	99		$	—		$	—		$	112		$	10		$	115		$	—		$	—		$	125
Nuclear decommissioning trusts	792			449			—			—			1,241			779			412			—			—			1,191
Other investments (c) (d)	100			50			—			—			150			92			44			—			—			136
Derivative assets:
Commodity Contracts:
Natural Gas	555			140			92			(681		)	106			273			89			34			(382		)	14
Electricity	—			295			47			(280		)	62			—			261			139			(291		)	109
Other	42			—			3			(42		)	3			33			1			3			(34		)	3
Other derivative contracts (e)	—			4			—			(3		)	1			—			—			—			—			—
Total derivative assets	597			439			142			(1,006		)	172			306			351			176			(707		)	126
Total	$	1,502		$	1,037		$	142		$	(1,006	)	$	1,675		$	1,187		$	922		$	176		$	(707	)	$	1,578
Liabilities:
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(578	)	$	(78	)	$	(62	)	$	679		$	(39	)	$	(277	)	$	(140	)	$	(86	)	$	395		$	(108	)
Electricity	—			(290		)	(52		)	298			(44		)	—			(272		)	(126		)	269			(129		)
Other	(32		)	(9		)	(4		)	45			—			(32		)	(2		)	—			34			—
Other derivative contracts (e)	—			(5		)	—			3			(2		)	—			(1		)	—			—			(1		)
Total derivative liabilities	(610		)	(382		)	(118		)	1,025			(85		)	(309		)	(415		)	(212		)	698			(238		)
Total	$	(610	)	$	(382	)	$	(118	)	$	1,025		$	(85	)	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)
Net Assets (Liabilities) at the end of the period	$	892		$	655		$	24		$	19		$	1,590		$	878		$	507		$	(36	)	$	(9	)	$	1,340
Assets:
Current	$	582		$	504		$	109		$	(955	)	$	240		$	277		$	400		$	139		$	(592	)	$	224
Noncurrent (f)	920			533			33			(51		)	1,435			910			522			37			(115		)	1,354
Total Assets	$	1,502		$	1,037		$	142		$	(1,006	)	$	1,675		$	1,187		$	922		$	176		$	(707	)	$	1,578
Liabilities:
Current	$	(572	)	$	(357	)	$	(112	)	$	964		$	(77	)	$	(268	)	$	(328	)	$	(177	)	$	578		$	(195	)
Noncurrent	(38		)	(25		)	(6		)	61			(8		)	(41		)	(87		)	(35		)	120			(43		)
Total Liabilities	$	(610	)	$	(382	)	$	(118	)	$	1,025		$	(85	)	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)
Net Assets (Liabilities) at the end of the period	$	892		$	655		$	24		$	19		$	1,590		$	878		$	507		$	(36	)	$	(9	)	$	1,340

_______________________________________

(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, 2014, available-for-sale securities of $112 million included $105 million and $7 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively. 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.

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

(d) Available-for-sale equity securities of $8 million at December 31, 2014 and $7 million at December 31, 2013 are included in Other investments on the Consolidated Statements of Financial Position.

(e) Primarily includes Foreign currency exchange contracts.

(f) Includes $150 million and $136 million of Other investments that are included in the Consolidated Statements of Financial Position in Other investments at December 31, 2014 and 2013, respectively.

74

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.

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 hold exchange-traded equity or debt securities and are valued based on stated NAVs. 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.

75

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2014 and 2013:

	Year Ended December 31, 2014												Year Ended December 31, 2013
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of December 31	$	(52	)	$	13		$	3		$	(36	)	$	(38	)	$	23		$	2		$	(13	)
Transfers into Level 3 from Level 2	—			—			—			—			1			—			—			1
Transfers from Level 3 into Level 2	(2		)	—			—			(2		)	—			—			—			—
Total gains (losses):
Included in earnings	(40		)	25			(5		)	(20		)	(32		)	75			—			43
Recorded in regulatory assets/liabilities	—			—			8			8			—			—			5			5
Purchases, issuances and settlements:
Purchases	—			1			—			1			(8		)	1			—			(7		)
Issuances	—			(3		)	—			(3		)	—			(1		)	—			(1		)
Settlements	124			(41		)	(7		)	76			25			(85		)	(4		)	(64		)
Net Assets (Liabilities) as of December 31	$	30		$	(5	)	$	(1	)	$	24		$	(52	)	$	13		$	3		$	(36	)
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	35		$	9		$	(4	)	$	40		$	(49	)	$	48		$	—		$	(1	)

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. There were no transfers between levels 1 and 2 during the years ended December 31, 2014 and 2013.

The following tables present the unobservable inputs related to Level 3 assets and liabilities as of December 31, 2014 and 2013:

	December 31, 2014
Commodity Contracts	Derivative Assets		Derivative Liabilities			Valuation Techniques	Unobservable Input	Range						Weighted Average
	(In millions)
Natural Gas	$	92	$	(62	)	Discounted Cash Flow	Forward basis price (per MMBtu)	$	(2.28	) —	$	7.83	/MMBtu	$	(0.22	)/MMBtu
Electricity	$	47	$	(52	)	Discounted Cash Flow	Forward basis price (per MWh)	$	(14	) —	$	15	/MWh	$	4	/MWh

	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

The unobservable inputs used in the fair value measurement of the electricity and natural gas commodity types consist 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.

76

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 as assumptions about the remaining life of the loans and credit risk. Depending on the information available, other valuation techniques may be used that rely on internal assumptions and models. Valuation policies and procedures are determined by 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, 2014 and 2013:

	December 31, 2014								December 31, 2013
	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	$	41	$	—	$	—	$	41
Dividends payable	$	122	$	122	$	—	$	—	$	116	$	116	$	—	$	—
Short-term borrowings	$	398	$	—	$	398	$	—	$	131	$	—	$	131	$	—
Long-term debt, excluding capital leases	$	8,606	$	489	$	8,308	$	706	$	8,094	$	425	$	7,551	$	499

For further fair value information on financial and derivative instruments see Note 12 to the Consolidated Financial Statements, "Financial and Other 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 7 to the Consolidated Financial Statements, "Asset Retirement Obligations".

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

	December 31, 2014		December 31, 2013
	(In millions)
Fermi 2	$	1,221	$	1,172
Fermi 1	3		3
Low level radioactive waste	17		16
Total	$	1,241	$	1,191

77

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
	2014			2013			2012
	(In millions)
Realized gains	$	54		$	83		$	37
Realized losses	$	(33	)	$	(41	)	$	(31	)
Proceeds from sales of securities	$	1,146		$	1,118		$	759

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, 2014							December 31, 2013
	Fair Value		Unrealized Gains		Unrealized Losses			Fair Value		Unrealized Gains		Unrealized Losses
	(In millions)
Equity securities	$	756	$	204	$	(39	)	$	730	$	201	$	(25	)
Debt securities	474		21		(2		)	442		12		(6		)
Cash and cash equivalents	11		—		—			19		—		—
	$	1,241	$	225	$	(41	)	$	1,191	$	213	$	(31	)

At December 31, 2014, investments in the nuclear decommissioning trust funds consisted of approximately 61% in publicly traded equity securities, 38% in fixed debt instruments and 1% in cash equivalents. At December 31, 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.

The debt securities at December 31, 2014 and 2013 had an average maturity of approximately 7 years. 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.

Other Securities

At December 31, 2014 and 2013, these securities are comprised primarily of money-market and equity securities. During the years ended December 31, 2014 and 2013, 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, 2014, 2013 and 2012 were $14 million, $22 million and $11 million, respectively.

NOTE 12 — 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.

78

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 electricity, 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.

DTE 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 MTM and recoverable through the PSCR mechanism when settled. This results in the deferral of unrealized gains and losses as Regulatory assets or liabilities until realized.

DTE 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 natural gas supply requirements through March 2017. 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, 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.

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, 2014 and 2013 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.

79

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Derivative Activities

The Company manages its 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, 2014 and 2013:

	December 31, 2014					December 31, 2013
	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	4	$	(5	)	$	—	$	(1	)
Commodity Contracts:
Natural Gas	787		(718		)	396		(503		)
Electricity	342		(342		)	400		(398		)
Other	45		(45		)	37		(34		)
Total derivatives not designated as hedging instruments:	$	1,178	$	(1,110	)	$	833	$	(936	)
Total derivatives:
Current	$	1,083	$	(1,041	)	$	691	$	(773	)
Noncurrent	95		(69		)	142		(163		)
Total derivatives	$	1,178	$	(1,110	)	$	833	$	(936	)

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.

80

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 $7 million and $19 million at December 31, 2014 and 2013, respectively, which could be used to offset net derivative liabilities. Letters of credit received from third parties which could be used to offset our net derivative assets were approximately $5 million and $1 million at December 31, 2014 and 2013, respectively. 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.

The total cash collateral posted, net of cash collateral received, was $61 million and $12 million as of December 31, 2014 and 2013, respectively. There was no cash collateral related to unrealized positions to net against derivative assets while derivative liabilities are shown net of cash collateral of $19 million as of December 31, 2014. As of December 31, 2013, derivative assets and derivative liabilities are shown net of cash collateral of $26 million and $17 million, respectively. The Company recorded cash collateral paid of $44 million and cash collateral received of $2 million not related to unrealized derivative positions as of December 31, 2014. 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. 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, 2014 and 2013:

	December 31, 2014									December 31, 2013
	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	$	787		$	(681	)	$	106		$	396		$	(382	)	$	14
Electricity	342			(280		)	62			400			(291		)	109
Other	45			(42		)	3			37			(34		)	3
Other derivative contracts (a)	4			(3		)	1			—			—			—
Total derivative assets	$	1,178		$	(1,006	)	$	172		$	833		$	(707	)	$	126
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(718	)	$	679		$	(39	)	$	(503	)	$	395		$	(108	)
Electricity	(342		)	298			(44		)	(398		)	269			(129		)
Other	(45		)	45			—			(34		)	34			—
Other derivative contracts (a)	(5		)	3			(2		)	(1		)	—			(1		)
Total derivative liabilities	$	(1,110	)	$	1,025		$	(85	)	$	(936	)	$	698		$	(238	)

_______________________________________

(a) Primarily includes Foreign currency exchange contracts

81

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The following table presents the netting offsets of derivative assets and liabilities at December 31, 2014 and 2013:

	December 31, 2014												December 31, 2013
	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	$	1,083		$	95		$	(1,041	)	$	(69	)	$	691		$	142		$	(773	)	$	(163	)
Counterparty netting	(955		)	(51		)	955			51			(566		)	(115		)	566			115
Collateral adjustment	—			—			9			10			(26		)	—			12			5
Total derivatives as reported	$	128		$	44		$	(77	)	$	(8	)	$	99		$	27		$	(195	)	$	(43	)

The effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for years ended December 31, 2014 and 2013 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		2014			2013
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	(2	)	$	(1	)
Commodity Contracts:
Natural Gas	Operating Revenue	(30		)	(48		)
Natural Gas	Fuel, purchased power and gas	(5		)	(44		)
Electricity	Operating Revenue	123			82
Other	Operating Revenue	(7		)	—
Total		$	79		$	(11	)

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 MTM 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 MTM method with unrealized and realized gains and losses for sales recorded in Operating revenue and purchases recorded in Fuel, purchased power and gas.

The following represents the cumulative gross volume of derivative contracts outstanding as of December 31, 2014:

Commodity	Number of Units
Natural Gas (MMBtu)	895,599,953
Electricity (MWh)	11,296,153
Foreign Currency Exchange (Canadian dollars)	63,022,462

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 require 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 required 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, 2014, DTE Energy's contractual obligation to post collateral 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 $349 million.

82

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

As of December 31, 2014, the Company had approximately $1,058 million of derivatives in net liability positions, for which hard triggers exist. Collateral of approximately $12 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 $973 million. The net remaining amount of approximately $73 million is derived from the $349 million noted above.

NOTE 13 — 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:

	2014			2013
	(In millions)
Mortgage bonds, notes and other
DTE Energy Debt, Unsecured
4.6% due 2016 to 2033	$	1,647		$	1,297
DTE Electric Taxable Debt, Principally Secured
4.5% due 2016 to 2044	4,824			4,286
DTE Electric Tax-Exempt Revenue Bonds (b)
5.2% due 2020 to 2030	330			558
DTE Gas Taxable Debt, Principally Secured
5.2% due 2015 to 2044	1,099			1,029
Other Long-Term Debt, Including Non-Recourse Debt	121			142
	8,021			7,312
Less amount due within one year	(161		)	(694		)
	$	7,860		$	6,618
Securitization bonds
6.6% due 2015	$	105		$	302
Less amount due within one year	(105		)	(197		)
	$	—		$	105
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, 2014 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.

83

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Debt Issuances

In 2014, the following debt was issued:

Company	Month Issued	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Energy	May	Senior Notes (a)	3.50	%	2024	$	350
DTE Electric	June	Mortgage Bonds (a)	3.77	%	2026	100
DTE Electric	June	Mortgage Bonds (a)	4.60	%	2044	150
DTE Electric	July	Mortgage Bonds (a)	3.375	%	2025	350
DTE Electric	July	Mortgage Bonds (a)	4.30	%	2044	350
DTE Energy	November	Senior Notes (a)	2.40	%	2019	300
DTE Gas	December	Mortgage Bonds (a)	4.35	%	2044	150
						$	1,750

_______________________________________

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

Debt Redemptions

In 2014, the following debt was redeemed:

Company	Month	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March	Mortgage Bonds	Various		2014	$	13
DTE Electric	March	Securitization Bonds	6.62	%	2014	100
DTE Electric	April	Tax Exempt Revenue Bonds (a)	2.35	%	2024	31
DTE Electric	April	Tax Exempt Revenue Bonds (a)	4.65	%	2028	32
DTE Gas	May	Mortgage Bonds	8.25	%	2014	80
DTE Energy	May	Senior Notes	7.625	%	2014	300
DTE Electric	June	Tax Exempt Revenue Bonds (a)	4.875	%	2029	36
DTE Electric	June	Tax Exempt Revenue Bonds (a)	6.00	%	2036	69
DTE Electric	July	Senior Notes	4.80	%	2015	200
DTE Electric	August	Senior Notes	5.40	%	2014	200
DTE Electric	August	Tax Exempt Revenue Bonds (a)	5.25	%	2029	60
DTE Electric	September	Securitization Bonds	6.62	%	2014	96
DTE Energy	Various	Other Long Term Debt	Various		2014	20
						$	1,237

_______________________________________

(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, excluding any unamortized discount or premium on debt:

	2015		2016		2017		2018		2019		2020 and Thereafter		Total
	(In millions)
Amount to mature	$	266	$	465	$	9	$	407	$	427	$	7,046	$	8,620

Junior Subordinated Debentures

At December 31, 2014, DTE Energy had $280 million of 6.5% Junior Subordinated Debentures due 2061 and $200 million of 5.25% Junior Subordinated Debentures due 2062. DTE Energy has the right to defer interest payments on the debt securities. Should DTE Energy 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. As of December 31, 2014, no interest payments have been deferred on the debt securities.

84

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 14 — PREFERRED AND PREFERENCE SECURITIES

As of December 31, 2014, 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

NOTE 15 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

DTE Energy and its wholly owned subsidiaries, DTE Electric and DTE Gas, have unsecured revolving credit agreements that can be used for general corporate borrowings, but are intended to provide liquidity support for each of the companies’ commercial paper programs. 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. At December 31, 2014, the total funded debt to total capitalization ratios for DTE Energy, DTE Electric and DTE Gas are 0.50 to 1, 0.51 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, 2014 is shown in the following table:

	DTE Energy		DTE Electric		DTE Gas		Total
	(In millions)
Unsecured letter of credit facility, expiring in February 2015	$	100	$	—	$	—	$	100
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Unsecured revolving credit facility, expiring April 2018	1,200		300		300		1,800
	1,425		300		300		2,025
Amounts outstanding at December 31, 2014:
Commercial paper issuances	203		50		145		398
Letters of credit	204		—		—		204
	407		50		145		602
Net availability at December 31, 2014	$	1,018	$	250	$	155	$	1,423

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $35 million which are used for various corporate purposes.

The weighted average interest rate for short-term borrowings was 0.4% and 0.2% at December 31, 2014 and 2013, respectively.

85

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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, 2014, 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 $37 million and $138 million at December 31, 2014 and 2013, respectively.

Dividend Restrictions

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. The effect of this provision was to restrict the payment of approximately $730 million at December 31, 2014 of total retained earnings of approximately $4.6 billion. There are no other effective limitations with respect to the Company’s ability to pay dividends.

NOTE 16 — CAPITAL AND OPERATING LEASES

Lessee  - Operating Lease — The Company leases various assets under 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, 2014 were:

	Operating Leases
	(In millions)
2015	$	42
2016	34
2017	28
2018	23
2019	14
Thereafter	78
Total minimum lease payments	$	219

Rental expense for operating leases was $38 million in 2014, $34 million in 2013 and $36 million in 2012.

86

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 two energy services agreements, a portion of which are accounted for as capital leases. One agreement expires in 2021. The other 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, 2014, were as follows:

	Capital Leases
	(In millions)
2015	$	12
2016	13
2017	13
2018	13
2019	10
Thereafter	9
Total minimum future lease receipts	70
Residual value of leased pipeline	40
Less unearned income	(34		)
Net investment in capital lease	76
Less current portion	(5		)
	$	71

NOTE 17 — 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. The EPA and the State of Michigan have issued emission reduction regulations relating to ozone, fine particulate, regional haze, mercury, and other air pollution. These rules have led to controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, mercury and other emissions. To comply with these requirements, DTE Electric spent approximately $2.2 billion through 2014. The Company estimates DTE Electric will make capital expenditures of approximately $100 million in 2015 and up to approximately $30 million of additional capital expenditures through 2019 based on current regulations.

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), requires further reductions of sulfur dioxide and nitrogen oxides emissions effective January 2015. DTE Electric expects to meet its obligations under CSAPR beginning in 2015.

The Mercury and Air Toxics Standard (MATS) rule, formerly known as the Electric Generating Unit Maximum Achievable Control Technology (EGU MACT) Rule was finalized in December 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 all relevant 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 November 2014, the Supreme Court agreed to review a challenge to the MATS rule based on a narrowly focused question of how the EPA considered costs in regulating air pollutants emitted by electric utilities. DTE Electric cannot predict the financial impact or outcome of this Supreme Court case, or the timing of its resolution.

The EPA proposed revised air quality standards for ground level ozone in November 2014 and the standards are expected to be finalized by October 2015. DTE Electric will engage with the EPA and other stakeholders in commenting on this rule. DTE Electric cannot predict the financial impact of the proposed ozone standards at this time.

87

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

In July 2009, DTE Energy received a 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. In August 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. In October 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit. In March 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. In September 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. In March 2014, the U.S. District Court judge granted again DTE Energy's motion for summary judgment dismissing the civil case related to Monroe Unit 2. In April 2014, the U.S. District Court judge granted motions filed by the EPA and the Sierra Club to amend their New Source Review complaint adding additional claims for Monroe Units 1, 2 and 3, Belle River Units 1 and 2, Trenton Channel Unit 9 and denied the claims related to River Rouge that were brought by the Sierra Club. In June 2014, the EPA filed a motion requesting certification for appeal of the March 2014 summary judgment decision. In October 2014, the EPA and the U.S. Department of Justice filed the anticipated notice of appeal of the U.S. District Court judge's dismissal of the Monroe Unit 2 case. This will officially start the appellate process. The amended New Source Review claims are all stayed until the appeal is resolved by the U.S. Court of Appeals for the Sixth Circuit.

DTE Energy and DTE Electric believe that the plants and generating units identified by the EPA and the Sierra Club 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.

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. A final rule was issued in May 2014. The final rule specifies a time period exceeding three years to complete studies to determine the type of technology needed to reduce impacts to fish. Final compliance for the installation of the required technology will be determined by each state on a case by case basis. We are currently evaluating the compliance options and working with the State of Michigan on evaluating whether any controls are needed. These evaluations/studies may require modifications to some existing intake structures. It is not possible to quantify the impact of this rulemaking at this time.

In April 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 September 2015. It is not possible at this time to quantify the impacts of these developing requirements.

88

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 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 MGP 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, 2014 and 2013, the Company had $10 million and $8 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 believes the likelihood of a material change to the accrued amount is remote based on current knowledge of the conditions at each site.

In December 2014, the EPA released a pre-publication version of a rule to regulate coal ash. This rule is based on the continued listing of ash as a non-hazardous waste, and relies on various self-implementation design and performance standards. The rule is still being evaluated and it is not possible to quantify its impact at this time. DTE Electric owns and operates three permitted engineered ash storage facilities to dispose of fly ash from coal fired power plants and operates a number of smaller impoundments at its power plants.

Gas

Contaminated and Other Sites — Gas segment, owns or previously owned, 15 former MGP sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. Cleanup of three of the MGP sites is complete and the sites were closed. We completed partial closure of two sites in 2014. Cleanup activities associated with the remaining sites will be continued 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. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites, including gate stations, gas pipeline releases and underground storage tank locations. As of December 31, 2014 and 2013, the Company had $24 million and $28 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, 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 settled the alleged violations by implementing best management practices to address the issues and repair/upgrade their wastewater treatment plant. The Company recently received a permit to upgrade its existing waste water treatment system and is currently seeking a permit from the PADEP to further upgrade its wastewater treatment technology to a biological treatment facility. The Company expects to spend $1 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 will also spend up to an additional $13 million over the next few years to upgrade the treatment technology to biological treatment to meet future regulatory requirements and gain other operational improvement savings.

89

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

The Company received an NOV from the Allegheny County (PA) Health Department pertaining to excessive opacity readings from fugitive sources (mainly pushing emissions) in excess of its opacity standards for the Pennsylvania coke battery facility. Fugitive sources at the plant are in full compliance with the applicable Federal Opacity Standards. In February 2014, the Company received from the Group Against Smog & Pollution (GASP) a 60 day Notice of Intent to sue letter under the Federal Clean Air Act and/or Article XXI of the Allegheny County (PA) Health Department's Rules and Regulations. GASP alleged in the letter that the Company's coke battery facility in Pennsylvania was in violation of visible emissions limits from charging activities, door leaks, the combustion stack and pushing operations and hydrogen sulfide emission limits on flared, mixed or combusted coke oven gas. To resolve these issues, the Company agreed to a Consent Order and Agreement with Allegheny County pursuant to which the Company paid a fine of $300,000 and will spend $300,000 for a supplemental environmental project to enhance particulate collection efficiency from the coke battery's quench tower. Notwithstanding the agreement reached with the County, GASP proceeded with the filing of their complaint in May 2014. The Company believes that the GASP suit is without merit and filed a motion to dismiss in July 2014.

Other

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 information gathering stage, and DTE Energy is unable to estimate any required emissions reductions at this time.

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. 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 $1.5 billion in primary coverage and $1.25 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. The total limit for property damage for non-nuclear events is $2 billion and an aggregate of $328 million of coverage for extra expenses over a two-year period.

On January 13, 2015, the Terrorism Risk Insurance Program Reauthorization Act of 2015 was signed, extending TRIA through December 31, 2020. 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 NEIL policies, DTE Electric could be liable for maximum assessments of up to approximately $35 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 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.

90

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Nuclear Fuel Disposal Costs

In accordance with the Federal Nuclear Waste Policy Act of 1982, DTE Electric has a contract with the DOE for the future storage and disposal of spent nuclear fuel from Fermi 2 that required DTE Electric to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold. The fee was 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 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 agreement, including extensions, provides for a claims process and payment of delay-related costs experienced by DTE Electric through 2016. DTE Electric's claims are being settled and paid on a timely basis. The settlement proceeds reduce the cost of the dry cask storage facility assets and provide reimbursement for related operating expenses. The 1 mill per kWh DOE fee was reduced to zero effective May 16, 2014.

DTE Electric currently employs a spent nuclear fuel storage strategy utilizing a fuel pool and a newly completed dry cask storage facility. The initial dry cask loading campaign planned for 2014 has been completed. 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.

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.

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, 2014 is approximately $1 billion. Payment under these guarantees is considered remote.

REF Guarantees

The Company has provided certain guarantees and indemnities in conjunction with the sales of interests in its REF 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, 2014 is approximately $172 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, 2014. 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, 2014, the Company had approximately $49 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.

91

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Purchase Commitments

As of December 31, 2014, 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 $9.0 billion from 2015 through 2051 as detailed in the following table:

	(In millions)
2015	$	2,384
2016	1,258
2017	742
2018	477
2019	431
2020 and thereafter	3,723
	$	9,015

The Company also estimates that 2015 capital expenditures and contributions to equity method investments will be approximately $2.6 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.

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.

For a discussion of contingencies related to regulatory matters and derivatives see Notes 8 and 12 to the Consolidated Financial Statements, "Regulatory Matters" and "Financial and Other Derivative Instruments".

NOTE 18 — 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 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 to newly hired employees. 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.

92

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 $188 million to its qualified pension plans in 2014. At the discretion of management, and depending upon financial market conditions, the Company anticipates making up to $180 million in contributions to the pension plans in 2015.

Net pension cost includes the following components:

	2014			2013			2012
	(In millions)
Service cost	$	83		$	94		$	82
Interest cost	212			192			204
Expected return on plan assets	(273		)	(266		)	(244		)
Amortization of:
Net loss	157			208			176
Special termination benefits	—			—			2
Net pension cost	$	179		$	228		$	220

	2014			2013
	(In millions)
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income
Net actuarial (gain) loss	$	805		$	(581	)
Amortization of net actuarial loss	(157		)	(208		)
Prior service cost	(7		)	—
Total recognized in Regulatory assets and Other comprehensive income	$	641		$	(789	)
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	820		$	(561	)
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	$	206		$	151

93

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:

	2014			2013
	(In millions)
Accumulated benefit obligation, end of year	$	4,853		$	4,068
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	4,380		$	4,729
Service cost	83			94
Interest cost	212			192
Plan amendments	(7		)	(3		)
Actuarial (gain) loss	836			(400		)
Benefits paid	(235		)	(232		)
Projected benefit obligation, end of year	$	5,269		$	4,380
Change in plan assets
Plan assets at fair value, beginning of year	$	3,720		$	3,223
Actual return on plan assets	301			445
Company contributions	195			284
Benefits paid	(235		)	(232		)
Plan assets at fair value, end of year	$	3,981		$	3,720
Funded status of the plans	$	(1,288	)	$	(660	)
Amount recorded as:
Current liabilities	$	(8	)	$	(7	)
Noncurrent liabilities	(1,280		)	(653		)
	$	(1,288	)	$	(660	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	194		$	174
Prior service (credit)	(1		)	(1		)
	$	193		$	173
Amounts recognized in Regulatory assets (see Note 8)
Net actuarial loss	$	2,285		$	1,654
Prior service (credit) cost	(1		)	6
	$	2,284		$	1,660

At December 31, 2014, 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)
2015	$	269
2016	277
2017	286
2018	298
2019	309
2020-2024	1,634
Total	$	3,073

94

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

	2014	2013	2012
Projected benefit obligation
Discount rate	4.12%	4.95%	4.15%
Rate of compensation increase	4.65%	4.20%	4.20%
Net pension costs
Discount rate	4.95%	4.15%	5.00%
Rate of compensation increase	4.20%	4.20%	4.20%
Expected long-term rate of return on plan assets	7.75%	8.25%	8.25%

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 2015. The Company believes these rates are a reasonable assumption for the long-term rate of return on its plan assets for 2015 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-U.S. 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, 2014 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	%

95

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Fair Value Measurements for pension plan assets at December 31, 2014 and 2013(a):

	December 31, 2014											December 31, 2013
	Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
	(In millions)
Asset category:
Short-term investments (b)	$	46		$	—		$	—	$	46		$	22	$	—	$	—	$	22
Equity securities
U.S. large cap (c)	899			—			—		899			896		—		—		896
U.S. small/mid cap (d)	225			—			—		225			221		—		—		221
Non U.S. (e)	526			219			—		745			611		130		—		741
Fixed income securities (f)	7			1,113			—		1,120			16		921		—		937
Hedge funds and similar investments (g)	226			95			438		759			268		70		395		733
Private equity and other (h)	—			—			187		187			—		—		170		170
Securities lending (i)	(189		)	(50		)	—		(239		)	—		—		—		—
Securities lending collateral (i)	189			50			—		239			—		—		—		—
Total	$	1,929		$	1,427		$	625	$	3,981		$	2,034	$	1,121	$	565	$	3,720

_______________________________________

(a) For a description of levels within the fair value hierarchy see Note 11 to the Consolidated Financial Statements, "Fair Value".

(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.

(i) In 2014, DTE Energy began a securities lending program with a third party agent. The program allows the agent to lend certain securities from the Company's pension trusts to selected entities against receipt of collateral (in the form of cash) as provided for and determined in accordance with its securities lending agency agreement.

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 NAVs. 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 trustee challenges an assigned price and determines that another price source is considered to be preferable. DTE Energy has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, DTE Energy selectively corroborates the fair values of securities by comparison of market-based price sources.

96

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

	Year Ended December 31, 2014									Year Ended December 31, 2013
	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	$	395		$	170		$	565		$	339	$	179		$	518
Total realized/unrealized gains (losses)	22			16			38			40		4			44
Purchases, sales and settlements:
Purchases	22			31			53			16		15			31
Sales	(1		)	(30		)	(31		)	—		(28		)	(28		)
Ending Balance at December 31	$	438		$	187		$	625		$	395	$	170		$	565
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	$	21		$	11		$	32		$	38	$	3		$	41

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, 2014 and 2013.

Other Postretirement Benefits

The Company participates in defined benefit plans sponsored by the LLC that provide 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 VEBA and other benefit trusts exist. The Company contributed $24 million to these trusts for its defined benefit other postretirement medical and life insurance benefit plans during 2014. At the discretion of management, the Company anticipates making up to $200 million of contributions to the trusts in 2015.

Starting in 2012, in lieu of offering future employees defined benefit post-employment health care and life insurance benefits, the Company allocates a fixed amount per year to an account in a defined contribution VEBA for each employee. These accounts 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 contributions to the VEBA for these accounts were $4 million in 2014, $2 million in 2013 and less than $1 million in 2012.

Beginning in 2013, the Company replaced the defined benefit employer-sponsored retiree medical, prescription drug and dental coverage with a notional allocation to a Retiree Reimbursement Account. This change applies to both current and future Medicare eligible non-represented and future represented retirees, spouses, surviving spouses or same sex domestic partners when the youngest of the retiree's covered household turns age 65. The amount of the annual allocation to each participant is determined by the employee's retirement date: for employees who retired on or before January 1, 2013, the base allocation is $3,500, which increased to $3,570 in 2014 and for employees who retire after January 1, 2013, the base allocation is $3,250, which increased to $3,315 in 2014. The amount of the allocation will increase each year at the lower of the rate of medical inflation or 2%.

97

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Net other postretirement cost includes the following components:

	2014			2013			2012
	(In millions)
Service cost	$	34		$	47		$	68
Interest cost	89			88			120
Expected return on plan assets	(122		)	(110		)	(92		)
Amortization of:
Net loss	20			64			80
Prior service credit	(144		)	(131		)	(25		)
Net other postretirement cost (credit)	$	(123	)	$	(42	)	$	151

	2014			2013
	(In millions)
Other changes in plan assets and APBO recognized in Regulatory assets (liabilities) and Other comprehensive income
Net actuarial (gain) loss	$	192		$	(353	)
Amortization of net actuarial loss	(20		)	(64		)
Prior service credit	—			(218		)
Amortization of prior service credit	144			131
Total recognized in Regulatory assets (liabilities) and Other comprehensive income	$	316		$	(504	)
Total recognized in net periodic benefit cost, Regulatory assets (liabilities) and Other comprehensive income	$	193		$	(546	)
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	$	43		$	21
Prior service credit	$	(126	)	$	(144	)

98

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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:

	2014			2013
	(In millions)
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation, beginning of year	$	1,878		$	2,315
Service cost	34			47
Interest cost	89			88
Plan amendments	—			(218		)
Actuarial (gain) loss	131			(267		)
Medicare Part D subsidy	—			1
Benefits paid	(88		)	(88		)
Accumulated postretirement benefit obligation, end of year	$	2,044		$	1,878
Change in plan assets
Plan assets at fair value, beginning of year	$	1,527		$	1,153
Actual return on plan assets	62			196
Company contributions	24			264
Benefits paid	(85		)	(86		)
Plan assets at fair value, end of year	$	1,528		$	1,527
Funded status, end of year	$	(516	)	$	(351	)
Amount recorded as:
Current liabilities	$	(1	)	$	(1	)
Noncurrent liabilities	(515		)	(350		)
	$	(516	)	$	(351	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	34		$	29
Prior service credit	(5		)	(10		)
	$	29		$	19
Amounts recognized in Regulatory assets (liabilities) (see Note 8)
Net actuarial loss	$	488		$	321
Prior service credit	(254		)	(393		)
	$	234		$	(72	)

At December 31, 2014, 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)
2015	$	101
2016	107
2017	111
2018	117
2019	122
2020-2024	660
Total	$	1,218

99

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

	2014	2013	2012
Accumulated postretirement benefit obligation
Discount rate	4.10%	4.95%	4.15%
Health care trend rate pre- and post- 65	7.50 / 6.50%	7.50 / 6.50%	7.00%
Ultimate health care trend rate	4.50%	4.50%	5.00%
Year in which ultimate reached pre- and post- 65	2025 / 2024	2025 / 2024	2021
Other postretirement benefit costs
Discount rate (prior to interim remeasurement)	4.95%	4.15%	5.00%
Discount rate (post interim remeasurement)	N/A	4.30%	N/A
Expected long-term rate of return on plan assets	8.00%	8.25%	8.25%
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

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 $8 million in 2014 and increased the accumulated benefit obligation by $108 million at December 31, 2014. 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 $7 million in 2014 and would have decreased the accumulated benefit obligation by $94 million at December 31, 2014.

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, 2014 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	%

100

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

Fair Value Measurements for other postretirement benefit plan assets at December 31, 2014 and 2013(a):

	December 31, 2014											December 31, 2013
	Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Asset category:	(In millions)
Short-term investments (b)	$	6		$	—		$	—	$	6		$	5	$	—	$	—	$	5
Equity securities
U.S. large cap (c)	266			—			—		266			302		—		—		302
U.S. small/mid cap (d)	149			—			—		149			147		—		—		147
Non U.S. (e)	222			59			—		281			282		9		—		291
Fixed income securities (f)	15			360			—		375			17		350		—		367
Hedge funds and similar investments (g)	107			45			168		320			130		25		159		314
Private equity and other (h)	—			—			131		131			—		—		101		101
Securities lending (i)	(141		)	(17		)	—		(158		)	—		—		—		—
Securities lending collateral (i)	141			17			—		158			—		—		—		—
Total	$	765		$	464		$	299	$	1,528		$	883	$	384	$	260	$	1,527

_______________________________________

(a) For a description of levels within the fair value hierarchy see Note 11 to the Consolidated Financial Statements, "Fair Value".

(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.

(i) In 2014, DTE Energy began a securities lending program with a third party agent. The program allows the agent to lend certain securities from the Company's VEBA trust to selected entities against receipt of collateral (in the form of cash) as provided for and determined in accordance with its securities lending agency agreement.

The VEBA 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 NAVs. 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 trustee challenges an assigned price and determines that another price source is considered to be preferable. DTE Energy has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, DTE Energy selectively corroborates the fair values of securities by comparison of market-based price sources.

101

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

	Year Ended December 31, 2014									Year Ended December 31, 2013
	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	$	159		$	101		$	260		$	119	$	86		$	205
Total realized/unrealized gains (losses)	8			9			17			14		9			23
Purchases, sales and settlements:
Purchases	9			33			42			26		15			41
Sales	(8		)	(12		)	(20		)	—		(9		)	(9		)
Ending Balance at December 31	$	168		$	131		$	299		$	159	$	101		$	260
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	$	7		$	8		$	15		$	14	$	9		$	23

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, 2014 and 2013.

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 the defined benefit employer-sponsored retiree medical, prescription drug and dental coverage for future Medicare eligible retirees and their covered dependents with an allocation to a Retiree Reimbursement Account, when the youngest of the retiree's covered household turns age 65. The amount of the allocation is $3,250 per year for each eligible participant, which increased to $3,315 in 2014. The amount of the allocation will increase each year at the lower of the rate of medical inflation or 2%. 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.

Grantor Trust

DTE Gas maintains a Grantor Trust that invests in life insurance contracts and income securities to fund other postretirement benefit obligations. 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, which approximated $18 million and $17 million at December 31, 2014 and 2013, 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 $48 million, $41 million and $37 million in each of the years 2014, 2013 and 2012, respectively.

102

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 19 — 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. 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. Key provisions of the stock incentive program are:

• Authorized limit is 14,500,000 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.

The following table summarizes the components of stock-based compensation:

	2014		2013		2012
	(In millions)
Stock-based compensation expense	$	103	$	99	$	83
Tax benefit	40		38		33
Stock-based compensation cost capitalized in property, plant and equipment	16		15		5

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.

The following table summarizes our stock option activity for the year ended December 31, 2014:

	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In millions)
Options outstanding at December 31, 2013	723,697		$	42.60
Granted	—		$	—
Exercised	(268,689	)	$	41.14
Forfeited or expired	(10,730	)	$	39.41
Options outstanding and exercisable at December 31, 2014	444,278		$	43.56	$	17

As of December 31, 2014, the weighted average remaining contractual life for the exercisable shares is 3.41 years. As of December 31, 2014, all options were vested. No options vested during 2014.

There were no options granted during 2014, 2013 or 2012. The intrinsic value of options exercised for the years ended December 31, 2014, 2013 and 2012 was $11 million, $12 million and $25 million, respectively. Total option expense recognized was zero for 2014 and 2013 and $0.7 million for 2012.

103

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

Range of Exercise Prices					Number of Options	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)
$	27.00	—	$	38.00	25,857	$	27.70	4.16
$	38.01	—	$	42.00	82,834	$	41.77	3.16
$	42.01	—	$	45.00	221,487	$	43.93	4.06
$	45.01	—	$	50.00	114,100	$	47.75	2.15
					444,278	$	43.56	3.41

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:

	2014		2013		2012
Fair value of awards vested (in millions)	$	11	$	8	$	9
Restricted common shares awarded	159,590		127,785		167,320
Weighted average market price of shares awarded	$	70.09	$	64.72	$	53.71
Compensation cost charged against income (in millions)	$	10	$	23	$	12

The following table summarizes the Company’s restricted stock awards activity for the year ended December 31, 2014:

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at December 31, 2013	492,329		$	53.76
Grants	159,590		$	70.09
Forfeitures	(16,841	)	$	62.41
Vested and issued	(218,760	)	$	47.77
Balance at December 31, 2014	416,318		$	62.82

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. Awards granted in 2014 were primarily deemed to be equity awards. The stock price and number of probable shares attributable to market conditions for such equity awards are fair valued only at the grant date. Performance shares awarded prior to 2014 are liability awards and are remeasured to fair value at each reporting period. 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.

104

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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

	2014		2013		2012
	(In millions)
Compensation expense	$	93	$	77	$	71
Cash settlements (a)	$	11	$	9	$	4
Stock settlements (a)	$	61	$	56	$	41

_______________________________________

(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, 2014:

	Performance Shares		Weighted Average Grant Date Fair Value
Balance at December 31, 2013	1,608,789		$	—
Grants	561,335		$	69.32
Forfeitures	(44,250	)	$	69.16
Payouts	(571,177	)	$	—
Balance at December 31, 2014	1,554,697		$	69.32

Unrecognized Compensation Costs

As of December 31, 2014, the total unrecognized compensation cost related to non-vested stock incentive plan arrangements and the weighted average recognition period was as follows:

	Unrecognized Compensation Cost		Weighted Average to be Recognized
	(In millions)		(In years)
Stock awards	$	10	1.06
Performance shares	48		0.98
	$	58	0.99

NOTE 20 — 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 principally of DTE Gas, which 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.

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

105

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

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 REF and sell electricity from renewable 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 are determined on an individual company basis and recognize 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:

	2014		2013			2012
	(In millions)
Electric	$	29	$	26		$	29
Gas	6		4			4
Power and Industrial Projects	794		816			801
Gas Storage and Pipelines	9		3			6
Energy Trading	33		43			43
Corporate and Other	3		(24		)	(37		)
Discontinued Operations	—		—			2
	$	874	$	868		$	848

Financial data of the business segments follows:

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Tax Expense (Benefit)			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures and Acquisitions
	(In millions)
2014
Electric	$	5,283		$	933	$	(1	)	$	250		$	296		$	528		$	18,715		$	1,208	$	1,561
Gas	1,636			99		(7		)	57			78			140			4,283			743		224
Power and Industrial Projects	2,289			77		(5		)	28			(100		)	90			1,009			26		77
Gas Storage and Pipelines	203			34		(6		)	22			53			82			884			24		184
Energy Trading	3,762			1		—			7			77			122			755			17		3
Corporate and Other	2			1		(48		)	122			(40		)	(57		)	3,209			—		—
Reclassifications and Eliminations	(874		)	—		57			(57		)	—			—			(881		)	—		—
Total	$	12,301		$	1,145	$	(10	)	$	429		$	364		$	905		$	27,974		$	2,018	$	2,049

106

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Tax Expense (Benefit)			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures and Acquisitions
	(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
Power and Industrial Projects	1,950			72		(6		)	27			(45		)	66			1,067			26		93
Gas Storage and Pipelines	132			23		(7		)	18			45			70			824			24		245
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 Tax Expense (Benefit)			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures and Acquisitions
	(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
Power and Industrial Projects	1,823			65		(7		)	37			(44		)	42			991			26		281
Gas Storage and Pipelines	96			8		(8		)	8			39			61			668			22		233
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	$	1,969
Discontinued Operations (Note 4)															(56		)	—			—		49
Total															$	610		$	26,339		$	2,018	$	2,018

107

DTE Energy Company

Notes to Consolidated Financial Statements — (Continued)

NOTE 21 — 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)
2014
Operating Revenues	$	3,930	$	2,698	$	2,595	$	3,078	$	12,301
Operating Income	$	560	$	249	$	239	$	542	$	1,590
Net Income Attributable to DTE Energy Company	$	326	$	124	$	156	$	299	$	905
Basic Earnings per Share	$	1.84	$	0.70	$	0.88	$	1.68	$	5.11
Diluted Earnings per Share	$	1.84	$	0.70	$	0.88	$	1.68	$	5.10

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

NOTE 22 — SUBSEQUENT EVENT

In October 2014, DTE Electric executed an agreement to purchase a 732 MW simple-cycle natural gas facility in Carson City, Michigan from The LS Power Group for a total purchase price of approximately $240 million paid in cash. This facility will serve to meet the needs of approximately 260,000 additional households during peak demand. DTE Electric closed on the acquisition on January 21, 2015.

Effective upon closing, DTE Electric obtained control over and applied acquisition accounting to the acquired business. Due to the limited time since the acquisition date, the initial accounting for the business combination is incomplete. As a result, DTE Electric is unable to provide amounts recognized as of the acquisition date for major classes of assets and liabilities acquired. DTE Electric will include required information in the Quarterly Report on Form 10-Q for the period ending March 31, 2015.

108

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 2015 Annual Meeting of Shareholders to be held May 7, 2015. The Proxy Statement will be filed with the SEC, 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.

109

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:
3-12	Amended and Restated Bylaws of DTE Energy Company, as amended through February 5, 2015.
4-287	Supplemental Indenture, dated as of November 1, 2014, between DTE Energy Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee. (2014 Series G due 2019)
4-288	Forty-Fifth Supplemental Indenture, dated as of December 1, 2014 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between DTE Gas Company and Citibank, N.A. (2014 First Mortgage Bonds Series F)
10-92	First Amendment to the DTE Energy Company Supplemental Retirement Plan (Amended and Restated, effective as of January 1, 2005) dated as of March 19, 2013
10-93	Second Amendment to the DTE Energy Company Supplemental Retirement Plan (Amended and Restated, effective as of January 1, 2005) dated as of November 11, 2014
12-60	Computation of Ratio of Earnings to Fixed Charges
21-10	Subsidiaries of the Company
23-28	Consent of PricewaterhouseCoopers LLP
31-95	Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report
31-96	Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Database
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

	(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).
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)

110

	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 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)
	Supplemental Indenture, dated as of December 1, 2013, between DTE Energy and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-282 to Form 10-K for the year ended December 31, 2013). (2013 Series F Senior Notes due 2023)
	Supplemental Indenture, dated as of May 1, 2014, between DTE Energy Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4-284 to Form 10-Q for the quarter ended June 30, 2014). (2014 Series C due 2024)
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)
	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)

111

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)

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 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 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 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)

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)

112

	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 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)
	Supplemental Indenture, dated as of June 1, 2014, 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 4-282 to DTE Electric's Form 10-Q for the quarter ended June 30, 2014). (2014 Series A and B)
	Supplemental Indenture, dated as of July 1, 2014, 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 4-283 to DTE Electric's Form 10-Q for the quarter ended June 30, 2014). (2014 Series D and E)
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)
	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 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)

113

	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)
	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:
	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)

114

	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-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 First Mortgage Bonds Series D)
	Forty-fourth Supplemental Indenture, dated as of December 1, 2013 to Indenture of Mortgage and Deed of Trust dated March 1, 1944 between DTE Gas Company and Citibank, N.A., (Exhibit 4-283 to Form 10-K for the year ended December 31, 2013). (2013 First Mortgage Bonds Series C, D, and E)
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).
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 Long-Term Incentive Plan (as Amended February 6, 2014) (Exhibit 10-88 to Form 10-Q for the quarter ended March 31, 2014).
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).

115

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 March 3, 2014, between DTE Energy Company and each of Gerard M. Anderson, Steven E. Kurmas, David E. Meador, Peter B. Oleksiak, Gerardo Norcia, Bruce D. Peterson and Larry E. Steward (Exhibit 10.1 to Form 8-K filed on March 3, 2014)
10(w)	Form of Change-In-Control Severance Agreement dated as of July 1, 2014, between DTE Energy Company and each of Donna M. England and Lisa A. Muschong (Exhibit 10-90 to Form 10-Q for the quarter ended June 30, 2014).
10(x)	Form of Change-In-Control Severance Agreement dated as of July 1, 2014, between DTE Energy Company and each of Naif A. Khouri, David Ruud and Mark W. Stiers (Exhibit 10-91 to Form 10-Q for the quarter ended June 30, 2014).

116

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 (Exhibit 99-54 to Form 10-K for the year ended December 31, 2010).
	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 (Exhibit 99-55 to Form 10-K for the year end December 13, 2013).
	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 (Exhibit 99-56 to Form 10-K for the year ended December 31, 2013).
	Third 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 October 3, 2014 (Exhibit 99-57 to Form 10-Q for the quarter ended September 30, 2014).
	(iii) Exhibits furnished herewith:
32-95	Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report
32-96	Chief Financial Officer Section 906 Form 10-K Certification of Periodic Report

117

DTE Energy Company

Schedule II — Valuation and Qualifying Accounts

	Year Ending December 31,
	2014			2013			2012
	(In millions)
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statements of Financial Position)
Balance at Beginning of Period	$	55		$	62		$	162
Additions:
Charged to costs and expenses	95			94			79
Charged to other accounts (a)	20			23			16
Deductions (b)	(116		)	(124		)	(195		)
Balance at End of Period	$	54		$	55		$	62

_______________________________________

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

118

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 13, 2015

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 13, 2015

119

EX-3.12

EXHIBIT 3-12

AMENDED BYLAWS

of

DTE ENERGY COMPANY

As amended through February 5, 2015

AMENDED BYLAWS

of

DTE ENERGY COMPANY

INDEX

Page

ARTICLE I. Shareholders............................................................................................................. 1

ARTICLE II. Board of Directors and Committees........................................................................ 7

ARTICLE III. Officers...................................................................................................................10

ARTICLE IV. Capital Stock........................................................................................................... 12

ARTICLE V. Delivery of Notices................................................................................................... 13

ARTICLE VI. Checks, Notes, Bonds, Debentures, etc...................................................................13

ARTICLE VII. Corporate Seal........................................................................................................ 14

ARTICLE VIII. Control Share Acquisitions................................................................................... 14

ARTICLE IX. Amendment of Bylaws............................................................................................14

AMENDED BYLAWS

of

DTE ENERGY COMPANY

As amended through February 5, 2015

ARTICLE I.

Shareholders

Section 1.    Annual Meeting. The annual meeting of the shareholders of the Company shall be held on such date and at such time and place as may be fixed by the Board of Directors and stated in the notice of meeting, for the purpose of electing directors and such other purpose or purposes as may be stated in the notice of meeting.

Section 2.    Special Meetings.

(a)    Special meetings of the shareholders may be called (i) by the Board of Directors, the Chairman of the Board or the Presiding Director, if one has been designated, or (ii) by the Corporate Secretary at the written request of one or more shareholders of record who have continuously held for a minimum of one full year prior to the date such request is delivered to the Corporate Secretary shares of common stock of the Company representing in the aggregate at least twenty-five percent (25%) (the “Requisite Percentage”) of the outstanding shares of stock of the Company entitled to vote at such meeting, on such date and at such time and place as may designated and for such purpose or purposes as set forth in the notice of meeting.

(b)    A request for a shareholder requested special meeting must be signed by the holders of the Requisite Percentage (or their authorized agents) and be delivered to the Corporate Secretary at the principal executive offices of the Company by registered mail, return receipt requested or by a nationally recognized private overnight courier service, return receipt requested.

(c)    To be in proper form and valid, a request for a shareholder requested special meeting shall (1) set forth a statement of the specific purpose or purposes of the meeting and the matters proposed to be acted on at such special meeting (including the text of any resolutions proposed for consideration and, if such business includes a proposal to amend the Bylaws, the language of the proposed amendment), (2) bear the date of signature of each shareholder (or authorized agent) signing the request, (3) set forth (w) the name and address, as they appear in the Company’s books, of each shareholder signing such request (or on whose behalf the request is signed), (x) the number of shares that are held of record or are beneficially owned, directly or indirectly, by such shareholder, (y) include documentary evidence that the shareholders held the Requisite Percentage as of the request date and for a minimum of one full year prior to the request date, provided that if any of the shareholders are not the beneficial owners of the shares representing the Requisite Percentage, then to be valid, the request must also include documentary evidence (or, if not simultaneously provided with the request, such documentary evidence must be delivered to the Corporate Secretary within ten (10) days after the request date) that the beneficial owners on whose behalf the request is made held, together with any requesting shareholders who are beneficial owners, the Requisite Percentage as of the request date and for a minimum of one full year prior to the request date and (z) a certification from the shareholder submitting the request that the shareholders signing the request in the aggregate satisfy the Requisite Percentage, (4) describe any material interest of each such shareholder in the specific purpose or purposes of the meeting, (5) contain any other information that would be required to be provided by a shareholder seeking to nominate directors or bring

an item of business before an annual meeting of shareholders pursuant to Section 10 of this Article, (6) include an acknowledgment by each shareholder and any authorized agent that any reduction in shares owned by such shareholder as of the date of delivery of the special meeting request and prior to the record date for the proposed meeting requested by such shareholder shall constitute a revocation of such request to the extent of such reduction, and (7) include an agreement by each shareholder and any authorized agent to update and supplement the information previously provided to the Company in connection with such request, not later than ten (10) business days after the record date for notice of the Shareholder requested special meeting. In addition, the shareholders and any of their authorized agents shall promptly provide any other information reasonably requested by the Company.

(d)    The Company will provide the requesting shareholders with notice of the record date for the determination of shareholders entitled to vote at the shareholder requested special meeting in the manner described in Section 7 of this Article.

(e)    Any requesting shareholder may revoke a request for a special meeting at any time by written revocation delivered to the Corporate Secretary at the principal executive offices of the Company. If, following such revocation (including any revocation resulting from a disposition of shares) at any time before the date of the shareholder requested special meeting, the remaining unrevoked requests are from shareholders holding in the aggregate less than the Requisite Percentage, the Board of Directors, in its discretion, may cancel the shareholder requested special meeting.

(f)    Notwithstanding the foregoing, a special meeting request shall not be valid, and the Corporate Secretary shall not be required to call the shareholder requested special meeting if (1) the request for such special meeting does not comply with this Section 2, (2) the Board of Directors, the Chairman of the Board or the Presiding Director has called or calls an annual or special meeting of shareholders to be held not later than ninety (90) days after the date on which a valid request has been delivered to the Corporate Secretary (the “Delivery Date”) and the Board of Directors determines in good faith that the business of such meeting includes (among any other matters properly brought before the meeting) an identical or substantially similar item of business (a “Similar Item”) specified in the shareholder’s request, (3) the request is received by the Corporate Secretary during the period commencing ninety (90) days prior to the first anniversary of the date of the immediately preceding annual meeting and ending on the date of the next annual meeting, (4) if two or more special meetings have been called at the request of shareholders and convened within the 12-month period ending on the Delivery Date, (5) the request contains a Similar Item to an item that was presented at any meeting of shareholders held within one hundred and twenty (120) days prior to the Delivery Date, (6) the request relates to an item of business that is not a proper subject for action by the shareholders of the Company under applicable law or (7) the request was made in a manner that involved a violation of Regulation 14A under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) or other applicable law. The Board of Directors shall determine in good faith whether the requirements set forth in this Section 2 have been satisfied and such determination shall be binding on the Company and its shareholders.

(g)    If a valid special meeting request has been made, the shareholder requested special meeting shall be held at such date, time and place as the Board of Directors shall fix; provided, however, that the date of any such special meeting shall be not more than 120 days after the special meeting request is delivered to the Corporate Secretary.

(h)    Business transacted at any shareholder requested special meeting shall be limited to the purpose(s) stated in a valid special meeting request for such meeting; provided, however, that nothing

herein shall prohibit the Company from submitting matters to a vote of the shareholders at any shareholder requested special meeting.

(i)    If none of the Shareholders who submitted the request for a Shareholder requested special meeting appears or sends a qualified representative to present the matters to be presented for consideration that were specified in the special meeting request, the Company need not present such matters for a vote at such meeting, notwithstanding that proxies in respect of such matter may have been received by the Company.

Section 3.    Notice of Meetings. Written notice or notice by electronic transmission of the date, time, place and purpose or purposes the meeting and the matters proposed to be acted on at such meeting of the shareholders shall be given in the manner described in Article V. If a shareholder or proxy holder may be present and vote at a meeting by remote communication, the means of remote communication allowed shall be included in the notice. Notice of a special meeting shall also indicate that it is being issued by or at the direction of the Board of Directors, the Chairman of the Board, the Presiding Director, if one has been designated, or the holders of Requisite Percentage of the outstanding shares of stock of the Company.

Notice of a meeting need not be given to any shareholder who submits a signed waiver of notice, in person or by proxy, or a waiver of notice by electronic transmission, whether before or after the meeting. The attendance of any shareholder at a meeting, in person or by proxy, will result in both of the following:

(a)    Waiver of objection to lack of notice or defective notice of the meeting, unless the shareholder at the beginning of the meeting objects to holding the meeting or transacting business at the meeting; and

(b)    Waiver of objection to consideration of a particular matter at the meeting that is not within the purpose or purposes described in the meeting notice, unless the shareholder objects to considering the matter when it is presented.

Section 4.    Adjournments. Any meeting of shareholders, annual or special, may adjourn from time to time to reconvene at the same or some other place. Notice need not be given of any adjourned meeting if the new date, time and place of the meeting are announced at the meeting at which the adjournment is taken. A shareholder or proxy holder may be present and vote at the adjourned meeting by means of remote communication if he or she were permitted to be present and vote by that means of remote communication in the original meeting notice. If a notice of the adjourned meeting is not given, the Company may only transact business that might have been transacted at the original meeting. If, after the adjournment, the Board of Directors fixes a new record date for the adjourned meeting, a notice of the adjourned meeting shall be given to each shareholder entitled to notice under these Bylaws as of the new record date.

Section 5.    Quorum. Unless otherwise provided by law, the Articles of Incorporation or these Bylaws, the holders of a majority of the outstanding shares of stock of the Company entitled to vote at such meeting, whether present in person or by proxy, shall constitute a quorum at any meeting of shareholders. If at any meeting there shall be no quorum, the holders of a majority of the outstanding shares of stock so present or represented shall have the power to adjourn the meeting, without notice other than announcement at the meeting of the new meeting time and place, until a quorum has been obtained. When a quorum is present, the shareholders present in person or by proxy at such meeting may continue

to do business until adjournment, notwithstanding the withdrawal of enough shareholders to leave less than a quorum.

Section 6.    Voting. Except as otherwise provided in the Articles of Incorporation, each outstanding share of capital stock shall be entitled to one vote on each matter submitted to a vote. Votes may be cast orally, in writing or by any other means permitted under Michigan law, as the chair of the meeting may decide. All voting may be done either in person or by proxy appointed by instrument in writing or by electronic means (telephone or internet), signed, or identified by the shareholder’s identification number or other unique identifier that is reasonably designed to ensure authenticity by such shareholder or his or her authorized agent. When a quorum is present:

(a)    Action on a matter is approved if the votes properly cast favoring the action exceed the votes properly cast opposing the action, unless the action is the election of directors, or is one upon which by express provision of law, the Articles of Incorporation or these Bylaws, a larger or different vote is required; and

(b)    Each director shall be elected by a majority of votes properly cast at any meeting of shareholders for the election of directors. However, if the number of director nominees for any director election exceeds the number of directors to be elected (a “Contested Election”), the nominees receiving a plurality of the votes cast by holders of the shares entitled to vote at any meeting for the election of directors at which a quorum is present will be elected. For purposes of this Section 6(b) of Article I, a majority of the votes properly cast means that the number of shares properly voted “for” a director must exceed fifty percent (50%) of the votes properly cast with respect to that director. The votes cast shall exclude abstentions with respect to that director’s election.

Section 7.    Record of Shareholders. For the purpose of determining the shareholders entitled (a) to notice of, or to vote at, any meeting of shareholders or any adjournment thereof, (b) to express consent to, or dissent from, any proposal without a meeting, or (c) to receive payment of any dividend or the allotment of any rights, or for the purpose of any other action, the Board of Directors may fix, in advance, a date as the record date for any such determination of shareholders. The record date shall not precede the date upon which it is fixed and shall not be less than 10 days nor more than 60 days before the date of the meeting, or the taking of any other action. A determination of shareholders of record entitled to notice of or to vote at a meeting of shareholders shall apply to any adjournment of the meeting, unless the Board of Directors chooses to fix a new record date for the adjourned meeting.

Section 8.    List of Shareholders. The Corporate Secretary shall prepare or have prepared before every meeting of shareholders a complete list of shareholders entitled to vote at the meeting in compliance with Michigan law.

Section 9.    Order of Business. At each meeting of shareholders, a chair shall preside. In the absence of a specific selection by the Board of Directors, the chair shall be the Chairman of the Board as provided in these Bylaws. The chair shall determine the order of business and shall have the authority in his or her sole discretion to regulate the conduct of any such meeting including, without limitation, by imposing restrictions on the persons (other than shareholders of the Company or their duly appointed proxies) who may attend any such shareholders’ meeting, by ascertaining whether any shareholder or his proxy may be excluded from any meeting of shareholders based upon any determination by the chair in his or her sole discretion, that any such person has unduly disrupted or is likely to disrupt the proceedings of the meeting, and by determining the circumstances in which any person may make a statement or ask questions at any meeting of shareholders. The chair of the meeting shall announce at the meeting when the polls close for each matter voted upon. If no announcement is made, the polls shall be deemed to have

closed upon the final adjournment of the meeting. After the polls close, no ballots, proxies or votes, nor any revocations or changes thereto may be accepted.

Section 10.    Director Nominations and Shareholder Business.

(a)    Annual Shareholder Meeting. At an annual meeting of shareholders, only such business will be conducted or considered as is properly brought before the meeting. To be properly brought before an annual meeting:

(i)    Nominations of persons for election as directors may be made only at an annual meeting (1) by or at the direction of the Board of Directors or a committee thereof, or (2) by any shareholder who is a shareholder of record at the time of giving notice, who is entitled to vote at the annual meeting and who complies with the notice requirements set forth in this Section.

(ii)    Other business to be considered at an annual meeting shall be: (1) specified in the notice of meeting (or any supplement thereto) given by or at the direction of the Board of Directors, Chairman of the Board, the President, a Vice President, the Corporate Secretary or an Assistant Corporate Secretary; (2) brought by or at the direction of the Board of Directors; or (3) properly requested by a shareholder of the Company in accordance with the law and with the notice requirements provided in this Section.

(b)    A shareholder who intends to make a director nomination or to bring any other matter before an annual meeting must give notice of his or her intent in writing to the Corporate Secretary. A shareholder’s notice must be received at the principal executive offices of the Company not less than 60 nor more than 90 calendar days prior to the annual meeting of shareholders. If the Company does not make a public announcement of an annual meeting date at least 70 calendar days prior to the date of the annual meeting, a shareholder’s notice must be received at the principal executive offices of the Company by the close of business on the 10th day following the Company’s first public announcement of the annual meeting date.

(c)    All shareholder notices must include:

(i)    the name and address, as they appear on the Company books, of the shareholder making the nomination or proposing the shareholder business, along with the class and number of shares of Company stock owned by the shareholder;

(ii)    a representation that the shareholder is a shareholder of record of Company stock entitled to vote at such annual meeting and intends to appear in person or by proxy at the annual meeting to make the nomination or propose the business specified in the notice;

(iii)    if the shareholder notice is to bring a matter up for vote at a shareholder meeting, (1) a description in reasonable detail of the business desired to be brought before the annual meeting, (2) the reasons for conducting such business at the annual meeting, (3) any material interest the shareholder has in the matter, and (4) compliance with all applicable requirements of the Securities Exchange Act of 1934, as amended (the “Act”), for shareholder proposals, including matters covered by Rule 14a-8;

(iv)    if a shareholder notice is to nominate a person for election as a director, a description of all arrangements or understandings between or among any of (1) the shareholder giving the

notice, (2) the beneficial owner on whose behalf the notice is given, (3) each nominee, and (4) any other person or person (naming such person or persons) pursuant to which the nomination is to be made by the shareholder giving the notice; and

(v)    if a shareholder notice is to nominate a person for election as a director, the information that would be required to be disclosed in a proxy statement to comply with all applicable requirements of the Act and the rules and regulations thereunder as if each nominee had been nominated by the Board.

Any shareholder notice to nominate a person for the election as a director must be accompanied by a written and signed consent of each nominee to serve as a director of the Company if elected.

Section 11.    Inspectors.

In advance of any meeting of shareholders, the Board of Directors may appoint one or more inspectors for the meeting. If inspectors are not so appointed, the chair of the meeting may appoint such inspectors. No officer or director of the Company or candidate for director shall be appointed as an inspector.

ARTICLE II.

Board of Directors and Committees

Section 1.    Number and Time of Holding Office. The business and affairs of the Company shall be managed by or under the direction of a Board of Directors. The number of directors constituting the entire Board of Directors shall be determined from time to time by resolution of the Board of Directors; provided that no change in the number of directors shall serve to shorten the term of office of any incumbent director. Commencing with the 2012 annual meeting of shareholders and for each annual meeting of shareholders thereafter, directors whose terms are expiring at an annual meeting of shareholders shall be elected for terms of one year; for the avoidance of doubt, each director whose term of office for which he or she was elected has not expired as of the 2012 annual meeting of shareholders shall continue to hold office until such time as his or her term has expired. If at any time the holders of any series of the Company's Preferred Stock are entitled to elect directors pursuant to the Articles of Incorporation of the Company, then the provisions of such series of Preferred Stock with respect to their rights shall apply and such directors shall be elected in a manner and for terms expiring consistent with the Articles of Incorporation.

Each director shall serve for the term to which the director was elected, and until a successor shall have been elected and qualified or until the director’s prior death, resignation, or removal. Except for the Chief Executive Officer of the Company, no person who has served as an employee of the Company or a subsidiary shall be elected a director after retiring from employment with the Company or a subsidiary.

Section 2.    Vacancies. Any vacancy in the Board of Directors may be filled by a majority vote of the remaining members of the Board of Directors then in office (even if constituting less than a quorum). Each person elected by the Board of Directors to fill a director vacancy shall be subject to election by a vote of the shareholders at the next annual shareholder meeting. During the existence of any vacancy, the remaining directors shall possess and may exercise all the powers of the full Board of Directors, unless otherwise required by law or these Bylaws.

Section 3.    Meetings of the Board.

(a)    Annual Meetings. An annual meeting of the Board of Directors shall be held without notice each year as soon as practicable after the adjournment of the annual meeting of shareholders for the purpose of election of officers and consideration of such business that may properly be brought before the meeting. If there is less than a quorum at the annual meeting of the Board of Directors, the meeting shall be adjourned and the matters which might have been taken up at the annual meeting may be taken up at any later special or annual meeting, or by consent resolution.

(b)    Regular Meetings. Regular meetings of the Board of Directors shall be held at such times and at such places as may from time to time be fixed by the Board of Directors.

(c)    Special Meetings. Special meetings of the Board of Directors may be called by the Chairman of the Board, the Presiding Director, if one has been designated, or, during the absence or incapacity of the Chairman of the Board or any designated Presiding Director, special meetings may be called by the Executive Committee, if one has been designated, by giving reasonable notice of the time and place of such meetings or by obtaining waivers of notice either signed or received by electronic transmission, before or after the meeting, from each absent director. A director’s attendance at or participation in any meeting of the Board of Directors or a committee waives any required notice to him or her of the meeting unless he or she, at the beginning of the meeting or upon his or her arrival, objects to

the meeting or the transacting of business at the meeting and does not thereafter vote for or assent to any action taken at the meeting.

(d)    A director may participate in a meeting by means of remote communications where all persons participating in the meeting can communicate with each other. Such participation shall constitute attendance at any meeting.

(e)    Neither the business to be transacted at, nor the purpose of, any regular or special meeting of the Board of Directors need be specified in the notice or waiver of notice of such meeting.

Section 4.    Quorum. A majority of the directors in office at the time of a meeting of the Board of Directors shall constitute a quorum for the transaction of business. If at any meeting of the Board of Directors there shall be less than a quorum present, a majority of the directors present may adjourn the meeting without notice other than announcement at the meeting of the new meeting time and place, until a quorum has been obtained. The acts of a majority of the directors present at any meeting at which there is a quorum shall be the acts of the Board of Directors, unless otherwise provided by law, by the Articles of Incorporation or by these Bylaws.

Section 5.    Chairman of the Board. From its members, the Board of Directors shall annually elect a Chairman of the Board. The Chairman of the Board may simultaneously serve as the Chief Executive Officer. Subject to Article I Section 9 and Article II Section 6, the Chairman of the Board shall preside at meetings of the Board of Directors and meetings of shareholders at which the Chairman of the Board is present.

Section 6.    Presiding Director. If the Chairman of the Board is not an independent director, the Board of Directors may elect a Presiding Director from among its members other than the Chairman of the Board. The Presiding Director shall have such authority and powers as the Board of Directors may from time to time prescribe.

Section 7.    Committees.

(a)    Executive Committee. The Board of Directors may, by resolution passed by a majority of the Board of Directors, designate an Executive Committee to consist of the Chairman of the Board, the Presiding Director, if one has been designated, and one or more of the other directors, and alternates, and shall designate the chair of the Executive Committee. Meetings of the Executive Committee may be called by the Chairman of the Board, or, in the event of the incapacity or absence of the Chairman of the Board, the Presiding Director, if one has been designated, or, in the incapacity or absence of the Chairman of the Board and of any designated Presiding Director, meetings may be called by one or more members of the Executive Committee by giving reasonable notice of the time and place of such meetings. The Executive Committee shall have and may exercise, when the Board of Directors is not in session, all of the powers of the Board of Directors in the management of the business and affairs of the Company, and shall have the power to authorize the seal of the Company to be affixed to all papers which may require it. The Executive Committee may make rules for the conduct of its business and may appoint such subcommittees and assistants, as it shall from time to time deem necessary. All action taken by the Executive Committee shall be reported to the Board of Directors at its next meeting succeeding such action. The Corporate Secretary or an Assistant Corporate Secretary shall attend and act as the secretary of all meetings of the Executive Committee and keep the minutes thereof.

(b)    Other Committees. The Board of Directors may, by resolution, appoint such other committees consisting of one or more directors, and alternates, and shall designate the chair of each such committee. Committees other than the Executive Committee shall have such authority as shall be specified by the Board of Directors in the resolution making such appointments.

(c)    The Board of Directors may designate one or more directors as alternate members of any committee who may replace an absent or disqualified member at any meeting of the committee. The Board shall have the power at any time to fill vacancies in, to change the membership of, or to dissolve any committee. A majority of the authorized number of members of any such committee shall constitute a quorum for the transaction of business, and the act of a majority of those present at any meeting at which a quorum is present shall be the act of such committee. Committees and each member shall serve at the pleasure of the Board.

(d)    Notwithstanding the foregoing, no committee of the Board shall have the power or authority to:

(i)    amend the Articles of Incorporation, except that a committee may prescribe the relative rights and preferences of the shares of a series if the Articles of Incorporation authorize the Board of Directors to do so;

(ii)    adopt an agreement of merger or plan of share exchange;

(iii)    recommend to shareholders the sale, lease or exchange of all or substantially all of the Company’s property and assets;

(iv)    recommend to shareholders a dissolution of the Company or revocation of a dissolution;

(v)    amend these Bylaws;

(vi)    fill vacancies in the Board of Directors; or

(vii)    unless expressly authorized by the Board of Directors, declare a dividend or authorize the issuance of stock.

Section 8.    Action by Consent. Any action required or permitted at any meeting of directors or committee of directors may be taken without a meeting, without prior notice and without a vote, if all of the directors or committee members entitled to vote on the action consent to the action in writing or by electronic transmission, before or after the action is taken. Such consents shall be filed with the minutes of the proceedings of the Board of Directors or committee and shall have the same effect as a vote of the Board of Directors or committee for all purposes.

Section 9.    Compensation. Each director of the Company who is not a salaried officer or employee of the Company may receive reasonable compensation for services as a director, including a reasonable fee for attendance at meetings of the Board of Directors and committees thereof, service as a committee chair or as Presiding Director and attendance at the Company's request at other meetings or similar activities related to the Company.

ARTICLE III.

Officers

Section 1.Officers and Agents. The officers of the Company shall be a President, a Corporate Secretary and a Treasurer. The Board of Directors may also, from time to time, elect a Chief Executive Officer and one or more Vice Presidents, a Controller, a General Auditor, a General Counsel and such other officers and agents, as it may deem proper or advisable in the conduct of the affairs of the Company. The Board of Directors may, in its discretion, leave vacant any office other than that of the President, Corporate Secretary, or Treasurer. Except as otherwise provided by law, the Articles of Incorporation or these Bylaws, one person may hold any number of offices.

Section 2.Term of Office. The term of office of all officers shall be until the next annual meeting of the Board of Directors or until the officers’ respective successors are chosen and qualified. Any officer or agent elected by the Board of Directors may be removed by the Board at any time, with or without cause.

Section 3.Chief Executive Officer. The Chief Executive Officer of the Company shall have general charge of the business and affairs of the Company, subject to the control of the Board of Directors, may create in the name of the Company corporate obligations or other instruments and shall perform such other functions and acts as may be incident to the office of Chief Executive Officer or prescribed by the Board of Directors from time to time. The Chief Executive Officer may also simultaneously serve as the Chairman of the Board.

The Chief Executive Officer shall manage or supervise the conduct of the corporate finances and relations of the Company with its shareholders, with the public, and with regulatory authorities, and may exercise all powers conferred upon the President elsewhere in the Bylaws. The Chief Executive Officer may delegate from time to time to other officers, employees or positions of the Company, such powers as the Chief Executive Officer may specify in writing. A copy of each such delegation and of any revocation or change shall be filed with the Corporate Secretary.

Section 4.President. The President shall have the power and authority, subject to the control of the Board of Directors and the Chief Executive Officer, if one has been appointed, to perform all acts incident to the President’s office or prescribed by the Board of Directors or the Chief Executive Officer, or authorized or required by law. During the absence or disability of the Chief Executive Officer, if one has been elected, the President shall assume the duties and authority of the Chief Executive Officer of the Company.

Section 5.Other Officers. The other officers, agents, and employees of the Company shall each have such powers and authority to perform such duties in the management of the property and affairs of the Company, subject to the control of the Board of Directors, as generally pertain to their respective offices, as well as such powers and duties that, from time to time, may be prescribed by the Board of Directors, by the Chief Executive Officer, or by the President, as the case may be.

Section 6.Compensation. The compensation of all executive officers of the Company above the level of Assistant Vice President (or equivalent) and the General Auditor (whether or not he or she is above the level of Assistant Vice President) shall be fixed by the Board of Directors or by an authorized committee of the Board of Directors.

Section 7.Voting of Shares and Securities of Other Corporations. Unless the Board of Directors otherwise directs, the Company’s Chairman of the Board, Chief Executive Officer, President, Corporate Secretary and Assistant Corporate Secretary shall each be authorized to vote or to designate a proxy to vote all shares and other securities that the Company owns in any other corporation or entity.

ARTICLE IV.

Capital Stock

Section 1.Certificates of Shares. Shares of the Company’s stock may be certificated or uncertificated, as provided under Michigan law at any time. The certificated shares shall be represented by certificates signed by the Chairman of the Board, the President or a Vice President and may also be signed by the Treasurer, an Assistant Treasurer, the Corporate Secretary or an Assistant Corporate Secretary of the Company, and shall be countersigned by a transfer agent for the stock and registered by a registrar for such stock. The signatures of the officers and the transfer agent and the registrar upon such certificates may be facsimiles, engraved, or printed, subject to the provisions of applicable law. In case any officer, transfer agent, or registrar shall cease to serve in that capacity after their facsimile signature has been placed on a certificate, the certificates may be issued with the same effect as if the officer, transfer agent, or registrar were still in office. A certificate representing shares shall state on its face that the Company is formed under the laws of the State of Michigan and shall also state the name of the person to whom it is issued, the number and class of shares and the designation of the series, if any, that the certificate represents, and any other provisions that may be required by the laws of the State of Michigan or by federal law or by the rules or regulations of any stock exchange or other organization applicable to the Company.

Section 2.Uncertificated Shares. The Board of Directors may authorize, by resolution, the issuance of some or all of the shares of any class or series without certificates. The authorization will not affect shares already represented by certificates until the certificates are surrendered to the Company. Within a reasonable time after the issuance or transfer of shares without certificates, the Company shall send the shareholder a written statement of the information required on certificates by applicable law, rule or regulation.

Section 3.Transfer of Shares. The Company shall make transfers of stock on the Company’s books (a) upon the presentation of the certificates by the registered holder in person or by duly authorized agent or attorney, or upon presentation of proper evidence of succession, assignment or authority to transfer the stock and upon surrender of the appropriate certificates, or (b) in the case of uncertificated shares, upon receipt of proper transfer instructions from the registered owner of such uncertificated shares, or from a duly authorized agent or attorney or from an individual presenting proper evidence of succession, assignment or authority to transfer the stock.

Section 4.Lost or Destroyed Stock Certificates. No certificate for shares of stock of the Company shall be issued in place of any certificate alleged to have been lost, stolen or destroyed, except upon production of such evidence of the loss, theft or destruction, and upon indemnification of the Company and its agents to such extent and in such manner as the Board of Directors may from time to time prescribe.

ARTICLE V.

Delivery of Notices

All notices to shareholders, directors and Board committee members shall be given (a) personally, (b) by mail (as provided in the Michigan Business Corporation Act, with postage pre‑paid), and addressed to such person at the address designated by him or her for that purpose, or, if none is designated, at his or her last known address, (c) by electronic transmission in a manner authorized by the person, or (d) as otherwise provided in the Michigan Business Corporation Act. In addition to any other form of notice to a shareholder permitted by the Articles of Incorporation, these Bylaws, or the Michigan Business Corporation Act, any notice given to a shareholder by a form of electronic transmission to which the shareholder has consented is effective. When a notice is required or permitted by the Michigan Business Corporation Act or these Bylaws to be given in writing, electronic transmission is written notice. Notices given pursuant to this Article V shall be deemed to be given when dispatched, or, if mailed, when deposited, with postage prepaid, in a post office or official depository under the exclusive care and custody of the United States Postal Service; provided that when a notice or communication is permitted by the Michigan Business Corporation Act or these Bylaws to be transmitted electronically, the notice or communication is given when electronically transmitted to the person entitled to the notice or communication in a manner authorized by the person. Further notice shall be given by mail, publication, electronic transmission, or otherwise, if and as required by law.

ARTICLE VI.

Checks, Notes, Bonds, Debentures, etc.

All checks and drafts on the Company’s bank accounts, all bills of exchange and promissory notes, and all acceptances, obligations, and other instruments for the payment of money, shall be signed by such officer or officers or agent or agents, either manually or by facsimile signature or signatures, as shall be thereunto authorized from time to time by the Board of Directors either generally or in specific instances; provided that bonds, debentures, and other evidences of indebtedness of the Company bearing facsimile signatures of officers of the Company shall be issued only when authenticated by a manual signature on behalf of a trustee or an authenticating agent appointed by the Board of Directors. In case any such officer of the Company shall cease to be such after such officer’s facsimile signature has been placed on the document, such bonds, debentures or other evidences of indebtedness may be issued with the same effect as if such person were still in office.

ARTICLE VII.

Corporate Seal

The Board of Directors may provide a suitable seal containing the name of the Company.

ARTICLE VIII.

Control Share Acquisitions

The Stacey, Bennett, and Randall Shareholder Equity Act (Chapter 7B of the Michigan Business Corporation Act) shall not apply to any control share acquisitions (as defined in such Act) of shares of the Company.

This Article VIII of the Bylaws may not be amended, altered, or repealed with respect to any control share acquisition of shares of the Company effected pursuant to a tender offer or other transaction commenced prior to the date of such amendment, alteration, or repeal.

ARTICLE IX.

Amendment of Bylaws

The Bylaws of the Company may be amended, repealed or adopted by vote of the holders of a majority of shares at the time entitled to vote in the election of any directors or by vote of a majority of the directors in office.

EX-4.287

EXHIBIT 4-287

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

__________________________

SUPPLEMENTAL INDENTURE
DATED AS OF NOVEMBER 1, 2014

__________________________

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

PROVIDING FOR

2014 SERIES G 2.40% SENIOR NOTES DUE 2019

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SUPPLEMENTAL INDENTURE, dated as of the 1st day of November, 2014, 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 “2014 Series G 2.40% Senior Notes due 2019”; 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 state of New York or the state of Michigan are required or authorized by law or executive order to be closed.

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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 “2014 Series G 2.40% Senior Notes due 2019” (the “Notes”). The Stated Maturity on which the principal of the Notes shall be due and payable will be December 1, 2019.

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

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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 2.40% per annum on the principal amount thereof from November 24, 2014, 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 December 1 and June 1 of each year (each such date, an “Interest Payment Date”), commencing June 1, 2015. 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.

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(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.

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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:/s/ MARK C. ROLLING

Name:     Mark C. Rolling

Title:      Vice President and Treasurer

ATTEST:

By:/s/ LISA A. MUSCHONG

Name: Lisa A. Muschong

Title:      Corporate Secretary

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

By:     /s/ RICHARD TARNAS

Name:    Richard Tarnas

Title: Vice President

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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
2014 SERIES G 2.40% SENIOR NOTES DUE 2019

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, 2019 (“Stated Maturity” with respect to the principal of this Note), unless previously redeemed, and to pay interest at the rate of 2.40% per annum on said principal sum from November 24, 2014 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 December 1 and June 1 of each year (each such date, an “Interest Payment Date”), commencing June 1, 2015. 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

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“Business Day” means any day other than a Saturday or Sunday or a day on which commercial 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 “2014 Series G 2.40% Senior Notes due 2019” (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, 2014 (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.

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At any time prior to November 1, 2019, the optional redemption price (which shall be a “Redemption 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 15 basis points, as determined by the Quotation Agent (as defined below), plus in either case, accrued interest thereon to the date of redemption. At any time on or after November 1, 2019, 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 Quotation Agent 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 Quotation Agent 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.

“Quotation Agent” means one of the Reference Treasury Dealers appointed by the Company.

“Reference Treasury Dealer” means: (i) each of J.P. Morgan Securities LLC, RBS Securities Inc. and UBS Securities LLC (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 Company.

“Reference Treasury Dealer Quotation” means, with respect to each Reference Treasury Dealer and any Optional Redemption Date, the average, as determined by the Quotation Agent, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage

A-3

of its principal amount) quoted in writing to the Quotation Agent by such Reference Treasury Dealer at 5:00 p.m., New York City time, on the third Business Day preceding such Optional Redemption Date.

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

A-4

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 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

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the principal of or premium, if any, or any interest on this Note on or after the respective due dates expressed herein.

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: November __, 2014

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: November ____, 2014

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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-4.288

EXHIBIT 4-288

FORTY-FIFTH

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, 2014

CREATING AN ISSUE OF FIRST MORTGAGE BONDS,

DESIGNATED AS

2014 SERIES F BONDS

DTE GAS COMPANY

FORTY-FIFTH SUPPLEMENTAL INDENTURE

DATED AS OF DECEMBER 1, 2014

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 “2014 SERIES f BONDS”    5

SECTION 15

SECTION 25

SECTION 37

SECTION 414

SECTION 516

ARTICLE II ISSUE OF BONDS    16

ARTICLE III THE TRUSTEE    17

ARTICLE IV RECORDING AND FILING OF SUPPLEMENTAL INDENTURE DATED AS OF DECEMBER 1, 2013    17

ARTICLE V RECORDING OF AFFIDAVIT OF FACTS AFFECTING REAL PROPERTY    19

ARTICLE VI MISCELLANEOUS PROVISIONS    19

THIS FORTY-FIFTH SUPPLEMENTAL INDENTURE, dated as of the 1st day of December, 2014, 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;

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

Forty-fourth Supplemental Indenture, dated as of December 1, 2013;

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WHEREAS, at the date hereof there were outstanding First Mortgage Bonds of the Company issued under the Indenture, of 11 series in the principal amounts set forth below (including Collateral Bonds):

Designation of Series	Amount Initially Issued		AmountOutstanding
First Mortgage Bonds
2012 Series D First Mortgage Bonds		$70,000,000		$70,000,000
2013 Series C First Mortgage Bonds		$50,000,000		$50,000,000
2013 Series D First Mortgage Bonds		$70,000,000		$70,000,000
2013 Series E First Mortgage Bonds		$50,000,000		$50,000,000
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

WHEREAS, the Company desires in and by this Supplemental Indenture to establish a series of bonds to be issued under the Indenture designated and distinguished as 2014 Series F Bonds (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;

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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-fifth 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:

ARTICLE I ESTABLISHMENT OF AN ISSUE OF
FIRST MORTGAGE BONDS, OF THE SERIES
DESIGNATED AND DISTINGUISHED AS “2014 SERIES F 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 “2014 Series F Bonds” of the Company. The 2014 Series F Bonds shall be limited in aggregate principal amount to $150,000,000 except as provided in Article II of the Indenture and in this Supplemental Indenture with respect to transfers, exchanges and replacements of the 2014 Series F Bonds. The 2014 Series F Bonds shall be registered bonds without coupons and shall be dated as of the date of the authentication thereof by the Trustee.

The 2014 Series F Bonds shall mature on the 15th day of December, 2044 (subject to earlier redemption, as provided herein), shall bear interest at the rate of 4.35% per annum, payable semi-annually on the 15th day of June and December of each year and at maturity (each an “2014 Series F Interest Payment Date”), beginning on June 15, 2015. The principal, Make-Whole Amount (as defined below), if any, and interest on the 2014 Series F 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 2014 Series F Bonds shall have such other terms as set forth in the form of 2014 Series F Bond provided in Section 3.

SECTION 2

The 2014 Series F 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 “2014 Series F Redemption Date”), at the applicable redemption price (“2014 Series F Redemption Price”) set forth below.

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At any time prior to June 15, 2044, the 2014 Series F Redemption Price will be equal to 100% of the principal amount of the 2014 Series F Bonds to be redeemed on the 2014 Series F Redemption Date together with the Make-Whole Amount (as defined in the form of 2014 Series F Bond provided in Section 3), if any, plus, in each case, accrued and unpaid interest thereon to the 2014 Series F Redemption Date.

At any time on or after June 15, 2044, the 2014 Series F Redemption Price will be equal to 100% of the principal amount of the bonds of 2014 Series F to be redeemed plus accrued and unpaid interest thereon to the redemption date.

Notwithstanding the foregoing, installments of interest on the 2014 Series F Bonds that are due and payable on 2014 Series F Interest Payment Dates falling on or prior to the 2014 Series F Redemption Date will be payable on the 2014 Series F 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 2014 Series F Bonds to be redeemed not more than 60 nor less than 30 days prior to the 2014 Series F Redemption Date, as provided in Section 4.05 of the Indenture. Each such notice shall specify such optional 2014 Series F Redemption Date, the aggregate principal amount of the 2014 Series F Bonds to be redeemed on such date, the principal amount of each 2014 Series F Bond held by such holder to be redeemed, and the interest to be paid on the 2014 Series F 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 2014 Series F Redemption Date and the Company shall deliver to holders of the 2014 Series F Bonds and to the Trustee a certificate of a senior financial officer specifying the calculation of such Make-Whole Amount as of the 2014 Series F 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 2014 Series F Redemption Date, and that such notice shall be of no effect unless such moneys are so received on or before such date.

If the 2014 Series F Bonds are only partially redeemed by the Company, the Trustee shall select which 2014 Series F Bonds are to be redeemed pro rata among all of the 2014 Series F 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 2014 Series F Bonds in part only, a new 2014 Series F Bond or 2014 Series F Bonds for the unredeemed portion will be issued in the name or names of the holders thereof upon the surrender or cancellation thereof.

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If money sufficient to pay the applicable the 2014 Series F Redemption Price with respect to the 2014 Series F Bonds to be redeemed on the applicable 2014 Series F Redemption Date, together with accrued interest to the 2014 Series F Redemption Date, is deposited with the Trustee on or before the related 2014 Series F Redemption Date and certain other conditions are satisfied, then the 2014 Series F 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 2014 Series F 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 2014 Series F Bond provided in Section 3.

SECTION 3

The 2014 Series F Bonds shall be registered bonds without coupons. The Trustee shall be the registrar and paying agent for the 2014 Series F Bonds, which duties it hereby accepts. The 2014 Series F Bonds may be issued in minimum denominations of $100,000 or any integral multiple of $1,000 in excess thereof.

The forms of 2014 Series F Bonds shall be substantially as follows:

[FORM OF DTE GAS COMPANY 4.35% FIRST MORTGAGE BONDS 2014 SERIES F DUE 2044]

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.

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DTE GAS COMPANY

4.35% MORTGAGE BONDS

2014 SERIES F DUE 2044

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 16, 2014

Stated Maturity: December 15, 2044

Interest Payment Dates: June 15 and December 15 of each year, beginning June 15, 2015.

Interest Rate: 4.35% 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, 2015 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 9, 2014 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-fifth Supplemental Indenture dated as of December 1, 2014 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 “4.35% First Mortgage

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Bonds 2014 Series F,” (herein called the “Bonds”) created by the Forty-fifth Supplemental Indenture dated as of December 1, 2014 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.

At any time prior to June 15, 2044, 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 June 15, 2044, the Redemption Price will be equal to 100% of the principal amount of the bonds of 2014 Series F 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.

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“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) over 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

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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.

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

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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.

Dated:

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DTE GAS COMPANY

By:______________________________

Attest:

By:______________________

De

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 2014 Series F Bond Form]

SECTION 4

Each certificate evidencing the 2014 Series F Bonds (and all 2014 Series F 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

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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 2014 Series F 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 2014 Series F Bonds are presented to the Trustee with a request (i) to register the transfer of such 2014 Series F Bonds; or (ii) to exchange such 2014 Series F Bonds for 2014 Series F 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 2014 Series F 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 2014 Series F 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 2014 Series F Bonds are being transferred to the Company, a certification to that effect; or (z) if such 2014 Series F 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 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 2014 Series F Bond to the Company, and the signature to such transfer power shall be guaranteed to the satisfaction of the Trustee. All 2014 Series F Bonds so surrendered shall be forthwith canceled and delivered to or upon the order of the Company. All 2014 Series F Bonds executed, authenticated and delivered in exchange for 2014 Series F Bonds so surrendered shall be valid obligations of the Company, evidencing the same debt as the 2014 Series F Bonds surrendered, and shall be secured by the same lien and be entitled to the same benefits and protection as the 2014 Series F 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 2014 Series F 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 2014 Series F 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 2014 Series F Bonds and subject to the same provisions, limitations and conditions, one or more temporary 2014 Series F 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 2014 Series F Bonds shall be substantially of the tenor of the 2014 Series F Bonds to be issued as herein before recited.

If any such temporary 2014 Series F Bonds shall at any time be so authenticated and delivered in lieu of definitive 2014 Series F 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 2014 Series F 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 2014 Series F Bonds surrendered. All temporary 2014 Series F Bonds so surrendered shall be forthwith canceled by the Trustee and delivered to or upon the order of the Company. Until exchanged for definitive 2014 Series F Bonds the temporary 2014 Series F Bonds shall in all respects be entitled to the lien and security of the Indenture and all supplemental indentures.

ARTICLE II
ISSUE OF BONDS

The 2014 Series F Bonds in the aggregate principal amount of $150,000,000 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 III 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.

16

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 IV RECORDING AND FILING OF SUPPLEMENTAL INDENTURE
DATED AS OF DECEMBER 1, 2013

Pursuant to the terms and provisions of the Original Indenture, a Supplemental Indenture dated as of December 1, 2013 providing for the terms of First Mortgage Bonds to be issued thereunder designated as 2013 Series C, 2013 Series D and 2013 Series E 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 12, 2013 (Filing No. 2013175671-0) 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	12/12/13	504	136
Alger County Register of Deeds	12/12/13	MI 201302664
Alpena County Register of Deeds	12/12/13	499	445
Antrim County Register of Deeds	12/12/13	845	335
Arenac County Register of Deeds	12/12/13	201304394
Barry County Register of Deeds	12/12/13	2013-014550
Benzie County Register of Deeds	12/13/13	2013R - 05997
Charlevoix County Register of Deeds	12/12/13	1051	798
Cheboygan County Register of Deeds	12/12/13	1249	307
Chippewa County Register of Deeds	12/12/13	1171	503
Clare County Register of Deeds	12/12/13	1247	789
Clinton County Register of Deeds	12/12/13	5209490
Crawford County Register of Deeds	12/12/13	716	376
Delta County Register of Deeds	12/12/13	1094	874
Dickinson County Register of Deeds	12/12/13	GL 791	923
Emmet County Register of Deeds	12/12/13	1162	686
Gladwin County Register of Deeds	12/12/13	1016	98
Grand Traverse County Register of Deeds	12/12/13	2013R - 22724
Gratiot County Register of Deeds	12/12/13	951	1439

17

COUNTY	RECORDED	LIBER/ INSTRUMENT NO.	PAGE
Ionia County Register of Deeds	12/12/13	632	4361
Iosco County Register of Deeds	12/12/13	1097	238
Iron County Register of Deeds	12/12/13	628	432
Isabella County Register of Deeds	12/12/13	1654	801
Jackson County Register of Deeds	12/12/13	2024	42
Kalkaska County Register of Deeds	12/12/13	3117392
Kent County Register of Deeds	12/13/13	20131213-0122498
Lake County Register of Deeds	12/18/13	367	964
Leelanau County Register of Deeds	12/12/13	1186	852
Lenawee County Register of Deeds	12/18/13	2480	395
Livingston County Register of Deeds	12/12/13	2013R - 045468
Macomb County Register of Deeds	12/16/13	22593	167
Manistee County Register of Deeds	12/12/13	2013R007066A
Marquette County Register of Deeds	12/18/13	2013R - 13633
Mason County Register of Deeds	12/12/13	2013R07258
Mecosta County Register of Deeds	12/18/13	840	2090
Menominee County Register of Deeds	12/12/13	741	330
Missaukee County Register of Deeds	12/18/13	2013-04250 AMTG
Monroe County Register of Deeds	12/18/13	2013R30522
Montcalm County Register of Deeds	12/18/13	1604	1164
Montmorency County Register of Deeds	12/18/13	339	489
Muskegon County Register of Deeds	12/18/13	4006	745
Newaygo County Register of Deeds	12/12/13	452	9317
Oakland County Register of Deeds	1/9/14	46695	165
Oceana County Register of Deeds	12/12/13	2013	26779
Ogemaw County Register of Deeds	12/12/13	3118540
Osceola County Register of Deeds	12/12/13	927	217
Oscoda County Register of Deeds	12/13/13	213-03094
Otsego County Register of Deeds	12/12/13	1337	658
Ottawa County Register of Deeds	12/13/13	2013-0053761
Presque Isle County Register of Deeds	12/12/13	544	936
Roscommon County Register of Deeds	12/20/13	1135	1710
St. Clair County Register of Deeds	12/12/13	4467	806
Saginaw County Register of Deeds	12/19/13	2756	642
Shiawassee County Register of Deeds	12/12/13	1193	797
Washtenaw County Register of Deeds	12/12/13	5014	571
Wayne County Register of Deeds	12/12/13	51221	462

18

COUNTY	RECORDED	LIBER/ INSTRUMENT NO.	PAGE
Wexford County Register of Deeds	12/12/13	664	1637

ARTICLE V 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 VI 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, by the Forty-fourth Supplemental Indenture dated as of December 1, 2013 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.

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

19

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.

20

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/ EDWARD J. SOLOMON

    Edward J. Solomon

Assistant Treasurer

Signed, sealed, acknowledged and
delivered by DTE GAS COMPANY in the presence of:

/s/ DANA PIERRE-LOUISDana 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, 2014, by Edward J. Solomon, 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

21

My Commission Expires: December 28, 2016

22

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/ CIRINO EMANUELE

Name: Cirino Emanuele

Vice President

State of New York    }

} ss.

County of New York    }

The foregoing instrument was acknowledged before me this 8th day of December, 2014, 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/ NOREEN SANTOSNotary Public, State of New York
No. 01SA6228750
Qualified in Nassau County

Certificate Filed in New York County

Commission Expires: September 27, 2018

23

This instrument was drafted by:

Dana Pierre-Louis

One Energy Plaza, 688WCB

Detroit, MI 48226

When recorded return to:

Jennifer Evans

DTE EnergyOne Energy Plaza, 688WCB

Detroit, MI 48226

24

EX-10.92

EXHIBIT 10-92

FIRST AMENDMENT TO THE

DTE ENERGY COMPANY

SUPPLEMENTAL RETIREMENT PLAN

(Amended and Restated Effective January 1, 2005)

As authorized by resolutions adopted by the DTE Energy Benefit Plan Administration Committee on March 19, 2013, the DTE Energy Company Supplemental Retirement Plan (Amended and Restated Effective January 1, 2005), is amended as follows:

1.Effective January 1, 2005, Section 7.4(b)(2)(A) is amended to read as follows:

(A)The Participant’s election is filed with the Committee at least 12 months before the earliest date on which the distribution of the Post-2004 Account would begin under the Participant’s then-current distribution election;

(i)For purposes of this Section 7.4(b)(2)(A), the date the Participant terminates employment other than because of death is treated as “the earliest date on which distribution of the Post-2004 Account would begin” if the Participant has not filed a previous election under this Section 7.4(b)(2) to change the form of distribution of the Post-2004 Account.

This Amendment is executed on behalf of the Committee by its Chairperson, as authorized by the Committee’s resolution.

Dated: March 19, 2013

/s/ LARRY E. STEWARD

Larry E. Steward

Vice President, Human Resources

Committee Chairperson

EX-10.93

EXHIBIT 10-93

SECOND AMENDMENT TO THE

DTE ENERGY COMPANY

SUPPLEMENTAL RETIREMENT PLAN

(Amended and Restated Effective January 1, 2005)

As authorized by resolutions adopted by the DTE Energy Benefit Plan Administration Committee on November 11, 2014, the DTE Energy Company Supplemental Retirement Plan (Amended and Restated Effective January 1, 2005), is amended as follows:

1.Effective January 1, 2015, Article 6 is amended to read as follows:

ARTICLE 6

Employers’ Obligation

Section 6.1.Qualified Plan Benefit. DTE Energy Corporate Services, LLC will pay under this Plan any amount that any eligible employee would have been entitled to receive under the Qualified Plan but for the limitation on compensation under Section 401(a)(17) of the Code, the limitation on benefits and contributions under Section 415 of the Code, and any other provision of the Code or other law that the Committee hereafter designates. Also, DTE Energy Corporate Services, LLC will pay under this Plan any amount that any eligible employee would have been entitled to receive under the Qualified Plan but for the exclusion of deferrals under the DTE Energy Company Supplemental Savings Plan and the DTE Energy Company Executive Deferred Compensation Plan from the definition of compensation under the option of the Qualified Plan applicable to such Participant.

Section 6.2.Executive Deferred Compensation Plan Benefit. DTE Energy Corporate Services, LLC will credit a hypothetical bookkeeping account (“Make-Up Account”) for each Participant with amounts intended to replace benefits (but not earnings) under any plan maintained by DTE Energy Corporate Services, LLC intended to be qualified under Code section 401(a) which are reduced as a result of any deferrals under Sections 4.01, 4.02, or 4.03 of the DTE Energy Company Executive Deferred Compensation Plan (“EDCP”):

(a)Traditional Pension Plan Make-Up. DTE Energy Corporate Services, LLC will credit to the Participant’s Make-Up Account an amount equal to the difference between (i) the present value, determined under each applicable defined benefit plan maintained by DTE Energy Corporate Services, LLC intended to be qualified under Code section 401(a), including the MCN Traditional Option and the DTE Traditional Option of the Qualified Plan (“Pension Plan”), of the benefit that the Participant would have been entitled to receive under each such Pension Plan but for his election to defer any amount under the EDCP, and (ii) the present value, determined under each such Pension Plan, of the benefit that the Participant is entitled to receive under such Pension Plan. Such credit will be determined and credited as of the Participant’s date of termination of employment.

(b)Cash Balance Plan Make-Up. DTE Energy Corporate Services, LLC will credit to the Participant’s Make-Up Account an amount equal to the additional increment that would have been added to the Participant’s account under a cash balance defined benefit plan maintained by DTE Energy Corporate Services, LLC intended to be qualified under Code section 401(a), excluding the MCN Traditional Option and the DTE Traditional Option of the Qualified Plan (“Cash Balance Plan”),

but for his election to defer any amount under the EDCP. Such credit will be determined and credited as of the last day of each calendar year.

Section 6.3.Prior Plan Payments. If a Participant is in pay status as of December 31, 2014 under this Plan or one of the Prior Plans, or has terminated employment from a Participating Employer prior to January 1, 2015, the amount and method of payment to the Participant will continue under the provisions of this Plan or the applicable Prior Plan. All payments payable under this Section 6.3 will be paid by DTE Energy Corporate Services, LLC.

2.Effective January 1, 2015, Section 7.6 is amended to read as follows:

Section 7.6.Transfer to an Affiliated Company. Benefits for a Participant who transfers employment from one Employer to an Affiliated Company will be subject to the transfer provisions of the Qualified Plan. The Participant’s participation in this Plan after the transfer will be conditioned on the Participant’s continued participation in the Qualified Plan after the transfer.

This Amendment is executed on behalf of the Committee by its Chairperson, as authorized by the Committee’s resolution.

Dated: November 11, 2014

/s/ LARRY E. STEWARD

Larry E. Steward

Senior Vice President, Human Resources

Committee Chairperson

EX-12.60

Exhibit 12-60

DTE Energy Company

Computation of Ratio of Earnings to Fixed Charges

	Year Ended December 31,
	2014			2013			2012		2011		2010
	(In millions)
Earnings:
Pretax earnings	$	1,275		$	922		$	960	$	991	$	962
Adjustments	(15		)	(26		)	71		4		7
Fixed charges	453			461			463		520		567
Net earnings	$	1,713		$	1,357		$	1,494	$	1,515	$	1,536
Fixed Charges:
Interest expense	$	424		$	432		$	441	$	490	$	543
Adjustments	29			29			22		30		24
Fixed charges	$	453		$	461		$	463	$	520	$	567
Ratio of earnings to fixed charges	3.78			2.94			3.23		2.91		2.71

EX-21.10

Exhibit 21-10

SUBSIDIARIES OF DTE ENERGY COMPANY

DTE Energy Company’s principal subsidiaries as of December 31, 2014 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 Energy Resources, LLC	Delaware
3.	DTE Energy Trading, Inc.	Michigan
4.	DTE Enterprises, Inc.	Michigan
5.	DTE Gas Holdings, Inc.	Michigan
6.	DTE Gas Company	Michigan

EX-23.28

Exhibit 23-28

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-183442 and 333-157769) and Form S-8 (No. 333-183440, 333-133645, 333-157768, 333-109623, and 333-199746) of DTE Energy Company of our report dated February 13, 2015 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 13, 2015

EX-31.95

Exhibit 31-95

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 13, 2015
Gerard M. Anderson Chairman of the Board and Chief Executive Officer of DTE Energy Company

EX-31.96

Exhibit 31-96

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 13, 2015
Peter B. Oleksiak Senior Vice President and Chief Financial Officer of DTE Energy Company

EX-32.95

Exhibit 32-95

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, 2014, 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 13, 2015	/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-32.96

Exhibit 32-96

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, 2014, 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 13, 2015	/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.

XML

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2014

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets

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

	2014			2013
	(In millions)
Assets
Recoverable pension and other postretirement costs:
Pension	$	2,284		$	1,660
Other postretirement costs	234			—
Asset retirement obligation	448			394
Recoverable Michigan income taxes	267			286
Unamortized loss on reacquired debt	67			63
Other recoverable income taxes	66			71
Accrued PSCR/GCR revenue	61			—
Deferred environmental costs	59			59
Cost to achieve Performance Excellence Process	54			75
Recoverable income taxes related to securitized regulatory assets	19			126
Removal costs asset	15			—
Transitional Reconciliation Mechanism	14			—
Other	139			129
	3,727			2,863
Less amount included in current assets	(76		)	(26		)
	$	3,651		$	2,837
Securitized regulatory assets	$	34		$	231

Schedule of Regulatory Liabilities

Liabilities
Removal costs liability	$	308		$	351
Renewable energy	227			277
Over recovery of Securitization	71			72
Refundable revenue decoupling/deferred gain	67			127
Negative pension offset	67			84
Refundable income taxes	33			45
Energy optimization	24			31
Fermi 2 refueling outage	16			26
Refundable other postretirement costs	—			72
Accrued PSCR/GCR refund	—			65
Other	7			14
	$	820		$	1,164
Less amount included current liabilities	(153		)	(302		)
	$	667		$	862

XML

Retirement Benefits and Trusteed Assets (Pension Plan - Fair Value Measurements) (Details) (Pension Plan, USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 3,981	$ 3,720	$ 3,223
Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	46	22
US Large Cap Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	899	896
US Small Cap and Mid Cap Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	225	221
Non US Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	745	741
Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,120	937
Hedge Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	759	733
Private Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	187	170
Securities Lending [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	(239)	0
Securities Lending Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	239	0
Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,929	2,034
Level 1 [Member] | Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	46	22
Level 1 [Member] | US Large Cap Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	899	896
Level 1 [Member] | US Small Cap and Mid Cap Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	225	221
Level 1 [Member] | Non US Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	526	611
Level 1 [Member] | Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	7	16
Level 1 [Member] | Hedge Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	226	268
Level 1 [Member] | Private Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 1 [Member] | Securities Lending [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	(189)	0
Level 1 [Member] | Securities Lending Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	189	0
Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,427	1,121
Level 2 [Member] | Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 2 [Member] | US Large Cap Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 2 [Member] | US Small Cap and Mid Cap Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 2 [Member] | Non US Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	219	130
Level 2 [Member] | Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,113	921
Level 2 [Member] | Hedge Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	95	70
Level 2 [Member] | Private Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 2 [Member] | Securities Lending [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	(50)	0
Level 2 [Member] | Securities Lending Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	50	0
Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	625	565	518
Level 3 [Member] | Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | US Large Cap Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | US Small Cap and Mid Cap Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Non US Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Hedge Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	438	395	339
Level 3 [Member] | Private Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	187	170	179
Level 3 [Member] | Securities Lending [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Securities Lending Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 0	$ 0

XML

Organization and Basis of Presentation (Details Textuals) (USD $)	Dec. 31, 2014 customers
Organization, Consolidation and Presentation of Financial Statements [Abstract]
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

XML

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Schedule of Long-term Purchase Commitment

The Company estimates that these commitments will be approximately $9.0 billion from 2015 through 2051 as detailed in the following table:

	(In millions)
2015	$	2,384
2016	1,258
2017	742
2018	477
2019	431
2020 and thereafter	3,723
	$	9,015

XML

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, 2014	Dec. 31, 2013
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$ 40	$ (1)
Other Postretirement Benefit Plan
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Plan assets at fair value, beginning of year	1,527	1,153
Total realized/unrealized gains (losses)	62	196
Plan assets at fair value, end of year	1,528	1,527
Other Postretirement Benefit Plan | Hedge Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Plan assets at fair value, end of year	320	314
Other Postretirement Benefit Plan | Private Equity Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Plan assets at fair value, end of year	131	101
Level 3 [Member] | Other Postretirement Benefit Plan
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Plan assets at fair value, beginning of year	260	205
Total realized/unrealized gains (losses)	17	23
Purchases	42	41
Sales	(20)	(9)
Plan assets at fair value, end of year	299	260
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	15	23
Level 3 [Member] | Other Postretirement Benefit Plan | Hedge Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Plan assets at fair value, beginning of year	159	119
Total realized/unrealized gains (losses)	8	14
Purchases	9	26
Sales	(8)	0
Plan assets at fair value, end of year	168	159
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	7	14
Level 3 [Member] | Other Postretirement Benefit Plan | Private Equity Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Plan assets at fair value, beginning of year	101	86
Total realized/unrealized gains (losses)	9	9
Purchases	33	15
Sales	(12)	(9)
Plan assets at fair value, end of year	131	101
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$ 8	$ 9

XML

Regulatory Matters (Schedule of Regulatory Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Regulatory Assets [Line Items]
Regulatory Assets	$ 3,727	$ 2,863
Regulatory Assets, Current	(76)	(26)
Regulatory Assets, Noncurrent	3,651	2,837
Securitized Regulatory Assets, Noncurrent	34	231
Pension Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	2,284	1,660
Postretirment Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	234	0
Asset Retirement Obligation Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	448	394
Recoverable Michigan Income Taxes [Member]
Regulatory Assets [Line Items]
Regulatory Assets	267	286
Unamortized Loss on Reacquired Debt [Member]
Regulatory Assets [Line Items]
Regulatory Assets	67	63
Other Recoverabe Income Taxes [Member]
Regulatory Assets [Line Items]
Regulatory Assets	66	71
Accrued PSCR/GCR Revenue [Member]
Regulatory Assets [Line Items]
Regulatory Assets	61	0
Deferred Environmental Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	59	59
Cost to Achieve Performance Excellence Process [Member]
Regulatory Assets [Line Items]
Regulatory Assets	54	75
Recoverable Income Taxes related to Securitized Regulatory Assets [Member]
Regulatory Assets [Line Items]
Regulatory Assets	19	126
Unrecovered Removal Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	15	0
Transitional Recovery Mechanism [Member]
Regulatory Assets [Line Items]
Regulatory Assets	14	0
Other Assets [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 139	$ 129

XML

Stock-Based Compensation (Stock Option Activity) (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Number of options (in shares):
Options outstanding beginning of the year	723,697
Granted	0
Exercised	(268,689)
Forfeited or expired	(10,730)
Options outstanding end of the year	444,278
Weighted Average Exercise Price (in dollars per share):
Options outstanding beginning of the year	$ 42.60
Granted	$ 0.00
Exercised	$ 41.14
Forfeited or expired	$ 39.41
Options outstanding end of the year	$ 43.56
Outstanding, Intrinsic Value	$ 17

XML

Organization and Basis of Presentation (Consolidated Variable Interest Entities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Assets [Abstract]
Cash and cash equivalents	$ 48	$ 52	$ 65	$ 68
Restricted cash	120	123
Accounts receivable	1,504	1,542
Property, plant and equipment, net	16,820	15,800
Securitized regulatory assets	34	231
Total Assets	27,974	25,935	26,339
Liabilities [Abstract]
Current portion long-term debt, including capital leases	274	898
Current regulatory liabilities	153	302
Mortgage bonds, notes and other	7,860	6,618
Securitization bonds	0	105
Capital lease obligations	3	11
Variable Interest Entity, Primary Beneficiary Securitization [Member]
Assets [Abstract]
Cash and cash equivalents	0	0
Restricted cash	96	100
Accounts receivable	26	34
Inventories	0	0
Property, plant and equipment, net	0	0
Securitized regulatory assets	34	231
Other current and long term assets	1	4
Total Assets	157	369
Liabilities [Abstract]
Accounts payable and accrued current liabilities	3	7
Current portion long-term debt, including capital leases	105	196
Current regulatory liabilities	32	43
Mortgage bonds, notes and other	0	0
Securitization bonds	0	105
Capital lease obligations	0	0
Other current and long term liabilities	9	8
Total Liabilities	149	359
Variable Interest Entity, Primary Beneficiary Other, Restricted [Member]
Assets [Abstract]
Cash and cash equivalents	7	12
Restricted cash	8	8
Accounts receivable	15	16
Inventories	67	118
Property, plant and equipment, net	81	99
Securitized regulatory assets	0	0
Other current and long term assets	6	9
Total Assets	184	262
Liabilities [Abstract]
Accounts payable and accrued current liabilities	8	23
Current portion long-term debt, including capital leases	10	9
Current regulatory liabilities	0	0
Mortgage bonds, notes and other	15	21
Securitization bonds	0	0
Capital lease obligations	3	7
Other current and long term liabilities	6	6
Total Liabilities	42	66
Variable Interest Entity, Primary Beneficiary, Restricted [Member]
Assets [Abstract]
Cash and cash equivalents	7	12
Restricted cash	104	108
Accounts receivable	41	50
Inventories	67	118
Property, plant and equipment, net	81	99
Securitized regulatory assets	34	231
Other current and long term assets	7	13
Total Assets	341	631
Liabilities [Abstract]
Accounts payable and accrued current liabilities	11	30
Current portion long-term debt, including capital leases	115	205
Current regulatory liabilities	32	43
Mortgage bonds, notes and other	15	21
Securitization bonds	0	105
Capital lease obligations	3	7
Other current and long term liabilities	15	14
Total Liabilities	$ 191	$ 425

XML

Earnings Per Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Basic Earnings per Share
Net Income Attributable to DTE Energy Company	$ 299	$ 156	$ 124	$ 326	$ 124	$ 198	$ 105	$ 234	$ 905	$ 661	$ 610
Average number of common shares outstanding (in shares)									177	175	171
Weighted average net restricted shares outstanding (in shares)									0	1	1
Dividends declared — common shares									475	453	413
Dividends declared — net restricted shares									1	1	1
Total distributed earnings									476	454	414
Net income less distributed earnings									429	207	196
Distributed (dividends per common share) (in dollars per share)									$ 2.69	$ 2.59	$ 2.42
Undistributed (in dollars per share)									$ 2.42	$ 1.17	$ 1.14
Total (in dollars per share)	$ 1.68	$ 0.88	$ 0.70	$ 1.84	$ 0.70	$ 1.13	$ 0.60	$ 1.35	$ 5.11	$ 3.76	$ 3.56
Diluted Earnings per Share
Net Income Attributable to DTE Energy Company	299	156	124	326	124	198	105	234	905	661	610
Average number of common shares outstanding (in shares)									177	175	171
Average incremental shares from assumed exercise of options (in shares)									0	0	1
Common shares for dilutive calculation (in shares)									177	175	172
Weighted average net restricted shares outstanding (in shares)									0	1	1
Dividends declared — common shares									475	453	413
Dividends declared — net restricted shares									1	1	1
Total distributed earnings									476	454	414
Net income less distributed earnings									$ 429	$ 207	$ 196
Distributed (dividends per common share)									$ 2.69	$ 2.59	$ 2.42
Undistributed (in dollars per share)									$ 2.41	$ 1.17	$ 1.13
Total (in dollars per share)	$ 1.68	$ 0.88	$ 0.70	$ 1.84	$ 0.70	$ 1.13	$ 0.60	$ 1.34	$ 5.10	$ 3.76	$ 3.55

XML

Commitments and Contingencies (Purchase Commitments) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Purchase Obligation, Fiscal Year Maturity [Abstract]
2015	$ 2,384
2016	1,258
2017	742
2018	477
2019	431
2020 and thereafter	3,723
Total Purchase Commitments	$ 9,015

XML

Short-Term Credit Arrangements and Borrowings (Tables)

12 Months Ended

Dec. 31, 2014

Short-term Debt [Abstract]

Schedule of Line of Credit Facilities

The availability under the facilities in place at December 31, 2014 is shown in the following table:

	DTE Energy		DTE Electric		DTE Gas		Total
	(In millions)
Unsecured letter of credit facility, expiring in February 2015	$	100	$	—	$	—	$	100
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Unsecured revolving credit facility, expiring April 2018	1,200		300		300		1,800
	1,425		300		300		2,025
Amounts outstanding at December 31, 2014:
Commercial paper issuances	203		50		145		398
Letters of credit	204		—		—		204
	407		50		145		602
Net availability at December 31, 2014	$	1,018	$	250	$	155	$	1,423

XML

Organization and Basis of Presentation (Tables)

12 Months Ended

Dec. 31, 2014

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

Schedule of Variable Interest Entities

The following table summarizes the major balance sheet items for consolidated VIEs as of December 31, 2014 and 2013. 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, 2014						December 31, 2013
	Securitization		Other		Total		Securitization		Other		Total
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	7	$	7	$	—	$	12	$	12
Restricted cash	96		8		104		100		8		108
Accounts receivable	26		15		41		34		16		50
Inventories	—		67		67		—		118		118
Property, plant and equipment, net	—		81		81		—		99		99
Securitized regulatory assets	34		—		34		231		—		231
Other current and long-term assets	1		6		7		4		9		13
	$	157	$	184	$	341	$	369	$	262	$	631
LIABILITIES
Accounts payable and accrued current liabilities	$	3	$	8	$	11	$	7	$	23	$	30
Current portion long-term debt, including capital leases	105		10		115		196		9		205
Current regulatory liabilities	32		—		32		43		—		43
Mortgage bonds, notes and other	—		15		15		—		21		21
Securitization bonds	—		—		—		105		—		105
Capital lease obligations	—		3		3		—		7		7
Other current and long-term liabilities	9		6		15		8		6		14
	$	149	$	42	$	191	$	359	$	66	$	425

Summary of Amounts For Nonconsolidated Variable Interest Entities

Amounts for non-consolidated VIEs as of December 31, 2014 and 2013 are as follows:

	December 31, 2014		December 31, 2013
	(In millions)
Other investments	$	134	$	141
Notes receivable	$	15	$	8

XML

Fair Value (Assets and Liabilities Recorded at Fair Value on a Recurring Basis) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Assets [Abstract]
Nuclear decommissioning trusts	$ 1,241	$ 1,191
Derivative Asset [Abstract]
Derivative asset, gross	1,178	833
Derivative asset, Netting	(1,006)	(707)
Derivative assets, net	172	126
Liabilities [Abstract]
Total fair value of derivatives	(1,110)	(936)
Derivative liability, netting	1,025	698
Derivative Liabilities, net	(85)	(238)
Current Derivative Liability [Member]
Liabilities [Abstract]
Total fair value of derivatives	(1,041)	(773)
Noncurrent Derivative Liability [Member]
Liabilities [Abstract]
Total fair value of derivatives	(69)	(163)
Natural Gas Commodity Contract [Member]
Derivative Asset [Abstract]
Derivative asset, gross	787	396
Derivative asset, Netting	(681)	(382)
Derivative assets, net	106	14
Liabilities [Abstract]
Total fair value of derivatives	(718)	(503)
Derivative liability, netting	679	395
Derivative Liabilities, net	(39)	(108)
Electricity Commodity Contract [Member]
Derivative Asset [Abstract]
Derivative asset, gross	342	400
Derivative asset, Netting	(280)	(291)
Derivative assets, net	62	109
Liabilities [Abstract]
Total fair value of derivatives	(342)	(398)
Derivative liability, netting	298	269
Derivative Liabilities, net	(44)	(129)
Other Commodity Contract [Member]
Derivative Asset [Abstract]
Derivative asset, gross	45	37
Derivative asset, Netting	(42)	(34)
Derivative assets, net	3	3
Liabilities [Abstract]
Total fair value of derivatives	(45)	(34)
Derivative liability, netting	45	34
Derivative Liabilities, net	0	0
Other Derivative Contract [Member]
Derivative Asset [Abstract]
Derivative asset, gross	4	0
Derivative asset, Netting	(3)	0
Derivative assets, net	1	0
Liabilities [Abstract]
Total fair value of derivatives	(5)	(1)
Derivative liability, netting	3	0
Derivative Liabilities, net	(2)	(1)
Recurring [Member]
Assets [Abstract]
Cash equivalents	112	125
Nuclear decommissioning trusts	1,241	1,191
Other Investments	150	136
Derivative Asset [Abstract]
Derivative asset, Netting	(1,006)	(707)
Derivative assets, net	172	126
Total assets	1,675	1,578
Liabilities [Abstract]
Derivative liability, netting	1,025	698
Derivative Liabilities, net	(85)	(238)
Net Assets (Liabilities) at the end of the period	1,590	1,340
Net Assets (Liabilities) at the end of the period, netting	19	(9)
Recurring [Member] | Current Asset [Member]
Derivative Asset [Abstract]
Derivative asset, Netting	(955)	(592)
Total assets	240	224
Recurring [Member] | Non Current Asset [Member]
Derivative Asset [Abstract]
Derivative asset, Netting	(51)	(115)
Total assets	1,435	1,354
Recurring [Member] | Current Derivative Liability [Member]
Liabilities [Abstract]
Derivative liability, netting	964	578
Derivative Liabilities, net	(77)	(195)
Recurring [Member] | Noncurrent Derivative Liability [Member]
Liabilities [Abstract]
Derivative liability, netting	61	120
Derivative Liabilities, net	(8)	(43)
Recurring [Member] | Natural Gas Commodity Contract [Member]
Derivative Asset [Abstract]
Derivative asset, Netting	(681)	(382)
Derivative assets, net	106	14
Liabilities [Abstract]
Derivative liability, netting	679	395
Derivative Liabilities, net	(39)	(108)
Recurring [Member] | Electricity Commodity Contract [Member]
Derivative Asset [Abstract]
Derivative asset, Netting	(280)	(291)
Derivative assets, net	62	109
Liabilities [Abstract]
Derivative liability, netting	298	269
Derivative Liabilities, net	(44)	(129)
Recurring [Member] | Other Commodity Contract [Member]
Derivative Asset [Abstract]
Derivative asset, Netting	(42)	(34)
Derivative assets, net	3	3
Liabilities [Abstract]
Derivative liability, netting	45	34
Derivative Liabilities, net	0	0
Recurring [Member] | Other Derivative Contract [Member]
Derivative Asset [Abstract]
Derivative asset, Netting	(3)	0
Derivative assets, net	1	0
Liabilities [Abstract]
Derivative liability, netting	3	0
Derivative Liabilities, net	(2)	(1)
Recurring [Member] | Level 1 [Member]
Assets [Abstract]
Cash equivalents	13	10
Nuclear decommissioning trusts	792	779
Other Investments	100	92
Derivative Asset [Abstract]
Derivative asset, gross	597	306
Total assets	1,502	1,187
Liabilities [Abstract]
Total fair value of derivatives	(610)	(309)
Net Assets (Liabilities) at the end of the period	892	878
Recurring [Member] | Level 1 [Member] | Current Asset [Member]
Derivative Asset [Abstract]
Total assets	582	277
Recurring [Member] | Level 1 [Member] | Non Current Asset [Member]
Derivative Asset [Abstract]
Total assets	920	910
Recurring [Member] | Level 1 [Member] | Current Derivative Liability [Member]
Liabilities [Abstract]
Total fair value of derivatives	(572)	(268)
Recurring [Member] | Level 1 [Member] | Noncurrent Derivative Liability [Member]
Liabilities [Abstract]
Total fair value of derivatives	(38)	(41)
Recurring [Member] | Level 1 [Member] | Natural Gas Commodity Contract [Member]
Derivative Asset [Abstract]
Derivative asset, gross	555	273
Liabilities [Abstract]
Total fair value of derivatives	(578)	(277)
Recurring [Member] | Level 1 [Member] | Electricity Commodity Contract [Member]
Derivative Asset [Abstract]
Derivative asset, gross	0	0
Liabilities [Abstract]
Total fair value of derivatives	0	0
Recurring [Member] | Level 1 [Member] | Other Commodity Contract [Member]
Derivative Asset [Abstract]
Derivative asset, gross	42	33
Liabilities [Abstract]
Total fair value of derivatives	(32)	(32)
Recurring [Member] | Level 1 [Member] | Other Derivative Contract [Member]
Derivative Asset [Abstract]
Derivative asset, gross	0	0
Liabilities [Abstract]
Total fair value of derivatives	0	0
Recurring [Member] | Level 2 [Member]
Assets [Abstract]
Cash equivalents	99	115
Nuclear decommissioning trusts	449	412
Other Investments	50	44
Derivative Asset [Abstract]
Derivative asset, gross	439	351
Total assets	1,037	922
Liabilities [Abstract]
Total fair value of derivatives	(382)	(415)
Net Assets (Liabilities) at the end of the period	655	507
Recurring [Member] | Level 2 [Member] | Current Asset [Member]
Derivative Asset [Abstract]
Total assets	504	400
Recurring [Member] | Level 2 [Member] | Non Current Asset [Member]
Derivative Asset [Abstract]
Total assets	533	522
Recurring [Member] | Level 2 [Member] | Current Derivative Liability [Member]
Liabilities [Abstract]
Total fair value of derivatives	(357)	(328)
Recurring [Member] | Level 2 [Member] | Noncurrent Derivative Liability [Member]
Liabilities [Abstract]
Total fair value of derivatives	(25)	(87)
Recurring [Member] | Level 2 [Member] | Natural Gas Commodity Contract [Member]
Derivative Asset [Abstract]
Derivative asset, gross	140	89
Liabilities [Abstract]
Total fair value of derivatives	(78)	(140)
Recurring [Member] | Level 2 [Member] | Electricity Commodity Contract [Member]
Derivative Asset [Abstract]
Derivative asset, gross	295	261
Liabilities [Abstract]
Total fair value of derivatives	(290)	(272)
Recurring [Member] | Level 2 [Member] | Other Commodity Contract [Member]
Derivative Asset [Abstract]
Derivative asset, gross	0	1
Liabilities [Abstract]
Total fair value of derivatives	(9)	(2)
Recurring [Member] | Level 2 [Member] | Other Derivative Contract [Member]
Derivative Asset [Abstract]
Derivative asset, gross	4	0
Liabilities [Abstract]
Total fair value of derivatives	(5)	(1)
Recurring [Member] | Level 3 [Member]
Assets [Abstract]
Cash equivalents	0	0
Nuclear decommissioning trusts	0	0
Other Investments	0	0
Derivative Asset [Abstract]
Derivative asset, gross	142	176
Total assets	142	176
Liabilities [Abstract]
Total fair value of derivatives	(118)	(212)
Net Assets (Liabilities) at the end of the period	24	(36)
Recurring [Member] | Level 3 [Member] | Current Asset [Member]
Derivative Asset [Abstract]
Total assets	109	139
Recurring [Member] | Level 3 [Member] | Non Current Asset [Member]
Derivative Asset [Abstract]
Total assets	33	37
Recurring [Member] | Level 3 [Member] | Current Derivative Liability [Member]
Liabilities [Abstract]
Total fair value of derivatives	(112)	(177)
Recurring [Member] | Level 3 [Member] | Noncurrent Derivative Liability [Member]
Liabilities [Abstract]
Total fair value of derivatives	(6)	(35)
Recurring [Member] | Level 3 [Member] | Natural Gas Commodity Contract [Member]
Derivative Asset [Abstract]
Derivative asset, gross	92	34
Liabilities [Abstract]
Total fair value of derivatives	(62)	(86)
Recurring [Member] | Level 3 [Member] | Electricity Commodity Contract [Member]
Derivative Asset [Abstract]
Derivative asset, gross	47	139
Liabilities [Abstract]
Total fair value of derivatives	(52)	(126)
Recurring [Member] | Level 3 [Member] | Other Commodity Contract [Member]
Derivative Asset [Abstract]
Derivative asset, gross	3	3
Liabilities [Abstract]
Total fair value of derivatives	(4)	0
Recurring [Member] | Level 3 [Member] | Other Derivative Contract [Member]
Derivative Asset [Abstract]
Derivative asset, gross	0	0
Liabilities [Abstract]
Total fair value of derivatives	$ 0	$ 0

XML

Retirement Benefits and Trusteed Assets (OPEB - Assumptions used in Determining the PBO and Net Pension Costs) (Details)	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 31, 2013	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Ultimate health care trend rate					5.00%
Health care trend rate pre- and post- 65					7.00%
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.30%	4.95%	4.10%	4.95%	4.15%
Health care trend rate pre 65			7.50%	7.50%
Health care trend post 65			6.50%	6.50%
Ultimate health care trend rate			4.50%	4.50%
Health care trend pre 65			2025	2025
Health care trend post 65			6.50%
Year in which ultimate reached pre- and post- 65					2021
Ultimate year post 65			2024	2024
Other postretirement benefit costs, Discount Rate	4.15%	4.30%	4.95%		5.00%
Expected long-term rate of return on plan assets			8.00%	8.25%	8.25%
Health care trend rate pre-65			7.50%
Health care trend rate pre- and post- 65				7.00%	7.00%
Other Postretirement Benefit Plan | Other postretirement benefit costs [Member]
Defined Benefit Plan Disclosure [Line Items]
Ultimate health care trend rate			4.50%	5.00%	5.00%
Health care trend pre 65			2025
Year in which ultimate reached pre- and post- 65		2021		2021	2020
Ultimate year post 65			2024

XML

Stock Based-Compensation (Stock Awards Activity Rollforward) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock (in shares):
Forfeitures	(10,730)
Restricted Stock [Member]
Restricted Stock (in shares):
Balance at beginning of the period	492,329
Grants	159,590	127,785	167,320
Forfeitures	(16,841)
Vested and issued	(218,760)
Balance at end of period	416,318	492,329
Weighted Average Grant Date Fair Value (in dollars per share):
Balance at beginning of period	$ 53.76
Grants	$ 70.09	$ 64.72	$ 53.71
Forfeitures	$ 62.41
Vested and issued	$ 47.77
Balance at end of period	$ 62.82	$ 53.76

XML

Segment and Related Information (Financial Data) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Operating Revenues	$ 3,078	$ 2,595	$ 2,698	$ 3,930	$ 2,533	$ 2,387	$ 2,225	$ 2,516	$ 12,301	$ 9,661	$ 8,791
Depreciation, Depletion and Amortization									1,145	1,094	1,018
Interest income									(10)	(9)	(10)
Interest Expense									429	436	440
Income Taxes									364	254	286
Net Income Attributable to DTE Energy Company	299	156	124	326	124	198	105	234	905	661	610
Total Assets	27,974				25,935				27,974	25,935	26,339
Goodwill	2,018				2,018				2,018	2,018	2,018
Capital Expenditures and Acquisitions									2,049	1,876	2,018
Continuing Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues											8,791
Depreciation, Depletion and Amortization											995
Interest income											(10)
Interest Expense											440
Income Taxes											286
Net Income Attributable to DTE Energy Company											666
Total Assets											26,339
Goodwill											2,018
Capital Expenditures and Acquisitions											1,969
Discontinued Operations [Member]
Segment Reporting Information [Line Items]
Net Income Attributable to DTE Energy Company											(56)
Total Assets											0
Goodwill											0
Capital Expenditures and Acquisitions											49
Operating Segments [Member] | Electric [Member]
Segment Reporting Information [Line Items]
Operating Revenues									5,283	5,199	5,293
Depreciation, Depletion and Amortization									933	902	827
Interest income									(1)	(1)	(1)
Interest Expense									250	268	272
Income Taxes									296	252	280
Net Income Attributable to DTE Energy Company									528	484	483
Total Assets	18,715				17,508				18,715	17,508	17,755
Goodwill	1,208				1,208				1,208	1,208	1,208
Capital Expenditures and Acquisitions									1,561	1,325	1,230
Operating Segments [Member] | Gas [Member]
Segment Reporting Information [Line Items]
Operating Revenues									1,636	1,474	1,315
Depreciation, Depletion and Amortization									99	95	92
Interest income									(7)	(7)	(7)
Interest Expense									57	58	59
Income Taxes									78	77	50
Net Income Attributable to DTE Energy Company									140	143	115
Total Assets	4,283				3,938				4,283	3,938	4,059
Goodwill	743				743				743	743	745
Capital Expenditures and Acquisitions									224	209	221
Operating Segments [Member] | Power and Industrial Projects [Member]
Segment Reporting Information [Line Items]
Operating Revenues									2,289	1,950	1,823
Depreciation, Depletion and Amortization									77	72	65
Interest income									(5)	(6)	(7)
Interest Expense									28	27	37
Income Taxes									(100)	(45)	(44)
Net Income Attributable to DTE Energy Company									90	66	42
Total Assets	1,009				1,067				1,009	1,067	991
Goodwill	26				26				26	26	26
Capital Expenditures and Acquisitions									77	93	281
Operating Segments [Member] | Gas Storage and Pipelines [Member]
Segment Reporting Information [Line Items]
Operating Revenues									203	132	96
Depreciation, Depletion and Amortization									34	23	8
Interest income									(6)	(7)	(8)
Interest Expense									22	18	8
Income Taxes									53	45	39
Net Income Attributable to DTE Energy Company									82	70	61
Total Assets	884				824				884	824	668
Goodwill	24				24				24	24	22
Capital Expenditures and Acquisitions									184	245	233
Operating Segments [Member] | Energy Trading [Member]
Segment Reporting Information [Line Items]
Operating Revenues									3,762	1,771	1,109
Depreciation, Depletion and Amortization									1	1	2
Interest income									0	0	0
Interest Expense									7	8	8
Income Taxes									77	(38)	7
Net Income Attributable to DTE Energy Company									122	(58)	12
Total Assets	755				623				755	623	629
Goodwill	17				17				17	17	17
Capital Expenditures and Acquisitions									3	3	1
Operating Segments [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating Revenues									2	3	3
Depreciation, Depletion and Amortization									1	1	1
Interest income									(48)	(51)	(52)
Interest Expense									122	120	121
Income Taxes									(40)	(37)	(46)
Net Income Attributable to DTE Energy Company									(57)	(44)	(47)
Total Assets	3,209				2,945				3,209	2,945	3,074
Goodwill	0				0				0	0	0
Capital Expenditures and Acquisitions									0	1	3
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating Revenues									(874)	(868)	(848)
Depreciation, Depletion and Amortization									0	0	0
Interest income									57	63	65
Interest Expense									(57)	(63)	(65)
Income Taxes									0	0	0
Net Income Attributable to DTE Energy Company									0	0	0
Total Assets	(881)				(970)				(881)	(970)	(837)
Goodwill	0				0				0	0	0
Capital Expenditures and Acquisitions									0	0	0
Intersegment Eliminations [Member] | Discontinued Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues									0	0	(2)
Intersegment Eliminations [Member] | Electric [Member] | Continuing Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues									(29)	(26)	(29)
Intersegment Eliminations [Member] | Gas [Member] | Continuing Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues									(6)	(4)	(4)
Intersegment Eliminations [Member] | Power and Industrial Projects [Member] | Continuing Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues									(794)	(816)	(801)
Intersegment Eliminations [Member] | Gas Storage and Pipelines [Member] | Continuing Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues									(9)	(3)	(6)
Intersegment Eliminations [Member] | Energy Trading [Member] | Continuing Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues									(33)	(43)	(43)
Intersegment Eliminations [Member] | Corporate and Other [Member] | Continuing Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues									$ (3)	$ 24	$ 37

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income before income taxes	$ 1,275	$ 922	$ 960
Income tax expense at 35% statutory rate	446	323	336
Production tax credits	(119)	(68)	(49)
Investment tax credits	(6)	(6)	(6)
Depreciation	(4)	(4)	(4)
AFUDC - Equity	(7)	(5)	(4)
Employee Stock Ownership Plan dividends	(4)	(4)	(4)
Domestic production activities deduction	0	(14)	(14)
State and local income taxes, net of federal benefit	51	37	37
Enactment of New York Corporate Income Tax Legislation, net of federal benefit	8	0	0
Other, net	(1)	(5)	(6)
Income tax expense	$ 364	$ 254	$ 286
Effective income tax rate (as percent)	28.50%	27.50%	29.80%

XML

Financial and Other Derivative Instruments (Netting Offsets Reconciliation to Balance Sheet) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Derivative Assets:
Total fair value of derivatives	$ 1,178,000,000	$ 833,000,000
Collateral adjustment	0	(26,000,000)
Derivative Asset, Current	128,000,000	99,000,000
Derivative Assets, Noncurrent	44,000,000	27,000,000
Derivative Liabilities:
Total fair value of derivatives	(1,110,000,000)	(936,000,000)
Counterparty netting	19,000,000	17,000,000
Derivative Liabilities, Current	(77,000,000)	(195,000,000)
Derivative Liabilities, Noncurrent	(8,000,000)	(43,000,000)
Current Derivative Asset [Member]
Derivative Assets:
Total fair value of derivatives	1,083,000,000	691,000,000
Counterparty netting	(955,000,000)	(566,000,000)
Collateral adjustment	0	(26,000,000)
Noncurrent Derivative Asset [Member]
Derivative Assets:
Total fair value of derivatives	95,000,000	142,000,000
Counterparty netting	(51,000,000)	(115,000,000)
Collateral adjustment	0	0
Current Derivative Liability [Member]
Derivative Liabilities:
Total fair value of derivatives	(1,041,000,000)	(773,000,000)
Counterparty netting	9,000,000	12,000,000
Collateral adjustment	955,000,000	566,000,000
Noncurrent Derivative Liability [Member]
Derivative Liabilities:
Total fair value of derivatives	(69,000,000)	(163,000,000)
Counterparty netting	10,000,000	5,000,000
Collateral adjustment	$ 51,000,000	$ 115,000,000

XML

Significant Accounting Policies Significant Accounting Policics (Accumulated Other Comprehensive Loss) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance	$ (136)	$ (158)
Other comprehensive income (loss) before reclassifications	(26)	13
Amounts reclassified from accumulated other comprehensive income	7	9
Other comprehensive income	(19)	22	0
Ending balance	(155)	(136)	(158)
Net Unrealized Gain/(Loss) on Derivatives [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance	(4)	(4)
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from accumulated other comprehensive income	0	0
Other comprehensive income	0	0
Ending balance	(4)	(4)
Net Unrealized Gain/(Loss) on Investments [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance	(6)	(8)
Other comprehensive income (loss) before reclassifications	1	2
Amounts reclassified from accumulated other comprehensive income	0	0
Other comprehensive income	1	2
Ending balance	(5)	(6)
Benefit Obligations [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance	(126)	(148)
Other comprehensive income (loss) before reclassifications	(25)	13
Amounts reclassified from accumulated other comprehensive income	7	9
Other comprehensive income	(18)	22
Ending balance	(144)	(126)
Foreign Currency Translation [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance	0	2
Other comprehensive income (loss) before reclassifications	(2)	(2)
Amounts reclassified from accumulated other comprehensive income	0	0
Other comprehensive income	(2)	(2)
Ending balance	$ (2)	$ 0

XML

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, USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Pension Plan
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2015	$ 269
2016	277
2017	286
2018	298
2019	309
2020-2024	1,634
Total Expected Future Benefit Payments	$ 3,073

XML

Supplementary Quarterly Financial Information (Unaudited) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Operating Revenues	$ 3,078	$ 2,595	$ 2,698	$ 3,930	$ 2,533	$ 2,387	$ 2,225	$ 2,516	$ 12,301	$ 9,661	$ 8,791
Operating Income	542	239	249	560	241	329	223	410	1,590	1,203	1,279
Net Income Attributable to DTE Energy Company	$ 299	$ 156	$ 124	$ 326	$ 124	$ 198	$ 105	$ 234	$ 905	$ 661	$ 610
Basic Earnings per Share (in dollars per share)	$ 1.68	$ 0.88	$ 0.70	$ 1.84	$ 0.70	$ 1.13	$ 0.60	$ 1.35	$ 5.11	$ 3.76	$ 3.56
Diluted Earnings per Share (in dollars per share)	$ 1.68	$ 0.88	$ 0.70	$ 1.84	$ 0.70	$ 1.13	$ 0.60	$ 1.34	$ 5.10	$ 3.76	$ 3.55

XML

Income Taxes (Reconciliation of Unrecognized Tax Benefits) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, beginning balance	$ 10	$ 11	$ 48
Reductions for tax positions of prior years	0	0	(2)
Additions for tax positions of current year	0	0	1
Settlements	0	0	(30)
Lapse of statute of limitations	(1)	(1)	(6)
Unrecognized Tax Benefits, ending balance	$ 9	$ 10	$ 11

XML

Fair Value (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Option, Quantitative Disclosures [Line Items]
Assets level 1 to level 2	$ 0	$ 0
Assets level 2 to 1	0	0
Liabilities level 1 to 2	0	0
Liabilities level 2 to 1	0	0
Unrealized losses on available for sale securities	(7,000,000)	(9,000,000)
Trading securities realized gain (loss)	14,000,000	22,000,000	11,000,000
Accumulated Net Unrealized Investment Gain (Loss) [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Unrealized losses on available for sale securities	0	0
Nuclear Decommissioning Trust Fund [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Cash equivalents	11,000,000	19,000,000
Average maturity of debt securities	7 years	7 years
Cash and Cash Equivalents [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Nuclear decommissioning trust fund investments	1.00%	2.00%
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	38.00%	37.00%
Recurring [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Cash equivalents	112,000,000	125,000,000
Restricted Assets [Member] | Recurring [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Cash equivalents	105,000,000	109,000,000
Other Investments [Member] | Recurring [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Cash equivalents	7,000,000	16,000,000
Other Investments [Member] | Recurring [Member] | Equity [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Available-for-sale securities	8,000,000	7,000,000
Other investments	$ 150,000,000	$ 136,000,000

XML

Fair Value (Unobservable Inputs related to Level 3 Assets and Liabilities) (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Unobservable Input Valuation Techniques [Line Items]
Derivative asset, gross	$ 1,178	$ 833
Total fair value of derivatives	(1,110)	(936)
Natural Gas Commodity Contract [Member]
Unobservable Input Valuation Techniques [Line Items]
Derivative asset, gross	787	396
Total fair value of derivatives	(718)	(503)
Electricity Commodity Contract [Member]
Unobservable Input Valuation Techniques [Line Items]
Derivative asset, gross	342	400
Total fair value of derivatives	(342)	(398)
Level 3 [Member] | Discounted Cash Flow Valuation Technique [Member] | Natural Gas Commodity Contract [Member] | Minimum [Member]
Unobservable Input Valuation Techniques [Line Items]
Forward Basis Price	(2.28)	(0.88)
Level 3 [Member] | Discounted Cash Flow Valuation Technique [Member] | Natural Gas Commodity Contract [Member] | Maximum
Unobservable Input Valuation Techniques [Line Items]
Forward Basis Price	7.83	5.07
Level 3 [Member] | Discounted Cash Flow Valuation Technique [Member] | Natural Gas Commodity Contract [Member] | Weighted Average [Member]
Unobservable Input Valuation Techniques [Line Items]
Forward Basis Price	(0.22)	(0.16)
Level 3 [Member] | Discounted Cash Flow Valuation Technique [Member] | Electricity Commodity Contract [Member] | Minimum [Member]
Unobservable Input Valuation Techniques [Line Items]
Forward Basis Price	(14)	(7)
Level 3 [Member] | Discounted Cash Flow Valuation Technique [Member] | Electricity Commodity Contract [Member] | Maximum
Unobservable Input Valuation Techniques [Line Items]
Forward Basis Price	15	15
Level 3 [Member] | Discounted Cash Flow Valuation Technique [Member] | Electricity Commodity Contract [Member] | Weighted Average [Member]
Unobservable Input Valuation Techniques [Line Items]
Forward Basis Price	4	3
Recurring [Member] | Level 3 [Member]
Unobservable Input Valuation Techniques [Line Items]
Derivative asset, gross	142	176
Total fair value of derivatives	(118)	(212)
Recurring [Member] | Level 3 [Member] | Natural Gas Commodity Contract [Member]
Unobservable Input Valuation Techniques [Line Items]
Derivative asset, gross	92	34
Total fair value of derivatives	(62)	(86)
Recurring [Member] | Level 3 [Member] | Electricity Commodity Contract [Member]
Unobservable Input Valuation Techniques [Line Items]
Derivative asset, gross	47	139
Total fair value of derivatives	$ (52)	$ (126)

XML

Financial and Other Derivative Instruments (Fair Value of Derivative Instruments) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Total fair value of derivatives	$ 1,178	$ 833
Total fair value of derivatives	(1,110)	(936)
Natural Gas Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Total fair value of derivatives	787	396
Total fair value of derivatives	(718)	(503)
Electricity Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Total fair value of derivatives	342	400
Total fair value of derivatives	(342)	(398)
Other Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Total fair value of derivatives	45	37
Total fair value of derivatives	(45)	(34)
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Total fair value of derivatives	1,178	833
Total fair value of derivatives	(1,110)	(936)
Not Designated as Hedging Instrument [Member] | Foreign Currency Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Total fair value of derivatives	4	0
Total fair value of derivatives	(5)	(1)
Not Designated as Hedging Instrument [Member] | Natural Gas Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Total fair value of derivatives	787	396
Total fair value of derivatives	(718)	(503)
Not Designated as Hedging Instrument [Member] | Electricity Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Total fair value of derivatives	342	400
Total fair value of derivatives	(342)	(398)
Not Designated as Hedging Instrument [Member] | Other Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Total fair value of derivatives	45	37
Total fair value of derivatives	(45)	(34)
Current Derivative Asset [Member]
Derivatives, Fair Value [Line Items]
Total fair value of derivatives	1,083	691
Noncurrent Derivative Asset [Member]
Derivatives, Fair Value [Line Items]
Total fair value of derivatives	95	142
Current Derivative Liability [Member]
Derivatives, Fair Value [Line Items]
Total fair value of derivatives	(1,041)	(773)
Noncurrent Derivative Liability [Member]
Derivatives, Fair Value [Line Items]
Total fair value of derivatives	$ (69)	$ (163)

XML

Income Taxes (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Deferred tax asset, general business tax credit carryforwards		$ 29,000,000
Deferred tax asset, alternative minimum tax credit carryforwards		267,000,000
Deferred tax assets, state net operating loss and credit carry-forwards		39,000,000	43,000,000
Valuation allowance		31,000,000	37,000,000
Unrecognized tax benefits that would impact effective tax rate		2,000,000	2,000,000
Significant change in unrecognized tax benefit is reasonable possible, amount of unrecorded benefit		6,000,000
Interest on income taxes accrued		1,000,000	1,000,000
Income tax penalties accrued		0
Interest on income taxes expense	$ (1,000,000)

XML

Regulatory Matters Regulatory Matters (Schedule of Regulatory Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 820	$ 1,164
Regulatory Liability, Current	(153)	(302)
Regulatory Liability, Noncurrent	667	862
Removal Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	308	351
Renewable Energy [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	227	277
Over Recovery of Securitization [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	71	72
Refundable Revenue Decoupling [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	67	127
Pension Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	67	84
Refundable Income Taxes [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	33	45
Energy Optimization [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	24	31
Refueling Outage [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	16	26
Refundable postretirement costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	72
Accrued PSCR GCR Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	65
Other Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 7	$ 14

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Commitments and Contingencies (Notes)

12 Months Ended

Dec. 31, 2014

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. The EPA and the State of Michigan have issued emission reduction regulations relating to ozone, fine particulate, regional haze, mercury, and other air pollution. These rules have led to controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, mercury and other emissions. To comply with these requirements, DTE Electric spent approximately $2.2 billion through 2014. The Company estimates DTE Electric will make capital expenditures of approximately $100 million in 2015 and up to approximately $30 million of additional capital expenditures through 2019 based on current regulations.

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), requires further reductions of sulfur dioxide and nitrogen oxides emissions effective January 2015. DTE Electric expects to meet its obligations under CSAPR beginning in 2015.

The Mercury and Air Toxics Standard (MATS) rule, formerly known as the Electric Generating Unit Maximum Achievable Control Technology (EGU MACT) Rule was finalized in December 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 all relevant 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 November 2014, the Supreme Court agreed to review a challenge to the MATS rule based on a narrowly focused question of how the EPA considered costs in regulating air pollutants emitted by electric utilities. DTE Electric cannot predict the financial impact or outcome of this Supreme Court case, or the timing of its resolution.

The EPA proposed revised air quality standards for ground level ozone in November 2014 and the standards are expected to be finalized by October 2015. DTE Electric will engage with the EPA and other stakeholders in commenting on this rule. DTE Electric cannot predict the financial impact of the proposed ozone standards at this time.

In July 2009, DTE Energy received a 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. In August 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. In October 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit. In March 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. In September 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. In March 2014, the U.S. District Court judge granted again DTE Energy's motion for summary judgment dismissing the civil case related to Monroe Unit 2. In April 2014, the U.S. District Court judge granted motions filed by the EPA and the Sierra Club to amend their New Source Review complaint adding additional claims for Monroe Units 1, 2 and 3, Belle River Units 1 and 2, Trenton Channel Unit 9 and denied the claims related to River Rouge that were brought by the Sierra Club. In June 2014, the EPA filed a motion requesting certification for appeal of the March 2014 summary judgment decision. In October 2014, the EPA and the U.S. Department of Justice filed the anticipated notice of appeal of the U.S. District Court judge's dismissal of the Monroe Unit 2 case. This will officially start the appellate process. The amended New Source Review claims are all stayed until the appeal is resolved by the U.S. Court of Appeals for the Sixth Circuit.

DTE Energy and DTE Electric believe that the plants and generating units identified by the EPA and the Sierra Club 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.

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. A final rule was issued in May 2014. The final rule specifies a time period exceeding three years to complete studies to determine the type of technology needed to reduce impacts to fish. Final compliance for the installation of the required technology will be determined by each state on a case by case basis. We are currently evaluating the compliance options and working with the State of Michigan on evaluating whether any controls are needed. These evaluations/studies may require modifications to some existing intake structures. It is not possible to quantify the impact of this rulemaking at this time.

In April 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 September 2015. 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 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 MGP 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, 2014 and 2013, the Company had $10 million and $8 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 believes the likelihood of a material change to the accrued amount is remote based on current knowledge of the conditions at each site.

In December 2014, the EPA released a pre-publication version of a rule to regulate coal ash. This rule is based on the continued listing of ash as a non-hazardous waste, and relies on various self-implementation design and performance standards. The rule is still being evaluated and it is not possible to quantify its impact at this time. DTE Electric owns and operates three permitted engineered ash storage facilities to dispose of fly ash from coal fired power plants and operates a number of smaller impoundments at its power plants.

Gas

Contaminated and Other Sites — Gas segment, owns or previously owned, 15 former MGP sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. Cleanup of three of the MGP sites is complete and the sites were closed. We completed partial closure of two sites in 2014. Cleanup activities associated with the remaining sites will be continued 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. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites, including gate stations, gas pipeline releases and underground storage tank locations. As of December 31, 2014 and 2013, the Company had $24 million and $28 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, 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 settled the alleged violations by implementing best management practices to address the issues and repair/upgrade their wastewater treatment plant. The Company recently received a permit to upgrade its existing waste water treatment system and is currently seeking a permit from the PADEP to further upgrade its wastewater treatment technology to a biological treatment facility. The Company expects to spend $1 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 will also spend up to an additional $13 million over the next few years to upgrade the treatment technology to biological treatment to meet future regulatory requirements and gain other operational improvement savings.

The Company received an NOV from the Allegheny County (PA) Health Department pertaining to excessive opacity readings from fugitive sources (mainly pushing emissions) in excess of its opacity standards for the Pennsylvania coke battery facility. Fugitive sources at the plant are in full compliance with the applicable Federal Opacity Standards. In February 2014, the Company received from the Group Against Smog & Pollution (GASP) a 60 day Notice of Intent to sue letter under the Federal Clean Air Act and/or Article XXI of the Allegheny County (PA) Health Department's Rules and Regulations. GASP alleged in the letter that the Company's coke battery facility in Pennsylvania was in violation of visible emissions limits from charging activities, door leaks, the combustion stack and pushing operations and hydrogen sulfide emission limits on flared, mixed or combusted coke oven gas. To resolve these issues, the Company agreed to a Consent Order and Agreement with Allegheny County pursuant to which the Company paid a fine of $300,000 and will spend $300,000 for a supplemental environmental project to enhance particulate collection efficiency from the coke battery's quench tower. Notwithstanding the agreement reached with the County, GASP proceeded with the filing of their complaint in May 2014. The Company believes that the GASP suit is without merit and filed a motion to dismiss in July 2014.

Other

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 information gathering stage, and DTE Energy is unable to estimate any required emissions reductions at this time.

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. 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 $1.5 billion in primary coverage and $1.25 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. The total limit for property damage for non-nuclear events is $2 billion and an aggregate of $328 million of coverage for extra expenses over a two-year period.

On January 13, 2015, the Terrorism Risk Insurance Program Reauthorization Act of 2015 was signed, extending TRIA through December 31, 2020. 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 NEIL policies, DTE Electric could be liable for maximum assessments of up to approximately $35 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 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 DOE for the future storage and disposal of spent nuclear fuel from Fermi 2 that required DTE Electric to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold. The fee was 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 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 agreement, including extensions, provides for a claims process and payment of delay-related costs experienced by DTE Electric through 2016. DTE Electric's claims are being settled and paid on a timely basis. The settlement proceeds reduce the cost of the dry cask storage facility assets and provide reimbursement for related operating expenses. The 1 mill per kWh DOE fee was reduced to zero effective May 16, 2014.

DTE Electric currently employs a spent nuclear fuel storage strategy utilizing a fuel pool and a newly completed dry cask storage facility. The initial dry cask loading campaign planned for 2014 has been completed. 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.

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.

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, 2014 is approximately $1 billion. Payment under these guarantees is considered remote.

REF Guarantees

The Company has provided certain guarantees and indemnities in conjunction with the sales of interests in its REF 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, 2014 is approximately $172 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, 2014. 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, 2014, the Company had approximately $49 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, 2014, 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 $9.0 billion from 2015 through 2051 as detailed in the following table:

	(In millions)
2015	$	2,384
2016	1,258
2017	742
2018	477
2019	431
2020 and thereafter	3,723
	$	9,015

The Company also estimates that 2015 capital expenditures and contributions to equity method investments will be approximately $2.6 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.

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.

For a discussion of contingencies related to regulatory matters and derivatives see Notes 8 and 12 to the Consolidated Financial Statements, "Regulatory Matters" and "Financial and Other Derivative Instruments".

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Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2014

Share-based Compensation [Abstract]

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Table Text Block]

The following table summarizes the components of stock-based compensation:

	2014		2013		2012
	(In millions)
Stock-based compensation expense	$	103	$	99	$	83
Tax benefit	40		38		33
Stock-based compensation cost capitalized in property, plant and equipment	16		15		5

Schedule of Share-based Compensation, Stock Options, Activity

The following table summarizes our stock option activity for the year ended December 31, 2014:

	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In millions)
Options outstanding at December 31, 2013	723,697		$	42.60
Granted	—		$	—
Exercised	(268,689	)	$	41.14
Forfeited or expired	(10,730	)	$	39.41
Options outstanding and exercisable at December 31, 2014	444,278		$	43.56	$	17

Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, by Exercise Price Range

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

Range of Exercise Prices					Number of Options	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)
$	27.00	—	$	38.00	25,857	$	27.70	4.16
$	38.01	—	$	42.00	82,834	$	41.77	3.16
$	42.01	—	$	45.00	221,487	$	43.93	4.06
$	45.01	—	$	50.00	114,100	$	47.75	2.15
					444,278	$	43.56	3.41

Schedule of Share-based Compensation, Restricted Stock Units Award Activity [Table Text Block]

Stock award activity for the years ended December 31 was:

	2014		2013		2012
Fair value of awards vested (in millions)	$	11	$	8	$	9
Restricted common shares awarded	159,590		127,785		167,320
Weighted average market price of shares awarded	$	70.09	$	64.72	$	53.71
Compensation cost charged against income (in millions)	$	10	$	23	$	12

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block]

The following table summarizes the Company’s restricted stock awards activity for the year ended December 31, 2014:

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at December 31, 2013	492,329		$	53.76
Grants	159,590		$	70.09
Forfeitures	(16,841	)	$	62.41
Vested and issued	(218,760	)	$	47.77
Balance at December 31, 2014	416,318		$	62.82

Share Based Compensation Expense [Table Text Block]

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

	2014		2013		2012
	(In millions)
Compensation expense	$	93	$	77	$	71
Cash settlements (a)	$	11	$	9	$	4
Stock settlements (a)	$	61	$	56	$	41

_______________________________________

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

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award

The following table summarizes the Company’s performance share activity for the period ended December 31, 2014:

	Performance Shares		Weighted Average Grant Date Fair Value
Balance at December 31, 2013	1,608,789		$	—
Grants	561,335		$	69.32
Forfeitures	(44,250	)	$	69.16
Payouts	(571,177	)	$	—
Balance at December 31, 2014	1,554,697		$	69.32

Schedule of Unrecognized Compensation Cost, Nonvested Awards

As of December 31, 2014, the total unrecognized compensation cost related to non-vested stock incentive plan arrangements and the weighted average recognition period was as follows:

	Unrecognized Compensation Cost		Weighted Average to be Recognized
	(In millions)		(In years)
Stock awards	$	10	1.06
Performance shares	48		0.98
	$	58	0.99

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Fair Value (Tables)

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Assets and Liabilities 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, 2014 and 2013:

	December 31, 2014															December 31, 2013
	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)	$	13		$	99		$	—		$	—		$	112		$	10		$	115		$	—		$	—		$	125
Nuclear decommissioning trusts	792			449			—			—			1,241			779			412			—			—			1,191
Other investments (c) (d)	100			50			—			—			150			92			44			—			—			136
Derivative assets:
Commodity Contracts:
Natural Gas	555			140			92			(681		)	106			273			89			34			(382		)	14
Electricity	—			295			47			(280		)	62			—			261			139			(291		)	109
Other	42			—			3			(42		)	3			33			1			3			(34		)	3
Other derivative contracts (e)	—			4			—			(3		)	1			—			—			—			—			—
Total derivative assets	597			439			142			(1,006		)	172			306			351			176			(707		)	126
Total	$	1,502		$	1,037		$	142		$	(1,006	)	$	1,675		$	1,187		$	922		$	176		$	(707	)	$	1,578
Liabilities:
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(578	)	$	(78	)	$	(62	)	$	679		$	(39	)	$	(277	)	$	(140	)	$	(86	)	$	395		$	(108	)
Electricity	—			(290		)	(52		)	298			(44		)	—			(272		)	(126		)	269			(129		)
Other	(32		)	(9		)	(4		)	45			—			(32		)	(2		)	—			34			—
Other derivative contracts (e)	—			(5		)	—			3			(2		)	—			(1		)	—			—			(1		)
Total derivative liabilities	(610		)	(382		)	(118		)	1,025			(85		)	(309		)	(415		)	(212		)	698			(238		)
Total	$	(610	)	$	(382	)	$	(118	)	$	1,025		$	(85	)	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)
Net Assets (Liabilities) at the end of the period	$	892		$	655		$	24		$	19		$	1,590		$	878		$	507		$	(36	)	$	(9	)	$	1,340
Assets:
Current	$	582		$	504		$	109		$	(955	)	$	240		$	277		$	400		$	139		$	(592	)	$	224
Noncurrent (f)	920			533			33			(51		)	1,435			910			522			37			(115		)	1,354
Total Assets	$	1,502		$	1,037		$	142		$	(1,006	)	$	1,675		$	1,187		$	922		$	176		$	(707	)	$	1,578
Liabilities:
Current	$	(572	)	$	(357	)	$	(112	)	$	964		$	(77	)	$	(268	)	$	(328	)	$	(177	)	$	578		$	(195	)
Noncurrent	(38		)	(25		)	(6		)	61			(8		)	(41		)	(87		)	(35		)	120			(43		)
Total Liabilities	$	(610	)	$	(382	)	$	(118	)	$	1,025		$	(85	)	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)
Net Assets (Liabilities) at the end of the period	$	892		$	655		$	24		$	19		$	1,590		$	878		$	507		$	(36	)	$	(9	)	$	1,340

_______________________________________

(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, 2014, available-for-sale securities of $112 million included $105 million and $7 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively. 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.

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

(d) Available-for-sale equity securities of $8 million at December 31, 2014 and $7 million at December 31, 2013 are included in Other investments on the Consolidated Statements of Financial Position.

(e) Primarily includes Foreign currency exchange contracts.

(f) Includes $150 million and $136 million of Other investments that are included in the Consolidated Statements of Financial Position in Other investments at December 31, 2014 and 2013, respectively.

Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis Level 3 Roll Forward

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2014 and 2013:

	Year Ended December 31, 2014												Year Ended December 31, 2013
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of December 31	$	(52	)	$	13		$	3		$	(36	)	$	(38	)	$	23		$	2		$	(13	)
Transfers into Level 3 from Level 2	—			—			—			—			1			—			—			1
Transfers from Level 3 into Level 2	(2		)	—			—			(2		)	—			—			—			—
Total gains (losses):
Included in earnings	(40		)	25			(5		)	(20		)	(32		)	75			—			43
Recorded in regulatory assets/liabilities	—			—			8			8			—			—			5			5
Purchases, issuances and settlements:
Purchases	—			1			—			1			(8		)	1			—			(7		)
Issuances	—			(3		)	—			(3		)	—			(1		)	—			(1		)
Settlements	124			(41		)	(7		)	76			25			(85		)	(4		)	(64		)
Net Assets (Liabilities) as of December 31	$	30		$	(5	)	$	(1	)	$	24		$	(52	)	$	13		$	3		$	(36	)
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	35		$	9		$	(4	)	$	40		$	(49	)	$	48		$	—		$	(1	)

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques

The following tables present the unobservable inputs related to Level 3 assets and liabilities as of December 31, 2014 and 2013:

	December 31, 2014
Commodity Contracts	Derivative Assets		Derivative Liabilities			Valuation Techniques	Unobservable Input	Range						Weighted Average
	(In millions)
Natural Gas	$	92	$	(62	)	Discounted Cash Flow	Forward basis price (per MMBtu)	$	(2.28	) —	$	7.83	/MMBtu	$	(0.22	)/MMBtu
Electricity	$	47	$	(52	)	Discounted Cash Flow	Forward basis price (per MWh)	$	(14	) —	$	15	/MWh	$	4	/MWh

	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

Fair Value of Financial Instruments

The following table presents the carrying amount and fair value of financial instruments as of December 31, 2014 and 2013:

	December 31, 2014								December 31, 2013
	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	$	41	$	—	$	—	$	41
Dividends payable	$	122	$	122	$	—	$	—	$	116	$	116	$	—	$	—
Short-term borrowings	$	398	$	—	$	398	$	—	$	131	$	—	$	131	$	—
Long-term debt, excluding capital leases	$	8,606	$	489	$	8,308	$	706	$	8,094	$	425	$	7,551	$	499

Fair Value of Nuclear Decommissioning Trust Fund Assets Text Block

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

	December 31, 2014		December 31, 2013
	(In millions)
Fermi 2	$	1,221	$	1,172
Fermi 1	3		3
Low level radioactive waste	17		16
Total	$	1,241	$	1,191

Schedule of Realized Gain (Loss)

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
	2014			2013			2012
	(In millions)
Realized gains	$	54		$	83		$	37
Realized losses	$	(33	)	$	(41	)	$	(31	)
Proceeds from sales of securities	$	1,146		$	1,118		$	759

Fair Value and Unrealized Gains and Losses for Nuclear Decommissioning Trust Fund Table

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

	December 31, 2014							December 31, 2013
	Fair Value		Unrealized Gains		Unrealized Losses			Fair Value		Unrealized Gains		Unrealized Losses
	(In millions)
Equity securities	$	756	$	204	$	(39	)	$	730	$	201	$	(25	)
Debt securities	474		21		(2		)	442		12		(6		)
Cash and cash equivalents	11		—		—			19		—		—
	$	1,241	$	225	$	(41	)	$	1,191	$	213	$	(31	)

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Income Taxes (Deferred Tax Assets (Liabilities)) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Components of Deferred Tax Assets and Liabilities [Abstract]
Property, plant and equipment	$ (3,832)	$ (3,372)
Securitized regulatory assets	(2)	(127)
Tax credit carry-forwards	296	266
Pension and benefits	(152)	(30)
State net operating loss and credit carry-forwards	39	43
Deferred Tax Liabilities, Other	(19)	(92)
Deferred Tax Liabilities, Gross	(3,670)	(3,312)
Less valuation allowance	(31)	(37)
Current deferred income tax assets (liabilities)	75	(28)
Long-term deferred income tax liabilities	(3,776)	(3,321)
Deferred income tax assets	861	934
Deferred income tax liabilities	(4,562)	(4,283)
Deferred income tax liabilities	$ (3,701)	$ (3,349)

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Long-Term Debt (Details Textuals) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Junior Subordinated Notes, Noncurrent	$ 480	$ 480

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Jointly Owned Utility Plant (Tables)

12 Months Ended

Dec. 31, 2014

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

Schedule of Jointly Owned Utility Plants

Ownership information of the two utility plants as of December 31, 2014 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)	$	1,742		$	412
Accumulated depreciation (in millions)	$	993		$	175

_______________________________________

(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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Supplementary Quarterly Financial Information (Unaudited ) (Tables)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

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)
2014
Operating Revenues	$	3,930	$	2,698	$	2,595	$	3,078	$	12,301
Operating Income	$	560	$	249	$	239	$	542	$	1,590
Net Income Attributable to DTE Energy Company	$	326	$	124	$	156	$	299	$	905
Basic Earnings per Share	$	1.84	$	0.70	$	0.88	$	1.68	$	5.11
Diluted Earnings per Share	$	1.84	$	0.70	$	0.88	$	1.68	$	5.10

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

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Jointly Owned Utility Plant (Detail Textuals)	Dec. 31, 2014 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 Hydroelectric Pumped Storage [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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Retirement Benefits and Trusteed Assets (Pension Plan - Target Allocations of Plan Assets) (Details) (Pension Plan)	12 Months Ended
	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Percentage of Assets	100.00%
US Large Cap Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Percentage of Assets	22.00%
US Small Cap and Mid Cap Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Percentage of Assets	5.00%
Non US Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Percentage of Assets	20.00%
Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Percentage of Assets	25.00%
Hedge Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Percentage of Assets	20.00%
Private Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Percentage of Assets	8.00%

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Discontinued Operations (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of business	$ 0	$ 0	$ 255,000,000
Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of disposal of equity interest in segment percentage			100.00%
Proceeds from divestiture of business			255,000,000
Loss from disposal before tax			83,000,000
Loss from disposal, net of tax			55,000,000
Allocation of corporate interest costs			$ 0

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Capital and Operating Leases (Tables)

12 Months Ended

Dec. 31, 2014

Leases [Abstract]

Schedule of Future Minimum Rental Payments for Operating Leases

Future minimum lease payments under non-cancelable leases at December 31, 2014 were:

	Operating Leases
	(In millions)
2015	$	42
2016	34
2017	28
2018	23
2019	14
Thereafter	78
Total minimum lease payments	$	219

Schedule of Future Minimum Lease Receivables for Capital Leases

The components of the net investment in the capital leases at December 31, 2014, were as follows:

	Capital Leases
	(In millions)
2015	$	12
2016	13
2017	13
2018	13
2019	10
Thereafter	9
Total minimum future lease receipts	70
Residual value of leased pipeline	40
Less unearned income	(34		)
Net investment in capital lease	76
Less current portion	(5		)
	$	71

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Organization and Basis of Presentation (Notes)

12 Months Ended

Dec. 31, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Basis of Presentation

ORGANIZATION AND BASIS OF PRESENTATION

Corporate Structure

DTE Energy owns the following businesses:

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

• DTE Gas is 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 the CFTC.

References in this Report to “we”, “us”, “our”, “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.

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 plants. 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 consolidated when the Company is the primary beneficiary. In addition, we have interests in certain VIEs through which 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 and sale contracts. As of December 31, 2014, the carrying amount of assets and liabilities in the Consolidated Statements of Financial Position that relate to its variable interests under long-term purchase and sale contracts are predominately related to working capital accounts and generally represent the amounts owed by or to the Company for the deliveries associated with the current billing cycle under the contracts. The Company has not provided any significant 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 and sale 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, 2014 and 2013. 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, 2014						December 31, 2013
	Securitization		Other		Total		Securitization		Other		Total
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	7	$	7	$	—	$	12	$	12
Restricted cash	96		8		104		100		8		108
Accounts receivable	26		15		41		34		16		50
Inventories	—		67		67		—		118		118
Property, plant and equipment, net	—		81		81		—		99		99
Securitized regulatory assets	34		—		34		231		—		231
Other current and long-term assets	1		6		7		4		9		13
	$	157	$	184	$	341	$	369	$	262	$	631
LIABILITIES
Accounts payable and accrued current liabilities	$	3	$	8	$	11	$	7	$	23	$	30
Current portion long-term debt, including capital leases	105		10		115		196		9		205
Current regulatory liabilities	32		—		32		43		—		43
Mortgage bonds, notes and other	—		15		15		—		21		21
Securitization bonds	—		—		—		105		—		105
Capital lease obligations	—		3		3		—		7		7
Other current and long-term liabilities	9		6		15		8		6		14
	$	149	$	42	$	191	$	359	$	66	$	425

Amounts for non-consolidated VIEs as of December 31, 2014 and 2013 are as follows:

	December 31, 2014		December 31, 2013
	(In millions)
Other investments	$	134	$	141
Notes receivable	$	15	$	8

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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, 2014	Dec. 31, 2013	Dec. 31, 2012
Amounts recognized in Regulatory assets (liabilities) (see Note 8)
Regulatory Liabilities	$ (820)	$ (1,164)
Other Postretirement Benefit Plan
Change in accumulated postretirement benefit obligation
Benefit obligation, beginning of year	1,878	2,315
Service cost	34	47	68
Interest cost	89	88	120
Plan amendments	0	(218)
Actuarial (gain) loss	131	(267)
Medicare Part D subsidy	0	1
Benefits paid	(88)	(88)
Benefit obligation, end of year	2,044	1,878	2,315
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets	1,528	1,527	1,153
Actual return on plan assets	62	196
Company contributions	24	264
Benefits paid	(85)	(86)
Funded status of the plans	(516)	(351)
Amount recorded as:
Current liabilities	(1)	(1)
Noncurrent liabilities	(515)	(350)
Pension and Other Postretirement Defined Benefit Plans, Liabilities	(516)	(351)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	34	29
Prior service (credit)	(5)	(10)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax	29	19
Amounts recognized in Regulatory assets (liabilities) (see Note 8)
Net actuarial loss	488	321
Prior service credit	(254)	(393)
Regulatory Liabilities	$ 234	$ (72)

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Discontinued Operations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total operating expenses	$ 10,711	$ 8,458	$ 7,512
Income Tax Benefit	0	0	(29)
Net Loss Attributable to DTE Energy Company	0	0	(56)
Segment, Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating Revenues			55
Operation and maintenance			24
Depreciation, depletion and amortization			23
Taxes other than income			4
Asset (gains) losses, net			83
Total operating expenses			134
Operating Loss			(79)
Other (Income) and Deductions			6
Loss Before Income Taxes			(85)
Income Tax Benefit			(29)
Net Loss Attributable to DTE Energy Company			$ (56)

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Stock-Based Compensation (Performance Share Awards Compensation Expense) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Compensation Expense Recorded [Line Items]
Compensation expense	$ 103	$ 99	$ 83
Performance Shares [Member]
Compensation Expense Recorded [Line Items]
Compensation expense	93	77	71
Cash settlements	11	9	4
Stock settlements	$ 61	$ 56	$ 41

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Valuation and Qualifying Accounts Valuation and Qualifying Accounts (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	$ 55	$ 62	$ 162
Charged to cost and expenses	95	94	79
Charged to other accounts	20	23	16
Deductions	(116)	(124)	(195)
Balance at End of Period	$ 54	$ 55	$ 62

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Financial and Other Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2014

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, 2014 and 2013:

	December 31, 2014					December 31, 2013
	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	4	$	(5	)	$	—	$	(1	)
Commodity Contracts:
Natural Gas	787		(718		)	396		(503		)
Electricity	342		(342		)	400		(398		)
Other	45		(45		)	37		(34		)
Total derivatives not designated as hedging instruments:	$	1,178	$	(1,110	)	$	833	$	(936	)
Total derivatives:
Current	$	1,083	$	(1,041	)	$	691	$	(773	)
Noncurrent	95		(69		)	142		(163		)
Total derivatives	$	1,178	$	(1,110	)	$	833	$	(936	)

Netting Offsets of Derivative Assets and Liabilities

The following table presents the netting offsets of derivative assets and liabilities at December 31, 2014 and 2013:

	December 31, 2014									December 31, 2013
	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	$	787		$	(681	)	$	106		$	396		$	(382	)	$	14
Electricity	342			(280		)	62			400			(291		)	109
Other	45			(42		)	3			37			(34		)	3
Other derivative contracts (a)	4			(3		)	1			—			—			—
Total derivative assets	$	1,178		$	(1,006	)	$	172		$	833		$	(707	)	$	126
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(718	)	$	679		$	(39	)	$	(503	)	$	395		$	(108	)
Electricity	(342		)	298			(44		)	(398		)	269			(129		)
Other	(45		)	45			—			(34		)	34			—
Other derivative contracts (a)	(5		)	3			(2		)	(1		)	—			(1		)
Total derivative liabilities	$	(1,110	)	$	1,025		$	(85	)	$	(936	)	$	698		$	(238	)

_______________________________________

(a) Primarily includes Foreign currency exchange contracts

Netting Offsets of Derivative Assets and Liabilities Reconciliation to the Statements of Financial Position

The following table presents the netting offsets of derivative assets and liabilities at December 31, 2014 and 2013:

	December 31, 2014												December 31, 2013
	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	$	1,083		$	95		$	(1,041	)	$	(69	)	$	691		$	142		$	(773	)	$	(163	)
Counterparty netting	(955		)	(51		)	955			51			(566		)	(115		)	566			115
Collateral adjustment	—			—			9			10			(26		)	—			12			5
Total derivatives as reported	$	128		$	44		$	(77	)	$	(8	)	$	99		$	27		$	(195	)	$	(43	)

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, 2014 and 2013 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		2014			2013
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	(2	)	$	(1	)
Commodity Contracts:
Natural Gas	Operating Revenue	(30		)	(48		)
Natural Gas	Fuel, purchased power and gas	(5		)	(44		)
Electricity	Operating Revenue	123			82
Other	Operating Revenue	(7		)	—
Total		$	79		$	(11	)

Volume of Commodity Contracts

The following represents the cumulative gross volume of derivative contracts outstanding as of December 31, 2014:

Commodity	Number of Units
Natural Gas (MMBtu)	895,599,953
Electricity (MWh)	11,296,153
Foreign Currency Exchange (Canadian dollars)	63,022,462

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Supplementary Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Supplemental Quarterly Financial Information (Unaudited)

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)
2014
Operating Revenues	$	3,930	$	2,698	$	2,595	$	3,078	$	12,301
Operating Income	$	560	$	249	$	239	$	542	$	1,590
Net Income Attributable to DTE Energy Company	$	326	$	124	$	156	$	299	$	905
Basic Earnings per Share	$	1.84	$	0.70	$	0.88	$	1.68	$	5.11
Diluted Earnings per Share	$	1.84	$	0.70	$	0.88	$	1.68	$	5.10

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

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Segment and Related Information (Notes)

12 Months Ended

Dec. 31, 2014

Segment Reporting [Abstract]

Segment and Related 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 principally of DTE Gas, which 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.

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 REF and sell electricity from renewable 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 are determined on an individual company basis and recognize 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:

	2014		2013			2012
	(In millions)
Electric	$	29	$	26		$	29
Gas	6		4			4
Power and Industrial Projects	794		816			801
Gas Storage and Pipelines	9		3			6
Energy Trading	33		43			43
Corporate and Other	3		(24		)	(37		)
Discontinued Operations	—		—			2
	$	874	$	868		$	848

Financial data of the business segments follows:

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Tax Expense (Benefit)			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures and Acquisitions
	(In millions)
2014
Electric	$	5,283		$	933	$	(1	)	$	250		$	296		$	528		$	18,715		$	1,208	$	1,561
Gas	1,636			99		(7		)	57			78			140			4,283			743		224
Power and Industrial Projects	2,289			77		(5		)	28			(100		)	90			1,009			26		77
Gas Storage and Pipelines	203			34		(6		)	22			53			82			884			24		184
Energy Trading	3,762			1		—			7			77			122			755			17		3
Corporate and Other	2			1		(48		)	122			(40		)	(57		)	3,209			—		—
Reclassifications and Eliminations	(874		)	—		57			(57		)	—			—			(881		)	—		—
Total	$	12,301		$	1,145	$	(10	)	$	429		$	364		$	905		$	27,974		$	2,018	$	2,049

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Tax Expense (Benefit)			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures and Acquisitions
	(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
Power and Industrial Projects	1,950			72		(6		)	27			(45		)	66			1,067			26		93
Gas Storage and Pipelines	132			23		(7		)	18			45			70			824			24		245
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 Tax Expense (Benefit)			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures and Acquisitions
	(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
Power and Industrial Projects	1,823			65		(7		)	37			(44		)	42			991			26		281
Gas Storage and Pipelines	96			8		(8		)	8			39			61			668			22		233
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	$	1,969
Discontinued Operations (Note 4)															(56		)	—			—		49
Total															$	610		$	26,339		$	2,018	$	2,018

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Short-Term Credit Arrangements and Borrowings (Details Textuals) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Short-term Debt [Line Items]
Other outstanding letters of credit	$ 602,000,000
Short-term Debt, Weighted Average Interest Rate	0.40%	0.20%
Line of Credit Facility, Dividend Restrictions	730,000,000
Retained Earnings (Accumulated Deficit)	4,578,000,000	4,150,000,000
Other Restrictions on Payment of Dividends	0
DTE Energy [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio	0.50
Other outstanding letters of credit	407,000,000
DTE Electric [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio	0.51
Other outstanding letters of credit	50,000,000
DTE Gas [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio	0.48
Other outstanding letters of credit	145,000,000
Letter of Credit [Member]
Short-term Debt [Line Items]
Other outstanding letters of credit	204,000,000
Letter of Credit [Member] | DTE Energy [Member]
Short-term Debt [Line Items]
Other outstanding letters of credit	204,000,000
Letter of Credit [Member] | DTE Electric [Member]
Short-term Debt [Line Items]
Other outstanding letters of credit	0
Letter of Credit [Member] | DTE Gas [Member]
Short-term Debt [Line Items]
Other outstanding letters of credit	0
Demand Financing Agreement [Member] | DTE Energy [Member]
Short-term Debt [Line Items]
Financing Agreement, Maximum Borrowing Capacity	100,000,000
Maximum Additional Margin Financing	50,000,000
Financing Agreement, Amount Outstanding	37,000,000	138,000,000
Demand Financing Agreement Plus Letter of Credit [Member] | DTE Energy [Member]
Short-term Debt [Line Items]
Financing Agreement, Maximum Borrowing Capacity	150,000,000
Other outstanding letters of credit [Member] | Letter of Credit [Member] | DTE Energy [Member]
Short-term Debt [Line Items]
Other outstanding letters of credit	35,000,000
Demand Financing Agreement [Member] | Letter of Credit [Member] | DTE Energy [Member]
Short-term Debt [Line Items]
Financing Agreement, Maximum Borrowing Capacity	$ 50,000,000
Maximum
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio	0.65

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Organization and Basis of Presentation (Non Consolidated Variable Interest Entities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Variable Interest Entity [Line Items]
Notes receivable	$ 90	$ 102
Variable Interest Entity, NonConsolidated [Member]
Variable Interest Entity [Line Items]
Other investments	134	141
Notes receivable	$ 15	$ 8

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2014

Long-term Debt, Unclassified [Abstract]

Schedule of Long-term Debt Instruments

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

	2014			2013
	(In millions)
Mortgage bonds, notes and other
DTE Energy Debt, Unsecured
4.6% due 2016 to 2033	$	1,647		$	1,297
DTE Electric Taxable Debt, Principally Secured
4.5% due 2016 to 2044	4,824			4,286
DTE Electric Tax-Exempt Revenue Bonds (b)
5.2% due 2020 to 2030	330			558
DTE Gas Taxable Debt, Principally Secured
5.2% due 2015 to 2044	1,099			1,029
Other Long-Term Debt, Including Non-Recourse Debt	121			142
	8,021			7,312
Less amount due within one year	(161		)	(694		)
	$	7,860		$	6,618
Securitization bonds
6.6% due 2015	$	105		$	302
Less amount due within one year	(105		)	(197		)
	$	—		$	105
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, 2014 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

In 2014, the following debt was issued:

Company	Month Issued	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Energy	May	Senior Notes (a)	3.50	%	2024	$	350
DTE Electric	June	Mortgage Bonds (a)	3.77	%	2026	100
DTE Electric	June	Mortgage Bonds (a)	4.60	%	2044	150
DTE Electric	July	Mortgage Bonds (a)	3.375	%	2025	350
DTE Electric	July	Mortgage Bonds (a)	4.30	%	2044	350
DTE Energy	November	Senior Notes (a)	2.40	%	2019	300
DTE Gas	December	Mortgage Bonds (a)	4.35	%	2044	150
						$	1,750

_______________________________________

(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

In 2014, the following debt was redeemed:

Company	Month	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March	Mortgage Bonds	Various		2014	$	13
DTE Electric	March	Securitization Bonds	6.62	%	2014	100
DTE Electric	April	Tax Exempt Revenue Bonds (a)	2.35	%	2024	31
DTE Electric	April	Tax Exempt Revenue Bonds (a)	4.65	%	2028	32
DTE Gas	May	Mortgage Bonds	8.25	%	2014	80
DTE Energy	May	Senior Notes	7.625	%	2014	300
DTE Electric	June	Tax Exempt Revenue Bonds (a)	4.875	%	2029	36
DTE Electric	June	Tax Exempt Revenue Bonds (a)	6.00	%	2036	69
DTE Electric	July	Senior Notes	4.80	%	2015	200
DTE Electric	August	Senior Notes	5.40	%	2014	200
DTE Electric	August	Tax Exempt Revenue Bonds (a)	5.25	%	2029	60
DTE Electric	September	Securitization Bonds	6.62	%	2014	96
DTE Energy	Various	Other Long Term Debt	Various		2014	20
						$	1,237

_______________________________________

(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

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

	2015		2016		2017		2018		2019		2020 and Thereafter		Total
	(In millions)
Amount to mature	$	266	$	465	$	9	$	407	$	427	$	7,046	$	8,620

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Subsequent Event (Notes)

12 Months Ended

Dec. 31, 2014

Subsequent Events [Abstract]

Subsequent Event

SUBSEQUENT EVENT

In October 2014, DTE Electric executed an agreement to purchase a 732 MW simple-cycle natural gas facility in Carson City, Michigan from The LS Power Group for a total purchase price of approximately $240 million paid in cash. This facility will serve to meet the needs of approximately 260,000 additional households during peak demand. DTE Electric closed on the acquisition on January 21, 2015.

Effective upon closing, DTE Electric obtained control over and applied acquisition accounting to the acquired business. Due to the limited time since the acquisition date, the initial accounting for the business combination is incomplete. As a result, DTE Electric is unable to provide amounts recognized as of the acquisition date for major classes of assets and liabilities acquired. DTE Electric will include required information in the Quarterly Report on Form 10-Q for the period ending March 31, 2015.

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Valuation and Qualifying Accounts (Notes)

12 Months Ended

Dec. 31, 2014

Valuation and Qualifying Accounts [Abstract]

Schedule II Valuation and Qualifying Accounts

Valuation and Qualifying Accounts

	Year Ending December 31,
	2014			2013			2012
	(In millions)
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statements of Financial Position)
Balance at Beginning of Period	$	55		$	62		$	162
Additions:
Charged to costs and expenses	95			94			79
Charged to other accounts (a)	20			23			16
Deductions (b)	(116		)	(124		)	(195		)
Balance at End of Period	$	54		$	55		$	62

_______________________________________

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

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Consolidated Statements of Changes in Equity (USD $) In Millions, except Share data, unless otherwise specified	Total	Common Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Non-Controlling Interest [Member]
Beginning Balance at Dec. 31, 2011	$ 7,053	$ 3,417	$ 3,750	$ (158)	$ 44
Beginning Balance (in shares) at Dec. 31, 2011		169,247,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	618		610		8
Dividends declared on common stock	(414)		(414)
Issuance of common stock (in shares)		684,000
Issuance of common stock	39	39
Contribution of common stock to pension plan (in shares)		1,335,000
Contribution of common stock to pension plan	80	80
Benefit obligations, net of tax	(2)			(2)
Net change in unrealized losses on investments, net of tax	1			1
Foreign currency translation, net of tax	1			1
Stock-based compensation, distributions to noncontrolling interests and other (in 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 (in shares) at Dec. 31, 2012		172,352,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	668		661		7
Dividends declared on common stock	(454)		(454)
Issuance of common stock (in shares)		589,000
Issuance of common stock	39	39
Contribution of common stock to pension plan (in shares)		3,026,000
Contribution of common stock to pension plan	200	200
Benefit obligations, net of tax	22			22
Net change in unrealized losses on investments, net of tax	2			2
Foreign currency translation, net of tax	(2)			(2)
Stock-based compensation, distributions to noncontrolling interests and other (in 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 (in shares) at Dec. 31, 2013	177,087,230	177,087,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	911		905		6
Dividends declared on common stock	(476)		(476)
Repurchase of common stock (in shares)		(713,000)
Repurchase of common stock	(52)	(52)
Benefit obligations, net of tax	(18)			(18)
Net change in unrealized losses on investments, net of tax	1			1
Foreign currency translation, net of tax	(2)			(2)
Stock-based compensation, distributions to noncontrolling interests and other (in shares)		617,000
Stock-based compensation, distributions to noncontrolling interests and other	24	49	(1)		(24)
Ending Balance at Dec. 31, 2014	$ 8,342	$ 3,904	$ 4,578	$ (155)	$ 15
Ending Balance (in shares) at Dec. 31, 2014	176,991,231	176,991,000

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Basis of Presentation

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.

Principles of Consolidation

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 plants. 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 consolidated when the Company is the primary beneficiary. In addition, we have interests in certain VIEs through which 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 and sale contracts. As of December 31, 2014, the carrying amount of assets and liabilities in the Consolidated Statements of Financial Position that relate to its variable interests under long-term purchase and sale contracts are predominately related to working capital accounts and generally represent the amounts owed by or to the Company for the deliveries associated with the current billing cycle under the contracts. The Company has not provided any significant 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 and sale 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, 2014 and 2013. 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

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.

For further discussion of recovery mechanisms authorized by the MPSC see Note 8 to the Consolidated Financial Statements, "Regulatory Matters".

Non-utility businesses recognize revenues as services are provided and products are delivered. For discussion of derivative contracts see Note 12 to the Consolidated Financial Statements, "Financial and Other Derivative Instruments".

Accounting For ISO Transactions

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.

Changes in Accumulated Other Comprehensive Loss

Changes in Accumulated Other Comprehensive 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. The amounts recorded to accumulated other comprehensive loss include unrealized gains and losses from derivatives accounted for as cash flow hedges, unrealized gains and losses on available-for-sale securities and 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 foreign currency translation adjustments.

Cash, Cash Equivalents and Restricted Cash

Cash, 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

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 $773 million and $815 million are included in customer accounts receivable at December 31, 2014 and 2013, 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

Inventories

The Company generally values inventory at average cost.

Natural gas inventory of $43 million and $4 million as of December 31, 2014 and 2013, respectively, at DTE Gas is determined using the last-in, first-out (LIFO) method. At December 31, 2014, the replacement cost of gas remaining in storage exceeded the LIFO cost by $110 million. At December 31, 2013, the replacement cost of gas remaining in storage exceeded the LIFO cost by $170 million.

Property, Retirement and Maintenance, Depreciation, Depletion and Amortization

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

Property is stated at cost and includes construction-related labor, materials, overheads and AFUDC for utility property. 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 $16 million and $26 million of expenses related to Fermi 2 refueling outages were accrued at December 31, 2014 and 2013, respectively. Amounts are accrued on a pro-rata basis, generally over an 18-month period, that coincides with scheduled refueling outages at Fermi 2. This accrual of outage costs matches the regulatory recovery of these costs in rates set by the MPSC. See Note 8 to the Consolidated Financial Statements, "Regulatory Matters".

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, ranging from 3 to 15 years.

Long-Lived Assets

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 27 years.

Deferred Debt Costs

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

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 11 of the Consolidated Financial Statements, "Fair Value".

Government Grants

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

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

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.

Regulatory Matters

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 Taxes

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 are determined on an individual company basis and recognize 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.

Fair Value Measurement

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, 2014 and 2013. 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

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 hold exchange-traded equity or debt securities and are valued based on stated NAVs. 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

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.

Fair Value Transfer

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

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 as assumptions about the remaining life of the loans and credit risk. Depending on the information available, other valuation techniques may be used that rely on internal assumptions and models. Valuation policies and procedures are determined by DTE Energy's Treasury Department which reports to the Company's Vice President and Treasurer.

Derivatives

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 electricity, 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

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 $7 million and $19 million at December 31, 2014 and 2013, respectively, which could be used to offset net derivative liabilities. Letters of credit received from third parties which could be used to offset our net derivative assets were approximately $5 million and $1 million at December 31, 2014 and 2013, respectively. 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

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 MTM 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 MTM method with unrealized and realized gains and losses for sales recorded in Operating revenue and purchases recorded in Fuel, purchased power and gas.

Stock-Based Compensation

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

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Fair Value (Fair Value of Nuclear Decommissioning Trust Fund Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Schedule of Available-for-sale Securities [Line Items]
Decommissioning Fund Investments	$ 1,241	$ 1,191
Fermi 2 [Member]
Schedule of Available-for-sale Securities [Line Items]
Decommissioning Fund Investments	1,221	1,172
Fermi 1 [Member]
Schedule of Available-for-sale Securities [Line Items]
Decommissioning Fund Investments	3	3
Low Level Radioactive Waste [Member]
Schedule of Available-for-sale Securities [Line Items]
Decommissioning Fund Investments	17	16
Nuclear Decommissioning Trust Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Decommissioning Fund Investments	$ 1,241	$ 1,191

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Retirement Benefits and Trusteed Assets (OPEB - Postretirement Cost Inclusions) (Details) (Other Postretirement Benefit Plan, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 34	$ 47	$ 68
Interest cost	89	88	120
Expected return on plan assets	(122)	(110)	(92)
Amortization of Net Loss	20	64	80
Amortization of Prior Service Cost (Credit)	(144)	(131)	(25)
Net pension cost	$ (123)	$ (42)	$ 151

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation

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

	2014			2013			2012
	(In millions)
Income before income taxes	$	1,275		$	922		$	960
Income tax expense at 35% statutory rate	$	446		$	323		$	336
Production tax credits	(119		)	(68		)	(49		)
Investment tax credits	(6		)	(6		)	(6		)
Depreciation	(4		)	(4		)	(4		)
AFUDC - Equity	(7		)	(5		)	(4		)
Employee Stock Ownership Plan dividends	(4		)	(4		)	(4		)
Domestic production activities deduction	—			(14		)	(14		)
State and local income taxes, net of federal benefit	51			37			37
Enactment of New York Corporate Income Tax Legislation, net of federal benefit	8			—			—
Other, net	(1		)	(5		)	(6		)
Income tax expense	$	364		$	254		$	286
Effective income tax rate	28.5		%	27.5		%	29.8		%

Schedule of Components of Income Tax Expense (Benefit)

Components of income tax expense were as follows:

	2014			2013		2012
	(In millions)
Current income tax expense (benefit)
Federal	$	(16	)	$	74	$	190
State and other income tax	24			16		49
Total current income taxes	8			90		239
Deferred income tax expense
Federal	289			122		39
State and other income tax	67			42		8
Total deferred income taxes	356			164		47
Total income taxes from continuing operations	364			254		286
Discontinued operations	—			—		(29		)
Total	$	364		$	254	$	257

Schedule of Deferred Tax Assets and Liabilities

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

	2014			2013
	(In millions)
Property, plant and equipment	$	(3,832	)	$	(3,372	)
Securitized regulatory assets	(2		)	(127		)
Tax credit carry-forwards	296			266
Pension and benefits	(152		)	(30		)
State net operating loss and credit carry-forwards	39			43
Other	(19		)	(92		)
	(3,670		)	(3,312		)
Less valuation allowance	(31		)	(37		)
	$	(3,701	)	$	(3,349	)
Current deferred income tax assets (liabilities)	$	75		$	(28	)
Long-term deferred income tax liabilities	(3,776		)	(3,321		)
	$	(3,701	)	$	(3,349	)
Deferred income tax assets	$	861		$	934
Deferred income tax liabilities	(4,562		)	(4,283		)
	$	(3,701	)	$	(3,349	)

Schedule of Unrecognized Tax Benefits Roll Forward

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

	2014			2013			2012
	(In millions)
Balance at January 1	$	10		$	11		$	48
Reductions for tax positions of prior years	—			—			(2		)
Additions for tax positions of current year	—			—			1
Settlements	—			—			(30		)
Lapse of statute of limitations	(1		)	(1		)	(6		)
Balance at December 31	$	9		$	10		$	11

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Valuation and Qualifying Accounts (Tables)

12 Months Ended

Dec. 31, 2014

Valuation and Qualifying Accounts [Abstract]

Summary of Valuation Allowance

Valuation and Qualifying Accounts

	Year Ending December 31,
	2014			2013			2012
	(In millions)
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statements of Financial Position)
Balance at Beginning of Period	$	55		$	62		$	162
Additions:
Charged to costs and expenses	95			94			79
Charged to other accounts (a)	20			23			16
Deductions (b)	(116		)	(124		)	(195		)
Balance at End of Period	$	54		$	55		$	62

_______________________________________

(a) Collection of accounts previously written off.

(b) Uncollectible accounts written off.

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Regulatory Matters (Details Textuals) (USD $)	12 Months Ended	0 Months Ended	3 Months Ended
	Dec. 31, 2014	Dec. 19, 2014	Mar. 31, 2013	Dec. 31, 2013	Sep. 30, 2014	Jul. 30, 2012	Jan. 01, 2014	Sep. 30, 2012	Sep. 26, 2014	Aug. 31, 2013	Nov. 30, 2014
Regulatory Assets [Line Items]
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
Regulatory liabilities	$ 820,000,000			$ 1,164,000,000
Refundable Revenue Decoupling [Member]
Regulatory Assets [Line Items]
Regulatory liabilities	67,000,000			127,000,000
Electric [Member]
Regulatory Assets [Line Items]
Fermi 2 production level of full capacity						68.00%
Maximum of challenged Fermi 2 outage charges					32,000,000
Electric [Member] | Refundable Revenue Decoupling [Member]
Regulatory Assets [Line Items]
Regulatory liabilities								127,000,000
Monthly amount to amortize from liability to income							10,600,000
MPSC [Member] | Electric [Member]
Regulatory Assets [Line Items]
Public utilities, requested rate increase (decrease)		370,000,000
Rate increase previously authorized by the MPSC challenged by Court of Appeals reopened by the MPSC										11,000,000
Approved recovery amount for customer 360									215,000,000
Approved amortization period for customer 360 recovery	15 years
PSCR under-recovery from 2 plan years prior			87,000,000
PSCR under-recovery from 3 plan years prior			148,000,000
MPSC [Member] | Gas [Member]
Regulatory Assets [Line Items]
Infrastructure recovery mechanism surcharge											$ 47,000,000

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Consolidated Statements of Operations (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Statement [Abstract]
Operating Revenues	$ 12,301	$ 9,661	$ 8,791
Operating Expenses
Fuel, purchased power and gas	5,879	4,055	3,296
Operation and maintenance	3,347	2,978	2,892
Depreciation, depletion and amortization	1,145	1,094	995
Taxes other than income	352	340	332
Asset (gains) losses and impairments, net	(12)	(9)	(3)
Total operating expenses	10,711	8,458	7,512
Operating Income	1,590	1,203	1,279
Other (Income) and Deductions
Interest expense	429	436	440
Interest income	(10)	(9)	(10)
Other income	(196)	(201)	(173)
Other expenses	92	55	62
Total Other (Income) and Deductions	315	281	319
Income Before Income Taxes	1,275	922	960
Income Tax Expense	364	254	286
Income from Continuing Operations	911	668	674
Loss from Discontinued Operations, net of tax	0	0	(56)
Net Income	911	668	618
Less: Net Income Attributable to Noncontrolling Interests	6	7	8
Net Income Attributable to DTE Energy Company	$ 905	$ 661	$ 610
Basic Earnings per Common Share
Income from continuing operations (in dollars per share)	$ 5.11	$ 3.76	$ 3.89
Loss from discontinued operations, net of tax (in dollars per share)	$ 0	$ 0	$ (0.33)
Total (in dollars per share)	$ 5.11	$ 3.76	$ 3.56
Diluted Earnings per Common Share
Income from continuing operations (in dollars per share)	$ 5.10	$ 3.76	$ 3.88
Loss from discontinued operations, net of tax (in dollars per share)	$ 0	$ 0	$ (0.33)
Total (in dollars per share)	$ 5.10	$ 3.76	$ 3.55
Weighted Average Common Shares Outstanding
Basic (in shares)	177	175	171
Diluted (in shares)	177	175	172
Dividends Declared per Common Share	$ 2.69	$ 2.59	$ 2.42

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Preferred and Preferenced Securities (Tables)

12 Months Ended

Dec. 31, 2014

Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Schedule of Preferred and Preference Securities

As of December 31, 2014, 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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Long-Term Debt (Scheduled Debt Maturities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Maturities of Long-term Debt [Abstract]
2015	$ 266
2016	465
2017	9
2018	407
2019	427
2020 and Thereafter	7,046
Long-term Debt, Total	$ 8,620

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Subsequent Event (Details) (Electric [Member], Subsequent Event [Member], USD $) In Millions, unless otherwise specified	0 Months Ended
	Jan. 21, 2015
Electric [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Payments to acquire business	$ 240

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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, 2014	Dec. 31, 2013
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$ 40	$ (1)
Pension Plan
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Plan assets at fair value, beginning of year	3,720	3,223
Total realized/unrealized gains (losses)	301	445
Plan assets at fair value, end of year	3,981	3,720
Pension Plan | Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Plan assets at fair value, beginning of year	565	518
Total realized/unrealized gains (losses)	38	44
Purchases	53	31
Sales	(31)	(28)
Plan assets at fair value, end of year	625	565
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	32	41
Pension Plan | Hedge Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Plan assets at fair value, end of year	759	733
Pension Plan | Hedge Funds [Member] | Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Plan assets at fair value, beginning of year	395	339
Total realized/unrealized gains (losses)	22	40
Purchases	22	16
Sales	(1)	0
Plan assets at fair value, end of year	438	395
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	21	38
Pension Plan | Private Equity Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Plan assets at fair value, end of year	187	170
Pension Plan | Private Equity Funds [Member] | Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Plan assets at fair value, beginning of year	170	179
Total realized/unrealized gains (losses)	16	4
Purchases	31	15
Sales	(30)	(28)
Plan assets at fair value, end of year	187	170
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$ 11	$ 3

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Consolidated Statements of Financial Position (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current Assets:
Allowance for doubtful accounts	$ 54	$ 55
Stockholders' Equity:
Common stock, par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized (in shares)	400,000,000	400,000,000
Common stock, shares issued (in shares)	176,991,231	177,087,230
Common stock, shares outstanding (in shares)	176,991,231	177,087,230

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Long-Term Debt (Debt Issuances) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Debt Instrument [Line Items]
Debt face amount	$ 1,750
DTE Energy [Member] | Senior Notes [Member] | May 2014 3.50% Senior Notes Maturing in 2024 [Member]
Debt Instrument [Line Items]
Debt instrument stated interest rate	3.50%
Debt face amount	350
DTE Energy [Member] | Senior Notes [Member] | November 2014 2.40% Senior Notes Maturing in 2019 [Member]
Debt Instrument [Line Items]
Debt instrument stated interest rate	2.40%
Debt face amount	300
Electric [Member] | Mortgages [Member] | June 2014 3.77% Mortgage Bonds Maturing in 2026 [Member]
Debt Instrument [Line Items]
Debt instrument stated interest rate	3.77%
Debt face amount	100
Electric [Member] | Mortgages [Member] | June 2014 4.60% Mortgage Bonds Maturing in 2044 [Member]
Debt Instrument [Line Items]
Debt instrument stated interest rate	4.60%
Debt face amount	150
Electric [Member] | Mortgages [Member] | July 2014 3.375% Mortgage Bonds Maturing in 2025 [Member]
Debt Instrument [Line Items]
Debt instrument stated interest rate	3.375%
Debt face amount	350
Electric [Member] | Mortgages [Member] | July 2014 4.30% Mortgage Bonds Maturing in 2044 [Member]
Debt Instrument [Line Items]
Debt instrument stated interest rate	4.30%
Debt face amount	350
Gas [Member] | Mortgages [Member] | December 2014 4.35% Mortgage Bonds Maturing in 2044 [Member]
Debt Instrument [Line Items]
Debt instrument stated interest rate	4.35%
Debt face amount	$ 150

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Significant Accounting Policies (Future Amortization Expense Intangible Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2015	$ 12
2016	11
2017	8
2018	8
2019	$ 6

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Short-Term Credit Arrangements and Borrowings (Details) (USD $)	Dec. 31, 2014
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,025,000,000
Amounts outstanding	602,000,000
Net availability	1,423,000,000
DTE Energy [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,425,000,000
Amounts outstanding	407,000,000
Net availability	1,018,000,000
DTE Electric [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	300,000,000
Amounts outstanding	50,000,000
Net availability	250,000,000
DTE Gas [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	300,000,000
Amounts outstanding	145,000,000
Net availability	155,000,000
Letter of Credit [Member]
Line Of Credit Facility [Line Items]
Amounts outstanding	204,000,000
Letter of Credit [Member] | DTE Energy [Member]
Line Of Credit Facility [Line Items]
Amounts outstanding	204,000,000
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 February 2015 [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	100,000,000
Letter of Credit [Member] | Unsecured letter of credit, expiring in February 2015 [Member] | DTE Energy [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	100,000,000
Letter of Credit [Member] | Unsecured letter of credit, expiring in February 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 February 2015 [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	125,000,000
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	125,000,000
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	1,800,000,000
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	1,200,000,000
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	300,000,000
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	300,000,000
Commercial Paper [Member]
Line Of Credit Facility [Line Items]
Amounts outstanding	398,000,000
Commercial Paper [Member] | DTE Energy [Member]
Line Of Credit Facility [Line Items]
Amounts outstanding	203,000,000
Commercial Paper [Member] | DTE Electric [Member]
Line Of Credit Facility [Line Items]
Amounts outstanding	50,000,000
Commercial Paper [Member] | DTE Gas [Member]
Line Of Credit Facility [Line Items]
Amounts outstanding	$ 145,000,000

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Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2014

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures

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
	(In millions)
Operating Revenues	$	55
Operation and maintenance	24
Depreciation, depletion and amortization	23
Taxes other than income	4
Asset (gains) losses, net	83
	134
Operating Loss	(79		)
Other (Income) and Deductions	6
Loss Before Income Taxes	(85		)
Income Tax Benefit	(29		)
Net Loss Attributable to DTE Energy Company	$	(56	)

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Stock-Based Compensation (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Authorized limit of common stock shares	14,500,000
Performance units price per unit	1.00
Weighted Average Remaining Contractual Term	3 years 4 months 27 days
Options vested (in shares)	0
Options grants in period	$ 0	$ 0	$ 0
Options, exercises, intrinsic value	$ 11,000,000	$ 12,000,000	$ 25,000,000
Stock option expense	$ 0	$ 0	$ 700,000
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum award per employee	500,000
Award expiration period	10 years
Award vesting period	3 years
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum award per employee	150,000
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum award per employee	300,000
Performance Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum award per employee	1,000,000

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Property, Plant and Equipment (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Public Utility Property, Plant and Equipment [Line Items]
AFUDC capitalized	$ 37	$ 33
Capitalized computer software amortization	77	71	68
Capitalized computer software gross	668	611
Capitalized computer software accumulated amortization	335	323
Capital leased assets gross	35	35
Capital leases, accumulated depreciation	$ 27	$ 21
Electric [Member]
Public Utility Property, Plant and Equipment [Line Items]
Disclosure of composite depreciation rate for plants in service	3.40%	3.40%	3.30%
Gas [Member]
Public Utility Property, Plant and Equipment [Line Items]
Disclosure of composite depreciation rate for plants in service	2.40%	2.40%	2.40%
Minimum [Member]
Public Utility Property, Plant and Equipment [Line Items]
Property plant and equipment, useful life	3 years
Finite-lived intangible asset, useful life	1 year
Maximum
Public Utility Property, Plant and Equipment [Line Items]
Property plant and equipment, useful life	55 years
Finite-lived intangible asset, useful life	27 years
Computer Software, Intangible Asset [Member] | Minimum [Member]
Public Utility Property, Plant and Equipment [Line Items]
Finite-lived intangible asset, useful life	3 years
Computer Software, Intangible Asset [Member] | Maximum
Public Utility Property, Plant and Equipment [Line Items]
Finite-lived intangible asset, useful life	15 years

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Preferred and Preferenced Securities (Notes)

12 Months Ended

Dec. 31, 2014

Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Preferred and Preference Securities

PREFERRED AND PREFERENCE SECURITIES

As of December 31, 2014, 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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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment [Abstract]

Schedule of Property, Plant and Equipment

Summary of property by classification as of December 31:

	2014			2013
	(In millions)
Property, Plant and Equipment
DTE Electric
Generation	$	11,641		$	11,127
Distribution	8,164			7,603
Total DTE Electric	19,805			18,730
DTE Gas
Distribution	2,946			2,834
Storage	448			431
Other	863			836
Total DTE Gas	4,257			4,101
Non-utility and other	2,476			2,292
Total	26,538			25,123
Less Accumulated Depreciation, Depletion and Amortization
DTE Electric
Generation	(4,149		)	(4,004		)
Distribution	(3,067		)	(2,947		)
Total DTE Electric	(7,216		)	(6,951		)
DTE Gas
Distribution	(1,130		)	(1,129		)
Storage	(142		)	(138		)
Other	(363		)	(338		)
Total DTE Gas	(1,635		)	(1,605		)
Non-utility and other	(867		)	(767		)
Total	(9,718		)	(9,323		)
Net Property, Plant and Equipment	$	16,820		$	15,800

The average estimated useful life for each major class of utility property, plant and equipment as of December 31, 2014 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, 2014
DTE Energy [Member]
Preferred and Preferenced Securities [Line Items]
Preferred stock, par value (in dollars per share)	$ 0
Preferred stock, shares authorized (in shares)	5,000,000
DTE Electric [Member]
Preferred and Preferenced Securities [Line Items]
Preferred stock, par value (in dollars per share)	$ 100
Preferred stock, shares authorized (in shares)	6,747,484
Preference stock, par value (in dollars per share)	$ 1
Preference stock shares authorized (in shares)	30,000,000
DTE Gas [Member]
Preferred and Preferenced Securities [Line Items]
Preferred stock, par value (in dollars per share)	$ 1
Preferred stock, shares authorized (in shares)	7,000,000
Preference stock, par value (in dollars per share)	$ 1
Preference stock shares authorized (in shares)	4,000,000

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Stock-Based Compensation (Components of Stock Based Compensation) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Components of stock based-compensation [Abstract]
Compensation expense	$ 103	$ 99	$ 83
Employee Service Share-based Compensation Equity and Liability, Tax	40	38	33
Employee Service Share-based Compensation, Allocation of Recognized Period Costs Liability and Equity, Capitalized Amount	$ 16	$ 15	$ 5

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Capital and Operating Leases (Notes)

12 Months Ended

Dec. 31, 2014

Leases [Abstract]

Capital and Operating Leases

CAPITAL AND OPERATING LEASES

Lessee  - Operating Lease — The Company leases various assets under 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, 2014 were:

	Operating Leases
	(In millions)
2015	$	42
2016	34
2017	28
2018	23
2019	14
Thereafter	78
Total minimum lease payments	$	219

Rental expense for operating leases was $38 million in 2014, $34 million in 2013 and $36 million in 2012.

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 two energy services agreements, a portion of which are accounted for as capital leases. One agreement expires in 2021. The other 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, 2014, were as follows:

	Capital Leases
	(In millions)
2015	$	12
2016	13
2017	13
2018	13
2019	10
Thereafter	9
Total minimum future lease receipts	70
Residual value of leased pipeline	40
Less unearned income	(34		)
Net investment in capital lease	76
Less current portion	(5		)
	$	71

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Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning balance	$ 1,827
Accretion	112
Liabilities incurred	11
Liabilities settled	(12)
Revision in estimated cash flows	24
Asset retirement obligations, ending balance	$ 1,962

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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, 2014	Dec. 31, 2013	Dec. 31, 2012
Amounts recognized in Regulatory assets (see Note 8)
Regulatory Assets	$ 3,727	$ 2,863
Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Accumulated benefit obligation, end of year	4,853	4,068
Change in accumulated postretirement benefit obligation
Benefit obligation, beginning of year	4,380	4,729
Service cost	83	94	82
Interest cost	212	192	204
Plan amendments	(7)	(3)
Actuarial (gain) loss	836	(400)
Benefits paid	(235)	(232)
Benefit obligation, end of year	5,269	4,380	4,729
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Plan assets at fair value, beginning of year	3,720	3,223
Actual return on plan assets	301	445
Company contributions	195	284
Benefits paid	(235)	(232)
Plan assets at fair value, end of year	3,981	3,720	3,223
Funded status of the plans	(1,288)	(660)
Amount recorded as:
Current liabilities	(8)	(7)
Noncurrent liabilities	(1,280)	(653)
Pension and Other Postretirement Defined Benefit Plans, Liabilities	(1,288)	(660)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	194	174
Prior service (credit)	(1)	(1)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax	193	173
Amounts recognized in Regulatory assets (see Note 8)
Net actuarial loss	2,285	1,654
Prior service credit	(1)	6
Regulatory Assets	$ 2,284	$ 1,660

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Activities
Net Income	$ 911	$ 668	$ 618
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	1,145	1,094	1,018
Nuclear fuel amortization	48	38	29
Allowance for equity funds used during construction	(21)	(15)	(13)
Deferred income taxes	356	164	47
Loss on sale of non-utility business	0	0	83
Asset (gains) losses and impairments, net	(4)	(8)	1
Changes in assets and liabilities:
Accounts receivable, net	48	(154)	52
Inventories	(177)	123	35
Accounts payable	128	14	40
Accrued pension obligation	627	(644)	280
Accrued postretirement obligation	165	(526)	(323)
Derivative assets and liabilities	(199)	107	53
Regulatory assets and liabilities	(1,177)	1,269	278
Other assets	(30)	(24)	55
Other liabilities	19	48	(44)
Net cash from operating activities	1,839	2,154	2,209
Investing Activities
Plant and equipment expenditures — utility	(1,784)	(1,534)	(1,451)
Plant and equipment expenditures — non-utility	(265)	(342)	(369)
Proceeds from sale of non-utility business	0	0	255
Proceeds from sale of assets	45	36	38
Acquisition, net of cash acquired	0	0	(198)
Proceeds from sale of nuclear decommissioning trust fund assets	1,146	1,118	759
Investment in nuclear decommissioning trust funds	(1,156)	(1,134)	(764)
Other	(46)	(50)	(39)
Net cash used for investing activities	(2,060)	(1,906)	(1,769)
Financing Activities
Issuance of long-term debt, net of issuance costs	1,736	1,234	759
Redemption of long-term debt	(1,237)	(961)	(639)
Short-term borrowings, net	267	(109)	(179)
Issuance of common stock	0	39	39
Repurchase of common stock	(52)	0	0
Dividends on common stock	(470)	(445)	(407)
Other	(27)	(19)	(16)
Net cash from (used for) financing activities	217	(261)	(443)
Net Decrease in Cash and Cash Equivalents	(4)	(13)	(3)
Cash and Cash Equivalents at Beginning of Period	52	65	68
Cash and Cash Equivalents at End of Period	48	52	65
Supplemental disclosure of cash information
Cash paid (received) for: Interest (net of interest capitalized)	415	418	438
Cash paid (received) for: Income taxes	(35)	121	173
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Plant and equipment expenditures in accounts payable	$ 212	$ 329	$ 235

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Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net Income	$ 911	$ 668	$ 618
Other comprehensive income (loss), net of tax:
Benefit obligations, net of taxes of $(9), $13 and $(1), respectively	(18)	22	(2)
Net unrealized gains on investments during the period, net of taxes of $1, $1 and $1, respectively	1	2	1
Foreign currency translation, net of taxes of $(2), $(1) and $—, respectively	(2)	(2)	1
Other comprehensive income	(19)	22	0
Comprehensive income	892	690	618
Less comprehensive income attributable to noncontrolling interests	6	7	8
Comprehensive income attributable to DTE Energy Company	$ 886	$ 683	$ 610

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Income Taxes (Notes)

12 Months Ended

Dec. 31, 2014

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:

	2014			2013			2012
	(In millions)
Income before income taxes	$	1,275		$	922		$	960
Income tax expense at 35% statutory rate	$	446		$	323		$	336
Production tax credits	(119		)	(68		)	(49		)
Investment tax credits	(6		)	(6		)	(6		)
Depreciation	(4		)	(4		)	(4		)
AFUDC - Equity	(7		)	(5		)	(4		)
Employee Stock Ownership Plan dividends	(4		)	(4		)	(4		)
Domestic production activities deduction	—			(14		)	(14		)
State and local income taxes, net of federal benefit	51			37			37
Enactment of New York Corporate Income Tax Legislation, net of federal benefit	8			—			—
Other, net	(1		)	(5		)	(6		)
Income tax expense	$	364		$	254		$	286
Effective income tax rate	28.5		%	27.5		%	29.8		%

Components of income tax expense were as follows:

	2014			2013		2012
	(In millions)
Current income tax expense (benefit)
Federal	$	(16	)	$	74	$	190
State and other income tax	24			16		49
Total current income taxes	8			90		239
Deferred income tax expense
Federal	289			122		39
State and other income tax	67			42		8
Total deferred income taxes	356			164		47
Total income taxes from continuing operations	364			254		286
Discontinued operations	—			—		(29		)
Total	$	364		$	254	$	257

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:

	2014			2013
	(In millions)
Property, plant and equipment	$	(3,832	)	$	(3,372	)
Securitized regulatory assets	(2		)	(127		)
Tax credit carry-forwards	296			266
Pension and benefits	(152		)	(30		)
State net operating loss and credit carry-forwards	39			43
Other	(19		)	(92		)
	(3,670		)	(3,312		)
Less valuation allowance	(31		)	(37		)
	$	(3,701	)	$	(3,349	)
Current deferred income tax assets (liabilities)	$	75		$	(28	)
Long-term deferred income tax liabilities	(3,776		)	(3,321		)
	$	(3,701	)	$	(3,349	)
Deferred income tax assets	$	861		$	934
Deferred income tax liabilities	(4,562		)	(4,283		)
	$	(3,701	)	$	(3,349	)

Tax credit carry forwards include $29 million of general business credits that expire through 2034 and $267 million of alternative minimum tax credits that may be carried forward indefinitely. The alternative minimum tax credits are production tax credits earned prior to 2006 but not utilized. The majority of these alternative minimum tax credits were generated from projects that had received a private letter ruling (PLR) from the 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 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 $39 million and $43 million at December 31, 2014 and 2013, respectively. The state net operating loss and credit carry-forwards expire from 2015 through 2034. The Company has recorded valuation allowances at December 31, 2014 and 2013 of approximately $31 million and $37 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:

	2014			2013			2012
	(In millions)
Balance at January 1	$	10		$	11		$	48
Reductions for tax positions of prior years	—			—			(2		)
Additions for tax positions of current year	—			—			1
Settlements	—			—			(30		)
Lapse of statute of limitations	(1		)	(1		)	(6		)
Balance at December 31	$	9		$	10		$	11

The Company had $2 million of unrecognized tax benefits at December 31, 2014 and 2013, 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 $6 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 at December 31, 2014 and 2013. The Company had no accrued penalties pertaining to income taxes. The Company recognized interest expense (income) related to income taxes of a nominal amount in 2014 and 2013 and $(1) million in 2012.

In 2014, the Company settled a federal tax audit for the 2012 tax year. The Company's federal income tax returns for 2013 and subsequent years remain subject to examination by the IRS. The Company's MBT and MCIT 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.

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Capital and Operating Leases (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Leases [Abstract]
Rent expense	$ 38	$ 34	$ 36
Pipeline System Lease [Member]
Schedule of Lessor Capital Leases [Line Items]
Lessor capital lease renewal terms	5 years
Percent ownership in pipeline	40.00%
Minimum [Member] | Energy Services Agreement [Member]
Schedule of Lessor Capital Leases [Line Items]
Lessor capital lease renewal terms	3 years
Maximum | Energy Services Agreement [Member]
Schedule of Lessor Capital Leases [Line Items]
Lessor capital lease renewal terms	5 years

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Long-Term Debt (Long Term Debt Outstanding and Weighted Average Interest Rates) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term Debt, Total	$ 8,620
Long Term Debt excluding Securitization, Debentures and Capital Leases	8,021	7,312
Less Amount of Long-term Debt due within one year	(161)	(694)
Long-term Debt, Excluding Current Maturities	7,860	6,618
Less Amount of Securitization Bonds due within one year	(105)	(197)
Securitization bonds, Excluding Current Maturities	0	105
Junior Subordinated Notes, Noncurrent	480	480
6.6% Securitization Bonds Due 2015 [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	6.60%
Debt Instrument, Maturity Date	Mar. 15, 2015
Long-term Securitization Bond	105	302
Junior Subordinated Debentures [Member] | 6.5% Junior Subordinated Debentures Due 2061 [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 [Member] | 5.25% Junior Subordinated Debentures Due 2062 [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] | 4.6% Unsecured Debt Due 2016 to 2033 [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	4.60%
Debt Instrument, Maturity Date Range, Start	Jun. 01, 2016
Debt Instrument, Maturity Date Range, End	Apr. 15, 2033
Long-term Debt, Total	1,647	1,297
DTE Electric [Member] | Secured Debt [Member] | 4.5% Taxable Debt, Principally Secured Due 2016 to 2044 [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	4.50%
Debt Instrument, Maturity Date Range, Start	Mar. 31, 2016
Debt Instrument, Maturity Date Range, End	Jun. 01, 2044
Long-term Debt, Total	4,824	4,286
DTE Electric [Member] | Tax Exempt Revenue Bonds [Member] | 5.2% Tax Exempt Revenue Bonds Due 2020 to 2030 [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.20%
Debt Instrument, Maturity Date Range, Start	Jul. 01, 2020
Debt Instrument, Maturity Date Range, End	Dec. 01, 2030
Long-term Debt, Total	330	558
DTE Gas [Member] | Secured Debt [Member] | 5.2% Taxable Debt, Principally Secured Due 2015 to 2044 [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	5.20%
Debt Instrument, Maturity Date Range, Start	Sep. 01, 2015
Debt Instrument, Maturity Date Range, End	Dec. 15, 2044
Long-term Debt, Total	1,099	1,029
DTE Gas [Member] | Long Term Debt, Other [Member]
Debt Instrument [Line Items]
Long-term Debt, Total	$ 121	$ 142

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Financial and Other Derivative Instruments (Cumulative Gross Volume of Derivative Contracts Outstanding) (Details) (CAD)	Dec. 31, 2014 MMBTU
Natural Gas Commodity Contract [Member]
Derivative [Line Items]
Derivative outstanding, energy	895,599,953
Electricity Commodity Contract [Member]
Derivative [Line Items]
Derivative outstanding, energy	11,296,153
Foreign Currency Exchange Contract [Member]
Derivative [Line Items]
Foreign Currency Exchange (Canadian dollars)	63,022,462

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Retirement Benefits and Trusteed Assets (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Transfers into Level 3	$ 0	$ 1,000,000
Transfers out of Level 3	2,000,000	0
Defined contribution plan, cost recognized (less than $1 million in 2012)	48,000,000	41,000,000	37,000,000
Grantor Trust Balance	18,000,000	17,000,000
Retirement Savings Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Company contribution to employee savings plan	4.00%
Retirement Savings Plan [Member] | DTE Gas Represented Employees
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Company contribution to employee savings plan	8.00%
Qualified Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Company contributions	188,000,000
Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Company contributions	195,000,000	284,000,000
Expected return on plan assets	7.75%
Transfers into Level 3	0	0
Transfers out of Level 3	0	0
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.12%	4.95%	4.15%
Pension Plan | Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Estimated future employer contributions in next fiscal year	180,000,000
Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Company contributions	24,000,000	264,000,000
Expected return on plan assets	8.00%
Transfers into Level 3	0	0
Transfers out of Level 3	0	0
Annual allocation to Retiree Reimbursement Account Per Participant, Retired on or before January 1, 2013	3,570	3,500
Annual allocation to Retiree Reimbursement Account Per Participant, Retired after January 1, 2013	3,315	3,250
Retiree Health Care Allowance will increase at lower of the rate of medical inflation or a set percentage	2.00%
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components	8,000,000
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	108,000,000
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components	7,000,000
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	94,000,000
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.10%	4.95%	4.15%	4.30%
Other Postretirement Benefit Plan | Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Estimated future employer contributions in next fiscal year	200,000,000
Retiree Healthcare Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined contribution plan, cost recognized (less than $1 million in 2012)	$ 4,000,000	$ 2,000,000	$ 1,000,000

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Segment and Related Information (Details Textuals)	Dec. 31, 2014 customers
Segment Reporting [Abstract]
Number of electric utility customers	2,100,000
Number of gas utility customers	1,200,000

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Retirement Benefits and Trusteed Assets (OPEB - Target Allocations of Plan Assets) (Details) (Other Postretirement Benefit Plan)	12 Months Ended
	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Percentage of Assets	100.00%
US Large Cap Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Percentage of Assets	17.00%
US Small Cap and Mid Cap Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Percentage of Assets	4.00%
Non US Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Percentage of Assets	20.00%
Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Percentage of Assets	25.00%
Hedge Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Percentage of Assets	20.00%
Private Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Percentage of Assets	14.00%

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Document and Entity Information Document and Entity Information (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Jan. 30, 2015	Jun. 30, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	DTE ENERGY CO
Entity Central Index Key	0000936340
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		177,229,483
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 13.3

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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, 2014
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Number of Options (in shares)	444,278.000000
Weighted Average Exercise Price (in dollars per share)	$ 43.56
Weighted Average Remaining Contractual Life (Years)	3 years 4 months 27 days
$27.00 - $38.00 [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 (in shares)	25,857
Weighted Average Exercise Price (in dollars per share)	$ 27.70
Weighted Average Remaining Contractual Life (Years)	4 years 1 month 28 days
$38.01 - $42.00 [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 (in shares)	82,834
Weighted Average Exercise Price (in dollars per share)	$ 41.77
Weighted Average Remaining Contractual Life (Years)	3 years 1 month 28 days
$42.01 - $45.00 [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 (in shares)	221,487
Weighted Average Exercise Price (in dollars per share)	$ 43.93
Weighted Average Remaining Contractual Life (Years)	4 years 22 days
$45.01 - $50.00 [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 (in shares)	114,100
Weighted Average Exercise Price (in dollars per share)	$ 47.75
Weighted Average Remaining Contractual Life (Years)	2 years 1 month 25 days

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Earnings Per Share (Notes)

12 Months Ended

Dec. 31, 2014

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:

	2014		2013		2012
	(In millions, expect per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	905	$	661	$	610
Average number of common shares outstanding	177		175		171
Weighted average net restricted shares outstanding	—		1		1
Dividends declared — common shares	$	475	$	453	$	413
Dividends declared — net restricted shares	1		1		1
Total distributed earnings	$	476	$	454	$	414
Net income less distributed earnings	$	429	$	207	$	196
Distributed (dividends per common share)	$	2.69	$	2.59	$	2.42
Undistributed	2.42		1.17		1.14
Total Basic Earnings per Common Share	$	5.11	$	3.76	$	3.56
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	905	$	661	$	610
Average number of common shares outstanding	177		175		171
Average incremental shares from assumed exercise of options	—		—		1
Common shares for dilutive calculation	177		175		172
Weighted average net restricted shares outstanding	—		1		1
Dividends declared — common shares	$	475	$	453	$	413
Dividends declared — net restricted shares	1		1		1
Total distributed earnings	$	476	$	454	$	414
Net income less distributed earnings	$	429	$	207	$	196
Distributed (dividends per common share)	$	2.69	$	2.59	$	2.42
Undistributed	2.41		1.17		1.13
Total Diluted Earnings per Common Share	$	5.10	$	3.76	$	3.55

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Fair Value (Reconciliation of Level 3 Assets and Liabilities at Fair Value on a Recurring Basis) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Net Assets (Liabilities) as of December 31	$ (36,000,000)	$ (13,000,000)
Transfers into Level 3 from Level 2	0	1,000,000
Transfers from Level 3 into Level 2	(2,000,000)	0
Total gains (losses):
Included in earnings	(20,000,000)	43,000,000
Recorded in regulatory assets/liabilities	8,000,000	5,000,000
Purchases, issuances and settlements:
Purchases	1,000,000	(7,000,000)
Issuances	(3,000,000)	(1,000,000)
Settlements	76,000,000	(64,000,000)
Net Assets (Liabilities) as of December 31	24,000,000	(36,000,000)
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	40,000,000	(1,000,000)
Natural Gas Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Net Assets (Liabilities) as of December 31	(52,000,000)	(38,000,000)
Transfers into Level 3 from Level 2	0	1,000,000
Transfers from Level 3 into Level 2	(2,000,000)	0
Total gains (losses):
Included in earnings	(40,000,000)	(32,000,000)
Recorded in regulatory assets/liabilities	0	0
Purchases, issuances and settlements:
Purchases	0	(8,000,000)
Issuances	0	0
Settlements	124,000,000	25,000,000
Net Assets (Liabilities) as of December 31	30,000,000	(52,000,000)
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	35,000,000	(49,000,000)
Electricity Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Net Assets (Liabilities) as of December 31	13,000,000	23,000,000
Transfers into Level 3 from Level 2	0	0
Transfers from Level 3 into Level 2	0	0
Total gains (losses):
Included in earnings	25,000,000	75,000,000
Recorded in regulatory assets/liabilities	0	0
Purchases, issuances and settlements:
Purchases	1,000,000	1,000,000
Issuances	(3,000,000)	(1,000,000)
Settlements	(41,000,000)	(85,000,000)
Net Assets (Liabilities) as of December 31	(5,000,000)	13,000,000
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	9,000,000	48,000,000
Other Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Net Assets (Liabilities) as of December 31	3,000,000	2,000,000
Transfers into Level 3 from Level 2	0	0
Transfers from Level 3 into Level 2	0	0
Total gains (losses):
Included in earnings	(5,000,000)	0
Recorded in regulatory assets/liabilities	8,000,000	5,000,000
Purchases, issuances and settlements:
Purchases	0	0
Issuances	0	0
Settlements	(7,000,000)	(4,000,000)
Net Assets (Liabilities) as of December 31	(1,000,000)	3,000,000
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$ (4,000,000)	$ 0

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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, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 79	$ (11)
Foreign Currency Exchange Contract [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(2)	(1)
Natural Gas Commodity Contract [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(30)	(48)
Natural Gas Commodity Contract [Member] | Fuel, purchased power and gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(5)	(44)
Electricity Commodity Contract [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	123	82
Other Commodity Contract [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ (7)	$ 0

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Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Tax effect on benefit obligation	$ (9)	$ 13	$ (1)
Tax effect on net unrealized gains (losses) on investments during the period	1	1	1
Tax effect on foreign currency translation	$ (2)	$ (1)	$ 0

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Discontinued Operations (Notes)

12 Months Ended

Dec. 31, 2014

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

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
	(In millions)
Operating Revenues	$	55
Operation and maintenance	24
Depreciation, depletion and amortization	23
Taxes other than income	4
Asset (gains) losses, net	83
	134
Operating Loss	(79		)
Other (Income) and Deductions	6
Loss Before Income Taxes	(85		)
Income Tax Benefit	(29		)
Net Loss Attributable to DTE Energy Company	$	(56	)

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Accounting Pronouncements (Notes)

12 Months Ended

Dec. 31, 2014

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements

NEW ACCOUNTING PRONOUNCEMENTS

In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers. The objectives of this ASU are to improve upon revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and timing of recognition. The core principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. This ASU also requires expanded qualitative and quantitative disclosures regarding the nature, amount, timing, and uncertainty of revenues and cash flows arising from contracts with customers. The revenue standard is effective for the first interim period within annual reporting periods beginning after December 15, 2016 and is to be applied retrospectively. Early adoption is not permitted. The Company is currently assessing the impact of this ASU on its Consolidated Financial Statements.

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Short-Term Credit Arrangements and Borrowings (Notes)

12 Months Ended

Dec. 31, 2014

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 that can be used for general corporate borrowings, but are intended to provide liquidity support for each of the companies’ commercial paper programs. 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. At December 31, 2014, the total funded debt to total capitalization ratios for DTE Energy, DTE Electric and DTE Gas are 0.50 to 1, 0.51 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, 2014 is shown in the following table:

	DTE Energy		DTE Electric		DTE Gas		Total
	(In millions)
Unsecured letter of credit facility, expiring in February 2015	$	100	$	—	$	—	$	100
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Unsecured revolving credit facility, expiring April 2018	1,200		300		300		1,800
	1,425		300		300		2,025
Amounts outstanding at December 31, 2014:
Commercial paper issuances	203		50		145		398
Letters of credit	204		—		—		204
	407		50		145		602
Net availability at December 31, 2014	$	1,018	$	250	$	155	$	1,423

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $35 million which are used for various corporate purposes.

The weighted average interest rate for short-term borrowings was 0.4% and 0.2% at December 31, 2014 and 2013, 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, 2014, 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 $37 million and $138 million at December 31, 2014 and 2013, respectively.

Dividend Restrictions

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. The effect of this provision was to restrict the payment of approximately $730 million at December 31, 2014 of total retained earnings of approximately $4.6 billion. There are no other effective limitations with respect to the Company’s ability to pay dividends.

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Fair Value (Notes)

12 Months Ended

Dec. 31, 2014

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, 2014 and 2013. 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, 2014 and 2013:

	December 31, 2014															December 31, 2013
	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)	$	13		$	99		$	—		$	—		$	112		$	10		$	115		$	—		$	—		$	125
Nuclear decommissioning trusts	792			449			—			—			1,241			779			412			—			—			1,191
Other investments (c) (d)	100			50			—			—			150			92			44			—			—			136
Derivative assets:
Commodity Contracts:
Natural Gas	555			140			92			(681		)	106			273			89			34			(382		)	14
Electricity	—			295			47			(280		)	62			—			261			139			(291		)	109
Other	42			—			3			(42		)	3			33			1			3			(34		)	3
Other derivative contracts (e)	—			4			—			(3		)	1			—			—			—			—			—
Total derivative assets	597			439			142			(1,006		)	172			306			351			176			(707		)	126
Total	$	1,502		$	1,037		$	142		$	(1,006	)	$	1,675		$	1,187		$	922		$	176		$	(707	)	$	1,578
Liabilities:
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(578	)	$	(78	)	$	(62	)	$	679		$	(39	)	$	(277	)	$	(140	)	$	(86	)	$	395		$	(108	)
Electricity	—			(290		)	(52		)	298			(44		)	—			(272		)	(126		)	269			(129		)
Other	(32		)	(9		)	(4		)	45			—			(32		)	(2		)	—			34			—
Other derivative contracts (e)	—			(5		)	—			3			(2		)	—			(1		)	—			—			(1		)
Total derivative liabilities	(610		)	(382		)	(118		)	1,025			(85		)	(309		)	(415		)	(212		)	698			(238		)
Total	$	(610	)	$	(382	)	$	(118	)	$	1,025		$	(85	)	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)
Net Assets (Liabilities) at the end of the period	$	892		$	655		$	24		$	19		$	1,590		$	878		$	507		$	(36	)	$	(9	)	$	1,340
Assets:
Current	$	582		$	504		$	109		$	(955	)	$	240		$	277		$	400		$	139		$	(592	)	$	224
Noncurrent (f)	920			533			33			(51		)	1,435			910			522			37			(115		)	1,354
Total Assets	$	1,502		$	1,037		$	142		$	(1,006	)	$	1,675		$	1,187		$	922		$	176		$	(707	)	$	1,578
Liabilities:
Current	$	(572	)	$	(357	)	$	(112	)	$	964		$	(77	)	$	(268	)	$	(328	)	$	(177	)	$	578		$	(195	)
Noncurrent	(38		)	(25		)	(6		)	61			(8		)	(41		)	(87		)	(35		)	120			(43		)
Total Liabilities	$	(610	)	$	(382	)	$	(118	)	$	1,025		$	(85	)	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)
Net Assets (Liabilities) at the end of the period	$	892		$	655		$	24		$	19		$	1,590		$	878		$	507		$	(36	)	$	(9	)	$	1,340

_______________________________________

(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, 2014, available-for-sale securities of $112 million included $105 million and $7 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively. 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.

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

(d) Available-for-sale equity securities of $8 million at December 31, 2014 and $7 million at December 31, 2013 are included in Other investments on the Consolidated Statements of Financial Position.

(e) Primarily includes Foreign currency exchange contracts.

(f) Includes $150 million and $136 million of Other investments that are included in the Consolidated Statements of Financial Position in Other investments at December 31, 2014 and 2013, respectively.

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.

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 hold exchange-traded equity or debt securities and are valued based on stated NAVs. 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 table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2014 and 2013:

	Year Ended December 31, 2014												Year Ended December 31, 2013
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of December 31	$	(52	)	$	13		$	3		$	(36	)	$	(38	)	$	23		$	2		$	(13	)
Transfers into Level 3 from Level 2	—			—			—			—			1			—			—			1
Transfers from Level 3 into Level 2	(2		)	—			—			(2		)	—			—			—			—
Total gains (losses):
Included in earnings	(40		)	25			(5		)	(20		)	(32		)	75			—			43
Recorded in regulatory assets/liabilities	—			—			8			8			—			—			5			5
Purchases, issuances and settlements:
Purchases	—			1			—			1			(8		)	1			—			(7		)
Issuances	—			(3		)	—			(3		)	—			(1		)	—			(1		)
Settlements	124			(41		)	(7		)	76			25			(85		)	(4		)	(64		)
Net Assets (Liabilities) as of December 31	$	30		$	(5	)	$	(1	)	$	24		$	(52	)	$	13		$	3		$	(36	)
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	35		$	9		$	(4	)	$	40		$	(49	)	$	48		$	—		$	(1	)

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. There were no transfers between levels 1 and 2 during the years ended December 31, 2014 and 2013.

The following tables present the unobservable inputs related to Level 3 assets and liabilities as of December 31, 2014 and 2013:

	December 31, 2014
Commodity Contracts	Derivative Assets		Derivative Liabilities			Valuation Techniques	Unobservable Input	Range						Weighted Average
	(In millions)
Natural Gas	$	92	$	(62	)	Discounted Cash Flow	Forward basis price (per MMBtu)	$	(2.28	) —	$	7.83	/MMBtu	$	(0.22	)/MMBtu
Electricity	$	47	$	(52	)	Discounted Cash Flow	Forward basis price (per MWh)	$	(14	) —	$	15	/MWh	$	4	/MWh

	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

The unobservable inputs used in the fair value measurement of the electricity and natural gas commodity types consist 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 as assumptions about the remaining life of the loans and credit risk. Depending on the information available, other valuation techniques may be used that rely on internal assumptions and models. Valuation policies and procedures are determined by 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, 2014 and 2013:

	December 31, 2014								December 31, 2013
	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	$	41	$	—	$	—	$	41
Dividends payable	$	122	$	122	$	—	$	—	$	116	$	116	$	—	$	—
Short-term borrowings	$	398	$	—	$	398	$	—	$	131	$	—	$	131	$	—
Long-term debt, excluding capital leases	$	8,606	$	489	$	8,308	$	706	$	8,094	$	425	$	7,551	$	499

For further fair value information on financial and derivative instruments see Note 12 to the Consolidated Financial Statements, "Financial and Other 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 7 to the Consolidated Financial Statements, "Asset Retirement Obligations".

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

	December 31, 2014		December 31, 2013
	(In millions)
Fermi 2	$	1,221	$	1,172
Fermi 1	3		3
Low level radioactive waste	17		16
Total	$	1,241	$	1,191

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
	2014			2013			2012
	(In millions)
Realized gains	$	54		$	83		$	37
Realized losses	$	(33	)	$	(41	)	$	(31	)
Proceeds from sales of securities	$	1,146		$	1,118		$	759

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, 2014							December 31, 2013
	Fair Value		Unrealized Gains		Unrealized Losses			Fair Value		Unrealized Gains		Unrealized Losses
	(In millions)
Equity securities	$	756	$	204	$	(39	)	$	730	$	201	$	(25	)
Debt securities	474		21		(2		)	442		12		(6		)
Cash and cash equivalents	11		—		—			19		—		—
	$	1,241	$	225	$	(41	)	$	1,191	$	213	$	(31	)

At December 31, 2014, investments in the nuclear decommissioning trust funds consisted of approximately 61% in publicly traded equity securities, 38% in fixed debt instruments and 1% in cash equivalents. At December 31, 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.

The debt securities at December 31, 2014 and 2013 had an average maturity of approximately 7 years. 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.

Other Securities

At December 31, 2014 and 2013, these securities are comprised primarily of money-market and equity securities. During the years ended December 31, 2014 and 2013, 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, 2014, 2013 and 2012 were $14 million, $22 million and $11 million, respectively.

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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, 2014	Dec. 31, 2013	Dec. 31, 2012
Nuclear Decommissioning Trust Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Realized gains	$ 54	$ 83	$ 37
Realized losses	(33)	(41)	(31)
Proceeds from sales of securities	$ 1,146	$ 1,118	$ 759

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Asset Retirement Obligations (Notes)

12 Months Ended

Dec. 31, 2014

Asset Retirement Obligation Disclosure [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 2014 follows:

	(In millions)
Asset retirement obligations at December 31, 2013	$	1,827
Accretion	112
Liabilities incurred	11
Liabilities settled	(12		)
Revision in estimated cash flows	24
Asset retirement obligations at December 31, 2014	$	1,962

Approximately $1.7 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. For additional discussion of Nuclear decommissioning trust fund assets see Note 11 to the Consolidated Financial Statements, "Fair Value".

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Significant Accounting Policies (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Significant Accounting Policies [Line Items]
Other income	$ 196,000,000	$ 201,000,000	$ 173,000,000
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 90 days	30 days
Unbilled revenues	1,504,000,000	1,542,000,000
Regulatory liabilities	820,000,000	1,164,000,000
Property maintenance accrual period	18 months
Amortization of Intangible Assets	12,000,000	14,000,000	6,000,000
Excise and sales taxes net impact on statement of operations	0
Charitable Contributions to a Foundation	25,000,000	18,000,000	21,000,000
Refueling Outage [Member]
Significant Accounting Policies [Line Items]
Regulatory liabilities	16,000,000	26,000,000
Minimum [Member]
Significant Accounting Policies [Line Items]
Notes receivable considered delinquent period	60 days
Finite-lived intangible asset, useful life	1 year
Maximum
Significant Accounting Policies [Line Items]
Notes receivable considered delinquent period	120 days
Finite-lived intangible asset, useful life	27 years
Unbilled Revenues [Member]
Significant Accounting Policies [Line Items]
Unbilled revenues	773,000,000	815,000,000
Public Utilities, Inventory, Natural Gas [Member]
Significant Accounting Policies [Line Items]
LIFO inventory amount	43,000,000	4,000,000
Excess of replacement costs over stated LIFO value	110,000,000	170,000,000
Power and Industrial Projects [Member]
Significant Accounting Policies [Line Items]
Other income	$ 78,000,000	$ 81,000,000	$ 63,000,000

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Retirement Benefits and Trusteed Assets (Pension Plan - Assumptions used in Determining the PBO and Net Pension Costs) (Details) (Pension Plan)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Plan
Projected benefit obligation
Discount rate	4.12%	4.95%	4.15%
Rate of compensation increase	4.65%	4.20%	4.20%
Net pension costs
Discount rate	4.95%	4.15%	5.00%
Rate of compensation increase	4.20%	4.20%	4.20%
Expected long-term rate of return on plan assets	7.75%	8.25%	8.25%

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Property, Plant and Equipment (Notes)

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

Summary of property by classification as of December 31:

	2014			2013
	(In millions)
Property, Plant and Equipment
DTE Electric
Generation	$	11,641		$	11,127
Distribution	8,164			7,603
Total DTE Electric	19,805			18,730
DTE Gas
Distribution	2,946			2,834
Storage	448			431
Other	863			836
Total DTE Gas	4,257			4,101
Non-utility and other	2,476			2,292
Total	26,538			25,123
Less Accumulated Depreciation, Depletion and Amortization
DTE Electric
Generation	(4,149		)	(4,004		)
Distribution	(3,067		)	(2,947		)
Total DTE Electric	(7,216		)	(6,951		)
DTE Gas
Distribution	(1,130		)	(1,129		)
Storage	(142		)	(138		)
Other	(363		)	(338		)
Total DTE Gas	(1,635		)	(1,605		)
Non-utility and other	(867		)	(767		)
Total	(9,718		)	(9,323		)
Net Property, Plant and Equipment	$	16,820		$	15,800

AFUDC and interest capitalized was approximately $37 million and $33 million for the years ended December 31, 2014 and 2013, respectively.

The composite depreciation rate for DTE Electric was approximately 3.4% in 2014 and 2013 and 3.3% in 2012. The composite depreciation rate for DTE Gas was 2.4% in 2014, 2013 and 2012. The average estimated useful life for each major class of utility property, plant and equipment as of December 31, 2014 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 range 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 $77 million in 2014, $71 million in 2013 and $68 million in 2012. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2014 were $668 million and $335 million, respectively. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 2013 were $611 million and $323 million, respectively.

Gross property under capital leases was $35 million at December 31, 2014 and 2013. Accumulated amortization of property under capital leases was $27 million and $21 million at December 31, 2014 and 2013, respectively.

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Jointly Owned Utility Plant (Notes)

12 Months Ended

Dec. 31, 2014

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

Jointly Owned Utility Plant

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, 2014 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)	$	1,742		$	412
Accumulated depreciation (in millions)	$	993		$	175

_______________________________________

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

Belle River

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

Ludington Hydroelectric Pumped Storage

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

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Regulatory Matters (Notes)

12 Months Ended

Dec. 31, 2014

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:

	2014			2013
	(In millions)
Assets
Recoverable pension and other postretirement costs:
Pension	$	2,284		$	1,660
Other postretirement costs	234			—
Asset retirement obligation	448			394
Recoverable Michigan income taxes	267			286
Unamortized loss on reacquired debt	67			63
Other recoverable income taxes	66			71
Accrued PSCR/GCR revenue	61			—
Deferred environmental costs	59			59
Cost to achieve Performance Excellence Process	54			75
Recoverable income taxes related to securitized regulatory assets	19			126
Removal costs asset	15			—
Transitional Reconciliation Mechanism	14			—
Other	139			129
	3,727			2,863
Less amount included in current assets	(76		)	(26		)
	$	3,651		$	2,837
Securitized regulatory assets	$	34		$	231

Liabilities
Removal costs liability	$	308		$	351
Renewable energy	227			277
Over recovery of Securitization	71			72
Refundable revenue decoupling/deferred gain	67			127
Negative pension offset	67			84
Refundable income taxes	33			45
Energy optimization	24			31
Fermi 2 refueling outage	16			26
Refundable other postretirement costs	—			72
Accrued PSCR/GCR refund	—			65
Other	7			14
	$	820		$	1,164
Less amount included current liabilities	(153		)	(302		)
	$	667		$	862

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's 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 service 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 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 MCIT was enacted. The regulatory asset was remeasured to reflect the impact of the MCIT tax rate. (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.

• 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)

• 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.

• 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)

• 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.

• 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, which ended in December 2014, was in place to recover the income tax over a fourteen-year period. (a)

• Removal costs asset — Receivable for the recovery of asset removal expenditures in excess of amounts collected from customers.

• Transitional Reconciliation Mechanism (TRM) — The MPSC approved the recovery of the deferred net incremental revenue requirement associated with the transition of PLD customers to DTE Electric's distribution system, effective July 1, 2014. Annual reconciliations will be filed and surcharges will be implemented to recover approved amounts. (a)

• 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, which ended in December 2014, was in place to recover the securitized regulatory asset over a fourteen-year period.

_________________________________

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

LIABILITIES

• Removal costs liability — 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.

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

• 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 MCOA 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 is being amortized into earnings in 2014 and 2015.

• 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.

• 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 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.

2014 Electric Rate Case Filing

DTE Electric filed a rate case with the MPSC on December 19, 2014 requesting an increase in base rates of $370 million based on a projected twelve-month period ending June 30, 2016. The requested increase in base rates is due primarily to an increase in net plant resulting from infrastructure investments, plant acquisitions, environmental compliance and reliability improvement projects. The rate filing also included projected changes in sales, working capital, operation and maintenance expenses, return on equity and capital structure. New rates could be self-implemented in July 2015, with a final order expected in December 2015.

2010 Electric Rate Case Filing - Court of Appeals Decision

In July 2013, the MCOA issued a decision relating to an appeal of the October 2011 MPSC order in DTE Electric's October 2010 rate case filing. The MCOA 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. In August 2013, the MPSC reopened the 2010 electric rate case for the limited purpose of addressing the MCOA's opinion on AMI. On November 6, 2014, the MPSC issued an order affirming the recovery of costs associated with the AMI program.

Customer360 Accounting Authority

In July 2014, DTE Electric filed an application for accounting authority to defer certain costs associated with implementing Customer360, which is an integrated software application that enables improved interface among customer service, billing, meter reading, credit and collections, device management, account management, and retail access. The estimated implementation cost of Customer360 is approximately $215 million and DTE Electric proposed an amortization period of 15 years. On September 26, 2014, the MPSC approved the accounting request.

Refundable Revenue Decoupling / Deferred Gain Amortization

In September 2012, the MPSC approved DTE Electric's accounting application to defer for future amortization the gain resulting from the reversal of the Company's $127 million regulatory liability associated with the operation of the RDM. The approved application provided for the amortization of the regulatory liability to income, at a monthly rate of approximately $10.6 million, beginning January 2014. On April 1, 2014, the MPSC approved DTE Electric's accounting application to suspend the amortization of the RDM regulatory liability as of June 30, 2014 and to complete the amortization over the period January 2015 to June 2015. If DTE Electric's base rates are increased prior to July 1, 2015, the Company will cease amortization and refund to customers the remaining unamortized balance of the regulatory liability.

Transition of PLD Customers to DTE Electric's Distribution System

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 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 May 13, 2014, the MPSC approved the TRM as requested and also ordered DTE Electric to include in the TRM the 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. The meter installation phase of the transition was completed in June 2014. On July 1, 2014, former PLD customers became customers of DTE Electric.

PSCR 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.

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 approximately 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 2 related purchased power costs. Resolution of this matter is expected in 2015.

DTE Gas Infrastructure Recovery Mechanism (IRM)

In November 2014, DTE Gas filed an application with the MPSC for approval of an increased IRM surcharge to recover an additional $47 million of annual capital expenditures in 2016 and 2017 for its gas main renewal program. Resolution of this matter is anticipated in 2015.

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Property, Plant and Equipment (Average Estimated Useful Life of Each Major Class) (Details)	12 Months Ended
	Dec. 31, 2014
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

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Retirement Benefits and Trusteed Assets (OPEB - Fair Value Measurements) (Details) (Other Postretirement Benefit Plan, USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 1,528	$ 1,527	$ 1,153
Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	765	883
Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	464	384
Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	299	260	205
Short-term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	6	5
Short-term Investments [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	6	5
Short-term Investments [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Short-term Investments [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
US Large Cap Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	266	302
US Large Cap Equity Securities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	266	302
US Large Cap Equity Securities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
US Large Cap Equity Securities [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
US Small Cap and Mid Cap Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	149	147
US Small Cap and Mid Cap Equity Securities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	149	147
US Small Cap and Mid Cap Equity Securities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
US Small Cap and Mid Cap Equity Securities [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Non US Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	281	291
Non US Equity Securities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	222	282
Non US Equity Securities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	59	9
Non US Equity Securities [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	375	367
Fixed Income Securities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	15	17
Fixed Income Securities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	360	350
Fixed Income Securities [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Hedge Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	320	314
Hedge Funds [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	107	130
Hedge Funds [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	45	25
Hedge Funds [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	168	159	119
Private Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	131	101
Private Equity Funds [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Private Equity Funds [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Private Equity Funds [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	131	101	86
Securities Lending [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	(158)	0
Securities Lending [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	(141)	0
Securities Lending [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	(17)	0
Securities Lending [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Securities Lending Collateral [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	158	0
Securities Lending Collateral [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	141	0
Securities Lending Collateral [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	17	0
Securities Lending Collateral [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 0	$ 0

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Fair Value (Fair Value and Unrealized Gains and Losses for the Nuclear Decommissioning Trust Funds) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Schedule of Available-for-sale Securities [Line Items]
Nuclear decommissioning trusts	$ 1,241	$ 1,191
Gross Unrealized Gain	225	213
Gross Unrealized Loss	(41)	(31)
Nuclear Decommissioning Trust Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Equity Securities	756	730
Debt Securities	474	442
Cash equivalents	11	19
Equity Securities, Gross Unrealized Gain	204	201
Equity Securities, Gross Unrealized Loss	(39)	(25)
Debt Securities, Gross Unrealized Gain	21	12
Debt Securities, Gross Unrealized Loss	$ (2)	$ (6)

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Jointly Owned Utility Plant (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014 MW
Belle River [Member]
Jointly Owned Utility Plant Interests [Line Items]
Total plant capacity (in MW)	1,270
Investment (in millions)	$ 1,742
Accumulated depreciation (in millions)	993
Ludington Hydroelectric Pumped Storage [Member]
Jointly Owned Utility Plant Interests [Line Items]
Total plant capacity (in MW)	1,872
Ownership interest	49.00%
Investment (in millions)	412
Accumulated depreciation (in millions)	$ 175

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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, 2014
Capital Leases of Lessor [Abstract]
2015	$ 12
2016	13
2017	13
2018	13
2019	10
Thereafter	9
Total minimum future lease receipts	70
Residual value of leased pipeline	40
Less unearned income	(34)
Net investment in capital lease	76
Less current portion	(5)
Capital Lease, noncurrent	$ 71

XML

Property, Plant and Equipment (Summary of Property by Classification) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Non-utility and other	$ 2,476	$ 2,292
Property, plant and equipment, Total	26,538	25,123
Less Accumulated Depreciation, Depletion and Amortization - Nonutility and Other	(867)	(767)
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	(9,718)	(9,323)
Property, plant and equipment	16,820	15,800
Electric Generation Equipment [Member]
Property, Plant and Equipment [Line Items]
Property Plant and Equipment - Generation	11,641	11,127
Accumulated Depreciation, Depletion and Amortization	(4,149)	(4,004)
Electric Distribution [Member]
Property, Plant and Equipment [Line Items]
Property Plant and Equipment - Distribution	8,164	7,603
Accumulated Depreciation, Depletion and Amortization	(3,067)	(2,947)
Electric Generation, Transmission and Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Plant in Service	19,805	18,730
Accumulated Depreciation, Depletion and Amortization	(7,216)	(6,951)
Gas Distribution [Member]
Property, Plant and Equipment [Line Items]
Property Plant and Equipment - Distribution	2,946	2,834
Accumulated Depreciation, Depletion and Amortization	(1,130)	(1,129)
Storage [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Storage	448	431
Accumulated Depreciation, Depletion and Amortization	(142)	(138)
Other [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment - Other	863	836
Accumulated Depreciation, Depletion and Amortization	(363)	(338)
Gas Distribution and Storage [Member]
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Plant in Service	4,257	4,101
Accumulated Depreciation, Depletion and Amortization	$ (1,635)	$ (1,605)

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Financial and Other Derivative Instruments (Details Textuals) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Letters of credit that could be used to offset net derivative liabilities	$ 7,000,000	$ 19,000,000
Letters of credit received that could be used to offset net derivative assets	5,000,000	1,000,000
Cash collateral posted, net of cash collateral received	61,000,000	12,000,000
Derivative asset, counterparty netting	0	26,000,000
Derivative liability, counterparty netting	19,000,000	17,000,000
Cash collateral received	2,000,000	13,000,000
Cash collateral paid	44,000,000	34,000,000
Derivative net liability position aggregate fair value	1,058,000,000
Collateral already posted fair value	12,000,000
Derivative, net asset position, fair value	973,000,000
Remaining amount of offsets to derivative net liability positions for hard and soft trigger provisions	73,000,000
Additional collateral, aggregate fair value	$ 349,000,000

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Stock-Based Compensation (Performance Share Awards Activity) (Details) (Performance Shares [Member], USD $)	12 Months Ended
	Dec. 31, 2014
Performance Shares [Member]
Performance Shares (in shares):
Balance at beginning of period	1,608,789
Grants	561,335
Forfeitures	(44,250)
Payouts	(571,177)
Balance at end of period	1,554,697
Weighted Average Grant Date Fair Value (in dollars per share):
Balance at beginning of period	$ 0.00
Grants	$ 69.32
Forfeitures	$ 69.16
Payouts	$ 0.00
Balance at end of period	$ 69.32

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

The following table summarizes the changes in Accumulated other comprehensive loss by component for the years ended December 31, 2014 and 2013:

	Changes in Accumulated Other Comprehensive Loss by Component (a)
	Net Unrealized Gain/(Loss) on Derivatives			Net Unrealized Gain/(Loss) on Investments			Benefit Obligations (b)			Foreign Currency Translation			Total
	(In millions)
Balance, January 1, 2013	$	(4	)	$	(8	)	$	(148	)	$	2		$	(158	)
Other comprehensive income (loss) before reclassifications	—			2			13			(2		)	13
Amounts reclassified from accumulated other comprehensive income	—			—			9			—			9
Net current-period other comprehensive income (loss)	—			2			22			(2		)	22
Balance, December 31, 2013	$	(4	)	$	(6	)	$	(126	)	$	—		$	(136	)
Other comprehensive income (loss) before reclassifications	—			1			(25		)	(2		)	(26		)
Amounts reclassified from accumulated other comprehensive income	—			—			7			—			7
Net current-period other comprehensive income (loss)	—			1			(18		)	(2		)	(19		)
Balance, December 31, 2014	$	(4	)	$	(5	)	$	(144	)	$	(2	)	$	(155	)

______________________________________

(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 18 to the Consolidated Financial Statements "Retirement Benefits and Trusteed Assets").

Schedule of Finite-Lived Intangible Assets by Major Class

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

	December 31, 2014		December 31, 2013
	(In millions)
Emission allowances	$	1	$	2
Renewable energy credits	45		51
Contract intangible assets	122		126
	168		179
Less accumulated amortization	57		45
Intangible assets, net	111		134
Less current intangible assets	9		12
	$	102	$	122

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense

The following table summarizes the estimated amortization expense expected to be recognized during each year through 2019:

Estimated amortization expense	(In millions)
2015	$	12
2016	$	11
2017	$	8
2018	$	8
2019	$	6

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Segment and Related Information (Tables)

12 Months Ended

Dec. 31, 2014

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

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:

	2014		2013			2012
	(In millions)
Electric	$	29	$	26		$	29
Gas	6		4			4
Power and Industrial Projects	794		816			801
Gas Storage and Pipelines	9		3			6
Energy Trading	33		43			43
Corporate and Other	3		(24		)	(37		)
Discontinued Operations	—		—			2
	$	874	$	868		$	848

Financial data of the business segments follows:

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Tax Expense (Benefit)			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures and Acquisitions
	(In millions)
2014
Electric	$	5,283		$	933	$	(1	)	$	250		$	296		$	528		$	18,715		$	1,208	$	1,561
Gas	1,636			99		(7		)	57			78			140			4,283			743		224
Power and Industrial Projects	2,289			77		(5		)	28			(100		)	90			1,009			26		77
Gas Storage and Pipelines	203			34		(6		)	22			53			82			884			24		184
Energy Trading	3,762			1		—			7			77			122			755			17		3
Corporate and Other	2			1		(48		)	122			(40		)	(57		)	3,209			—		—
Reclassifications and Eliminations	(874		)	—		57			(57		)	—			—			(881		)	—		—
Total	$	12,301		$	1,145	$	(10	)	$	429		$	364		$	905		$	27,974		$	2,018	$	2,049

	Operating Revenue			Depreciation, Depletion & Amortization		Interest Income			Interest Expense			Income Tax Expense (Benefit)			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures and Acquisitions
	(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
Power and Industrial Projects	1,950			72		(6		)	27			(45		)	66			1,067			26		93
Gas Storage and Pipelines	132			23		(7		)	18			45			70			824			24		245
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 Tax Expense (Benefit)			Net Income (Loss) Attributable to DTE Energy Company			Total Assets			Goodwill		Capital Expenditures and Acquisitions
	(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
Power and Industrial Projects	1,823			65		(7		)	37			(44		)	42			991			26		281
Gas Storage and Pipelines	96			8		(8		)	8			39			61			668			22		233
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	$	1,969
Discontinued Operations (Note 4)															(56		)	—			—		49
Total															$	610		$	26,339		$	2,018	$	2,018

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Long-Term Debt (Notes)

12 Months Ended

Dec. 31, 2014

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:

	2014			2013
	(In millions)
Mortgage bonds, notes and other
DTE Energy Debt, Unsecured
4.6% due 2016 to 2033	$	1,647		$	1,297
DTE Electric Taxable Debt, Principally Secured
4.5% due 2016 to 2044	4,824			4,286
DTE Electric Tax-Exempt Revenue Bonds (b)
5.2% due 2020 to 2030	330			558
DTE Gas Taxable Debt, Principally Secured
5.2% due 2015 to 2044	1,099			1,029
Other Long-Term Debt, Including Non-Recourse Debt	121			142
	8,021			7,312
Less amount due within one year	(161		)	(694		)
	$	7,860		$	6,618
Securitization bonds
6.6% due 2015	$	105		$	302
Less amount due within one year	(105		)	(197		)
	$	—		$	105
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, 2014 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 2014, the following debt was issued:

Company	Month Issued	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Energy	May	Senior Notes (a)	3.50	%	2024	$	350
DTE Electric	June	Mortgage Bonds (a)	3.77	%	2026	100
DTE Electric	June	Mortgage Bonds (a)	4.60	%	2044	150
DTE Electric	July	Mortgage Bonds (a)	3.375	%	2025	350
DTE Electric	July	Mortgage Bonds (a)	4.30	%	2044	350
DTE Energy	November	Senior Notes (a)	2.40	%	2019	300
DTE Gas	December	Mortgage Bonds (a)	4.35	%	2044	150
						$	1,750

_______________________________________

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

Debt Redemptions

In 2014, the following debt was redeemed:

Company	Month	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March	Mortgage Bonds	Various		2014	$	13
DTE Electric	March	Securitization Bonds	6.62	%	2014	100
DTE Electric	April	Tax Exempt Revenue Bonds (a)	2.35	%	2024	31
DTE Electric	April	Tax Exempt Revenue Bonds (a)	4.65	%	2028	32
DTE Gas	May	Mortgage Bonds	8.25	%	2014	80
DTE Energy	May	Senior Notes	7.625	%	2014	300
DTE Electric	June	Tax Exempt Revenue Bonds (a)	4.875	%	2029	36
DTE Electric	June	Tax Exempt Revenue Bonds (a)	6.00	%	2036	69
DTE Electric	July	Senior Notes	4.80	%	2015	200
DTE Electric	August	Senior Notes	5.40	%	2014	200
DTE Electric	August	Tax Exempt Revenue Bonds (a)	5.25	%	2029	60
DTE Electric	September	Securitization Bonds	6.62	%	2014	96
DTE Energy	Various	Other Long Term Debt	Various		2014	20
						$	1,237

_______________________________________

(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, excluding any unamortized discount or premium on debt:

	2015		2016		2017		2018		2019		2020 and Thereafter		Total
	(In millions)
Amount to mature	$	266	$	465	$	9	$	407	$	427	$	7,046	$	8,620

Junior Subordinated Debentures

At December 31, 2014, DTE Energy had $280 million of 6.5% Junior Subordinated Debentures due 2061 and $200 million of 5.25% Junior Subordinated Debentures due 2062. DTE Energy has the right to defer interest payments on the debt securities. Should DTE Energy 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. As of December 31, 2014, no interest payments have been deferred on the debt securities.

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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Retirement Benefits and Trusteed Assets (OPEB - Other Changes in Plan Assets and APBO Recognized in Regulatory Assets and OCI) (Details) (Other Postretirement Benefit Plan, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (gain) loss	$ 192	$ (353)
Amortization of net actuarial loss	(20)	(64)
Prior service credit	0	(218)
Amortization of prior service credit	144	131
Total recognized Regulatory assets and Other comprehensive income	316	(504)
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	193	(546)
Future amortization of net actuarial loss into net periodic benefit cost	43	21
Future amortization of prior service credit into net periodic benefit cost	$ (126)	$ (144)

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Retirement Benefits and Trusteed Assets (Notes)

12 Months Ended

Dec. 31, 2014

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 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 to newly hired employees. 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 $188 million to its qualified pension plans in 2014. At the discretion of management, and depending upon financial market conditions, the Company anticipates making up to $180 million in contributions to the pension plans in 2015.

Net pension cost includes the following components:

	2014			2013			2012
	(In millions)
Service cost	$	83		$	94		$	82
Interest cost	212			192			204
Expected return on plan assets	(273		)	(266		)	(244		)
Amortization of:
Net loss	157			208			176
Special termination benefits	—			—			2
Net pension cost	$	179		$	228		$	220

	2014			2013
	(In millions)
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income
Net actuarial (gain) loss	$	805		$	(581	)
Amortization of net actuarial loss	(157		)	(208		)
Prior service cost	(7		)	—
Total recognized in Regulatory assets and Other comprehensive income	$	641		$	(789	)
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	820		$	(561	)
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	$	206		$	151

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:

	2014			2013
	(In millions)
Accumulated benefit obligation, end of year	$	4,853		$	4,068
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	4,380		$	4,729
Service cost	83			94
Interest cost	212			192
Plan amendments	(7		)	(3		)
Actuarial (gain) loss	836			(400		)
Benefits paid	(235		)	(232		)
Projected benefit obligation, end of year	$	5,269		$	4,380
Change in plan assets
Plan assets at fair value, beginning of year	$	3,720		$	3,223
Actual return on plan assets	301			445
Company contributions	195			284
Benefits paid	(235		)	(232		)
Plan assets at fair value, end of year	$	3,981		$	3,720
Funded status of the plans	$	(1,288	)	$	(660	)
Amount recorded as:
Current liabilities	$	(8	)	$	(7	)
Noncurrent liabilities	(1,280		)	(653		)
	$	(1,288	)	$	(660	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	194		$	174
Prior service (credit)	(1		)	(1		)
	$	193		$	173
Amounts recognized in Regulatory assets (see Note 8)
Net actuarial loss	$	2,285		$	1,654
Prior service (credit) cost	(1		)	6
	$	2,284		$	1,660

At December 31, 2014, 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)
2015	$	269
2016	277
2017	286
2018	298
2019	309
2020-2024	1,634
Total	$	3,073

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

	2014	2013	2012
Projected benefit obligation
Discount rate	4.12%	4.95%	4.15%
Rate of compensation increase	4.65%	4.20%	4.20%
Net pension costs
Discount rate	4.95%	4.15%	5.00%
Rate of compensation increase	4.20%	4.20%	4.20%
Expected long-term rate of return on plan assets	7.75%	8.25%	8.25%

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 2015. The Company believes these rates are a reasonable assumption for the long-term rate of return on its plan assets for 2015 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-U.S. 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, 2014 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, 2014 and 2013(a):

	December 31, 2014											December 31, 2013
	Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
	(In millions)
Asset category:
Short-term investments (b)	$	46		$	—		$	—	$	46		$	22	$	—	$	—	$	22
Equity securities
U.S. large cap (c)	899			—			—		899			896		—		—		896
U.S. small/mid cap (d)	225			—			—		225			221		—		—		221
Non U.S. (e)	526			219			—		745			611		130		—		741
Fixed income securities (f)	7			1,113			—		1,120			16		921		—		937
Hedge funds and similar investments (g)	226			95			438		759			268		70		395		733
Private equity and other (h)	—			—			187		187			—		—		170		170
Securities lending (i)	(189		)	(50		)	—		(239		)	—		—		—		—
Securities lending collateral (i)	189			50			—		239			—		—		—		—
Total	$	1,929		$	1,427		$	625	$	3,981		$	2,034	$	1,121	$	565	$	3,720

_______________________________________

(a) For a description of levels within the fair value hierarchy see Note 11 to the Consolidated Financial Statements, "Fair Value".

(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.

(i) In 2014, DTE Energy began a securities lending program with a third party agent. The program allows the agent to lend certain securities from the Company's pension trusts to selected entities against receipt of collateral (in the form of cash) as provided for and determined in accordance with its securities lending agency agreement.

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 NAVs. 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 trustee challenges an assigned price and determines that another price source is considered to be preferable. DTE Energy has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, DTE Energy selectively corroborates the fair values of securities by comparison of market-based price sources.

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

	Year Ended December 31, 2014									Year Ended December 31, 2013
	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	$	395		$	170		$	565		$	339	$	179		$	518
Total realized/unrealized gains (losses)	22			16			38			40		4			44
Purchases, sales and settlements:
Purchases	22			31			53			16		15			31
Sales	(1		)	(30		)	(31		)	—		(28		)	(28		)
Ending Balance at December 31	$	438		$	187		$	625		$	395	$	170		$	565
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	$	21		$	11		$	32		$	38	$	3		$	41

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, 2014 and 2013.

Other Postretirement Benefits

The Company participates in defined benefit plans sponsored by the LLC that provide 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 VEBA and other benefit trusts exist. The Company contributed $24 million to these trusts for its defined benefit other postretirement medical and life insurance benefit plans during 2014. At the discretion of management, the Company anticipates making up to $200 million of contributions to the trusts in 2015.

Starting in 2012, in lieu of offering future employees defined benefit post-employment health care and life insurance benefits, the Company allocates a fixed amount per year to an account in a defined contribution VEBA for each employee. These accounts 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 contributions to the VEBA for these accounts were $4 million in 2014, $2 million in 2013 and less than $1 million in 2012.

Beginning in 2013, the Company replaced the defined benefit employer-sponsored retiree medical, prescription drug and dental coverage with a notional allocation to a Retiree Reimbursement Account. This change applies to both current and future Medicare eligible non-represented and future represented retirees, spouses, surviving spouses or same sex domestic partners when the youngest of the retiree's covered household turns age 65. The amount of the annual allocation to each participant is determined by the employee's retirement date: for employees who retired on or before January 1, 2013, the base allocation is $3,500, which increased to $3,570 in 2014 and for employees who retire after January 1, 2013, the base allocation is $3,250, which increased to $3,315 in 2014. The amount of the allocation will increase each year at the lower of the rate of medical inflation or 2%.

Net other postretirement cost includes the following components:

	2014			2013			2012
	(In millions)
Service cost	$	34		$	47		$	68
Interest cost	89			88			120
Expected return on plan assets	(122		)	(110		)	(92		)
Amortization of:
Net loss	20			64			80
Prior service credit	(144		)	(131		)	(25		)
Net other postretirement cost (credit)	$	(123	)	$	(42	)	$	151

	2014			2013
	(In millions)
Other changes in plan assets and APBO recognized in Regulatory assets (liabilities) and Other comprehensive income
Net actuarial (gain) loss	$	192		$	(353	)
Amortization of net actuarial loss	(20		)	(64		)
Prior service credit	—			(218		)
Amortization of prior service credit	144			131
Total recognized in Regulatory assets (liabilities) and Other comprehensive income	$	316		$	(504	)
Total recognized in net periodic benefit cost, Regulatory assets (liabilities) and Other comprehensive income	$	193		$	(546	)
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	$	43		$	21
Prior service credit	$	(126	)	$	(144	)

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:

	2014			2013
	(In millions)
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation, beginning of year	$	1,878		$	2,315
Service cost	34			47
Interest cost	89			88
Plan amendments	—			(218		)
Actuarial (gain) loss	131			(267		)
Medicare Part D subsidy	—			1
Benefits paid	(88		)	(88		)
Accumulated postretirement benefit obligation, end of year	$	2,044		$	1,878
Change in plan assets
Plan assets at fair value, beginning of year	$	1,527		$	1,153
Actual return on plan assets	62			196
Company contributions	24			264
Benefits paid	(85		)	(86		)
Plan assets at fair value, end of year	$	1,528		$	1,527
Funded status, end of year	$	(516	)	$	(351	)
Amount recorded as:
Current liabilities	$	(1	)	$	(1	)
Noncurrent liabilities	(515		)	(350		)
	$	(516	)	$	(351	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	34		$	29
Prior service credit	(5		)	(10		)
	$	29		$	19
Amounts recognized in Regulatory assets (liabilities) (see Note 8)
Net actuarial loss	$	488		$	321
Prior service credit	(254		)	(393		)
	$	234		$	(72	)

At December 31, 2014, 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)
2015	$	101
2016	107
2017	111
2018	117
2019	122
2020-2024	660
Total	$	1,218

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

	2014	2013	2012
Accumulated postretirement benefit obligation
Discount rate	4.10%	4.95%	4.15%
Health care trend rate pre- and post- 65	7.50 / 6.50%	7.50 / 6.50%	7.00%
Ultimate health care trend rate	4.50%	4.50%	5.00%
Year in which ultimate reached pre- and post- 65	2025 / 2024	2025 / 2024	2021
Other postretirement benefit costs
Discount rate (prior to interim remeasurement)	4.95%	4.15%	5.00%
Discount rate (post interim remeasurement)	N/A	4.30%	N/A
Expected long-term rate of return on plan assets	8.00%	8.25%	8.25%
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

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 $8 million in 2014 and increased the accumulated benefit obligation by $108 million at December 31, 2014. 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 $7 million in 2014 and would have decreased the accumulated benefit obligation by $94 million at December 31, 2014.

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, 2014 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, 2014 and 2013(a):

	December 31, 2014											December 31, 2013
	Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Asset category:	(In millions)
Short-term investments (b)	$	6		$	—		$	—	$	6		$	5	$	—	$	—	$	5
Equity securities
U.S. large cap (c)	266			—			—		266			302		—		—		302
U.S. small/mid cap (d)	149			—			—		149			147		—		—		147
Non U.S. (e)	222			59			—		281			282		9		—		291
Fixed income securities (f)	15			360			—		375			17		350		—		367
Hedge funds and similar investments (g)	107			45			168		320			130		25		159		314
Private equity and other (h)	—			—			131		131			—		—		101		101
Securities lending (i)	(141		)	(17		)	—		(158		)	—		—		—		—
Securities lending collateral (i)	141			17			—		158			—		—		—		—
Total	$	765		$	464		$	299	$	1,528		$	883	$	384	$	260	$	1,527

_______________________________________

(a) For a description of levels within the fair value hierarchy see Note 11 to the Consolidated Financial Statements, "Fair Value".

(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.

(i) In 2014, DTE Energy began a securities lending program with a third party agent. The program allows the agent to lend certain securities from the Company's VEBA trust to selected entities against receipt of collateral (in the form of cash) as provided for and determined in accordance with its securities lending agency agreement.

The VEBA 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 NAVs. 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 trustee challenges an assigned price and determines that another price source is considered to be preferable. DTE Energy has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, DTE Energy selectively corroborates the fair values of securities by comparison of market-based price sources.

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

	Year Ended December 31, 2014									Year Ended December 31, 2013
	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	$	159		$	101		$	260		$	119	$	86		$	205
Total realized/unrealized gains (losses)	8			9			17			14		9			23
Purchases, sales and settlements:
Purchases	9			33			42			26		15			41
Sales	(8		)	(12		)	(20		)	—		(9		)	(9		)
Ending Balance at December 31	$	168		$	131		$	299		$	159	$	101		$	260
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	$	7		$	8		$	15		$	14	$	9		$	23

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, 2014 and 2013.

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 the defined benefit employer-sponsored retiree medical, prescription drug and dental coverage for future Medicare eligible retirees and their covered dependents with an allocation to a Retiree Reimbursement Account, when the youngest of the retiree's covered household turns age 65. The amount of the allocation is $3,250 per year for each eligible participant, which increased to $3,315 in 2014. The amount of the allocation will increase each year at the lower of the rate of medical inflation or 2%. 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.

Grantor Trust

DTE Gas maintains a Grantor Trust that invests in life insurance contracts and income securities to fund other postretirement benefit obligations. 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, which approximated $18 million and $17 million at December 31, 2014 and 2013, 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 $48 million, $41 million and $37 million in each of the years 2014, 2013 and 2012, respectively.

XML

Long-Term Debt (Debt Redemptions) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Debt Instrument, Redemption [Line Items]
Extinguishment of debt	$ 1,237
Mortgages [Member] | Electric [Member] | March 2014 Mortgage Bonds Various Interest Rates Maturing in 2014 [Member]
Debt Instrument, Redemption [Line Items]
Extinguishment of debt	13
Mortgages [Member] | Gas [Member] | May 2014 Mortgage Bonds 8.25% Maturing in 2014 [Member]
Debt Instrument, Redemption [Line Items]
Debt instrument stated interest rate	8.25%
Extinguishment of debt	80
Senior Notes [Member] | Electric [Member] | July 2014 Senior Notes 4.80% Maturing in 2015 [Member]
Debt Instrument, Redemption [Line Items]
Debt instrument stated interest rate	4.80%
Extinguishment of debt	200
Senior Notes [Member] | Electric [Member] | August 2014 Senior Notes 5.40% Maturing in 2014 [Member]
Debt Instrument, Redemption [Line Items]
Debt instrument stated interest rate	5.40%
Extinguishment of debt	200
Senior Notes [Member] | DTE Energy [Member] | May 2014 Senior Notes 7.625% Maturing in 2014 [Member]
Debt Instrument, Redemption [Line Items]
Debt instrument stated interest rate	7.625%
Extinguishment of debt	300
Securitization Bonds [Member] | Electric [Member] | March 2014 Securitization Bonds 6.62% Maturing in 2014 [Member]
Debt Instrument, Redemption [Line Items]
Debt instrument stated interest rate	6.62%
Extinguishment of debt	100
Securitization Bonds [Member] | Electric [Member] | September 2014 Securitization Bonds 6.62% Maturing in 2014 [Member]
Debt Instrument, Redemption [Line Items]
Debt instrument stated interest rate	6.62%
Extinguishment of debt	96
Tax Exempt Revenue Bonds [Member] | Electric [Member] | April 2014 Tax Exempt Revenue Bonds 2.35% Maturing in 2024 [Member]
Debt Instrument, Redemption [Line Items]
Debt instrument stated interest rate	2.35%
Extinguishment of debt	31
Tax Exempt Revenue Bonds [Member] | Electric [Member] | April 2014 Tax Exempt Revenue Bonds 4.65% Maturing in 2028 [Member]
Debt Instrument, Redemption [Line Items]
Debt instrument stated interest rate	4.65%
Extinguishment of debt	32
Tax Exempt Revenue Bonds [Member] | Electric [Member] | June 2014 Tax Exempt Revenue Bonds 4.875% Maturing in 2029 [Member]
Debt Instrument, Redemption [Line Items]
Debt instrument stated interest rate	4.875%
Extinguishment of debt	36
Tax Exempt Revenue Bonds [Member] | Electric [Member] | June 2014 Tax Exempt Revenue Bonds 6.00% Maturing in 2036 [Member]
Debt Instrument, Redemption [Line Items]
Debt instrument stated interest rate	6.00%
Extinguishment of debt	69
Tax Exempt Revenue Bonds [Member] | Electric [Member] | August 2014 Tax Exempt Revenue Bonds 5.25% Maturing in 2029 [Member]
Debt Instrument, Redemption [Line Items]
Debt instrument stated interest rate	5.25%
Extinguishment of debt	60
Long Term Debt, Other [Member] | DTE Energy [Member]
Debt Instrument, Redemption [Line Items]
Extinguishment of debt	$ 20

XML

Retirement Benefits and Trusteed Assets (Tables)

12 Months Ended

Dec. 31, 2014

Pension Plan

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Net Benefit Costs

Net pension cost includes the following components:

	2014			2013			2012
	(In millions)
Service cost	$	83		$	94		$	82
Interest cost	212			192			204
Expected return on plan assets	(273		)	(266		)	(244		)
Amortization of:
Net loss	157			208			176
Special termination benefits	—			—			2
Net pension cost	$	179		$	228		$	220

Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]

	2014			2013
	(In millions)
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income
Net actuarial (gain) loss	$	805		$	(581	)
Amortization of net actuarial loss	(157		)	(208		)
Prior service cost	(7		)	—
Total recognized in Regulatory assets and Other comprehensive income	$	641		$	(789	)
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	$	820		$	(561	)
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	$	206		$	151

Schedule of Defined Benefit Plans Disclosures

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:

	2014			2013
	(In millions)
Accumulated benefit obligation, end of year	$	4,853		$	4,068
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	4,380		$	4,729
Service cost	83			94
Interest cost	212			192
Plan amendments	(7		)	(3		)
Actuarial (gain) loss	836			(400		)
Benefits paid	(235		)	(232		)
Projected benefit obligation, end of year	$	5,269		$	4,380
Change in plan assets
Plan assets at fair value, beginning of year	$	3,720		$	3,223
Actual return on plan assets	301			445
Company contributions	195			284
Benefits paid	(235		)	(232		)
Plan assets at fair value, end of year	$	3,981		$	3,720
Funded status of the plans	$	(1,288	)	$	(660	)
Amount recorded as:
Current liabilities	$	(8	)	$	(7	)
Noncurrent liabilities	(1,280		)	(653		)
	$	(1,288	)	$	(660	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	194		$	174
Prior service (credit)	(1		)	(1		)
	$	193		$	173
Amounts recognized in Regulatory assets (see Note 8)
Net actuarial loss	$	2,285		$	1,654
Prior service (credit) cost	(1		)	6
	$	2,284		$	1,660

Schedule of Expected Benefit Payments

At December 31, 2014, 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)
2015	$	269
2016	277
2017	286
2018	298
2019	309
2020-2024	1,634
Total	$	3,073

Schedule of Assumptions Used

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

	2014	2013	2012
Projected benefit obligation
Discount rate	4.12%	4.95%	4.15%
Rate of compensation increase	4.65%	4.20%	4.20%
Net pension costs
Discount rate	4.95%	4.15%	5.00%
Rate of compensation increase	4.20%	4.20%	4.20%
Expected long-term rate of return on plan assets	7.75%	8.25%	8.25%

Schedule of Allocation of Plan Assets

Target allocations for pension plan assets as of December 31, 2014 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, 2014 and 2013(a):

	December 31, 2014											December 31, 2013
	Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
	(In millions)
Asset category:
Short-term investments (b)	$	46		$	—		$	—	$	46		$	22	$	—	$	—	$	22
Equity securities
U.S. large cap (c)	899			—			—		899			896		—		—		896
U.S. small/mid cap (d)	225			—			—		225			221		—		—		221
Non U.S. (e)	526			219			—		745			611		130		—		741
Fixed income securities (f)	7			1,113			—		1,120			16		921		—		937
Hedge funds and similar investments (g)	226			95			438		759			268		70		395		733
Private equity and other (h)	—			—			187		187			—		—		170		170
Securities lending (i)	(189		)	(50		)	—		(239		)	—		—		—		—
Securities lending collateral (i)	189			50			—		239			—		—		—		—
Total	$	1,929		$	1,427		$	625	$	3,981		$	2,034	$	1,121	$	565	$	3,720

_______________________________________

(a) For a description of levels within the fair value hierarchy see Note 11 to the Consolidated Financial Statements, "Fair Value".

(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.

(i) In 2014, DTE Energy began a securities lending program with a third party agent. The program allows the agent to lend certain securities from the Company's pension trusts to selected entities against receipt of collateral (in the form of cash) as provided for and determined in accordance with its securities lending agency agreement.

Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets

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

	Year Ended December 31, 2014									Year Ended December 31, 2013
	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	$	395		$	170		$	565		$	339	$	179		$	518
Total realized/unrealized gains (losses)	22			16			38			40		4			44
Purchases, sales and settlements:
Purchases	22			31			53			16		15			31
Sales	(1		)	(30		)	(31		)	—		(28		)	(28		)
Ending Balance at December 31	$	438		$	187		$	625		$	395	$	170		$	565
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	$	21		$	11		$	32		$	38	$	3		$	41

Other Postretirement Benefit Plan

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Net Benefit Costs

Net other postretirement cost includes the following components:

	2014			2013			2012
	(In millions)
Service cost	$	34		$	47		$	68
Interest cost	89			88			120
Expected return on plan assets	(122		)	(110		)	(92		)
Amortization of:
Net loss	20			64			80
Prior service credit	(144		)	(131		)	(25		)
Net other postretirement cost (credit)	$	(123	)	$	(42	)	$	151

Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]

	2014			2013
	(In millions)
Other changes in plan assets and APBO recognized in Regulatory assets (liabilities) and Other comprehensive income
Net actuarial (gain) loss	$	192		$	(353	)
Amortization of net actuarial loss	(20		)	(64		)
Prior service credit	—			(218		)
Amortization of prior service credit	144			131
Total recognized in Regulatory assets (liabilities) and Other comprehensive income	$	316		$	(504	)
Total recognized in net periodic benefit cost, Regulatory assets (liabilities) and Other comprehensive income	$	193		$	(546	)
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	$	43		$	21
Prior service credit	$	(126	)	$	(144	)

Schedule of Defined Benefit Plans Disclosures

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:

	2014			2013
	(In millions)
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation, beginning of year	$	1,878		$	2,315
Service cost	34			47
Interest cost	89			88
Plan amendments	—			(218		)
Actuarial (gain) loss	131			(267		)
Medicare Part D subsidy	—			1
Benefits paid	(88		)	(88		)
Accumulated postretirement benefit obligation, end of year	$	2,044		$	1,878
Change in plan assets
Plan assets at fair value, beginning of year	$	1,527		$	1,153
Actual return on plan assets	62			196
Company contributions	24			264
Benefits paid	(85		)	(86		)
Plan assets at fair value, end of year	$	1,528		$	1,527
Funded status, end of year	$	(516	)	$	(351	)
Amount recorded as:
Current liabilities	$	(1	)	$	(1	)
Noncurrent liabilities	(515		)	(350		)
	$	(516	)	$	(351	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	34		$	29
Prior service credit	(5		)	(10		)
	$	29		$	19
Amounts recognized in Regulatory assets (liabilities) (see Note 8)
Net actuarial loss	$	488		$	321
Prior service credit	(254		)	(393		)
	$	234		$	(72	)

Schedule of Expected Benefit Payments

At December 31, 2014, 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)
2015	$	101
2016	107
2017	111
2018	117
2019	122
2020-2024	660
Total	$	1,218

Schedule of Assumptions Used

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

	2014	2013	2012
Accumulated postretirement benefit obligation
Discount rate	4.10%	4.95%	4.15%
Health care trend rate pre- and post- 65	7.50 / 6.50%	7.50 / 6.50%	7.00%
Ultimate health care trend rate	4.50%	4.50%	5.00%
Year in which ultimate reached pre- and post- 65	2025 / 2024	2025 / 2024	2021
Other postretirement benefit costs
Discount rate (prior to interim remeasurement)	4.95%	4.15%	5.00%
Discount rate (post interim remeasurement)	N/A	4.30%	N/A
Expected long-term rate of return on plan assets	8.00%	8.25%	8.25%
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

Schedule of Allocation of Plan Assets

Target allocations for other postretirement benefit plan assets as of December 31, 2014 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, 2014 and 2013(a):

	December 31, 2014											December 31, 2013
	Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Asset category:	(In millions)
Short-term investments (b)	$	6		$	—		$	—	$	6		$	5	$	—	$	—	$	5
Equity securities
U.S. large cap (c)	266			—			—		266			302		—		—		302
U.S. small/mid cap (d)	149			—			—		149			147		—		—		147
Non U.S. (e)	222			59			—		281			282		9		—		291
Fixed income securities (f)	15			360			—		375			17		350		—		367
Hedge funds and similar investments (g)	107			45			168		320			130		25		159		314
Private equity and other (h)	—			—			131		131			—		—		101		101
Securities lending (i)	(141		)	(17		)	—		(158		)	—		—		—		—
Securities lending collateral (i)	141			17			—		158			—		—		—		—
Total	$	765		$	464		$	299	$	1,528		$	883	$	384	$	260	$	1,527

_______________________________________

(a) For a description of levels within the fair value hierarchy see Note 11 to the Consolidated Financial Statements, "Fair Value".

(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.

(i) In 2014, DTE Energy began a securities lending program with a third party agent. The program allows the agent to lend certain securities from the Company's VEBA trust to selected entities against receipt of collateral (in the form of cash) as provided for and determined in accordance with its securities lending agency agreement.

Target allocations for other postretirement benefit plan assets as of December 31, 2014 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

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

	Year Ended December 31, 2014									Year Ended December 31, 2013
	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	$	159		$	101		$	260		$	119	$	86		$	205
Total realized/unrealized gains (losses)	8			9			17			14		9			23
Purchases, sales and settlements:
Purchases	9			33			42			26		15			41
Sales	(8		)	(12		)	(20		)	—		(9		)	(9		)
Ending Balance at December 31	$	168		$	131		$	299		$	159	$	101		$	260
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	$	7		$	8		$	15		$	14	$	9		$	23

XML

Commitments and Contingencies (Details Textuals) (USD $)	1 Months Ended	12 Months Ended	0 Months Ended	4 Months Ended	8 Months Ended
	Apr. 30, 2014	Dec. 31, 2014	May 31, 2014	May 15, 2014 kWh	Dec. 31, 2014 kWh facilities dte_instances	Dec. 31, 2010 dte_instances	Dec. 31, 2013
Loss Contingencies [Line Items]
Number of NOVs						2
Possible Environmental Capital Expenditures to Comply with Requirements		$ 1,000,000
Estimated maximum spend to upgrade treatment technology to biological treatment to meet future requirements		13,000,000
Length of Notice of Intent to sue from the Group Against Smog and Pollution		60 days
Fine related to consent order and agreement with Allegheny County related to NOV	300,000
Estimated expenditures for a supplemental environmental project to enhance particulate collection efficiency		300,000
EPA Sulfur Dioxide Ambient Air Quality Standard		1 hour
Waiting Period of Policy		84 days
Total Purchase Commitments		9,015,000,000			9,015,000,000
Estimated future capital expenditures for next year		2,600,000,000			2,600,000,000
Gas [Member]
Loss Contingencies [Line Items]
Number of Former MGP Sites		15
Accrued for remediation related to the sites		24,000,000			24,000,000		28,000,000
Period Gas Utility Can Amortize MGP Costs		10 years
Electric [Member]
Loss Contingencies [Line Items]
Environmental Capital Expenditures Through Current Year		2,200,000,000
Estimated capital expenditures in next fiscal year		100,000,000
Environmental Capital Expenditures In Future Years		30,000,000
EPA is Alleging Power Plants Violated New Source Performance Standards		5			5
Number of NOVs/FOVs currently being discussed with the EPA		2			2
Time period to complete studies on cooling water intake structures impacts on fish - EPA ruling			3 years
Number of Former MGP Sites		3
Accrued for remediation related to the sites		10,000,000			10,000,000		8,000,000
Number of Permitted Engineered Ash Storage Facilities Owned		3
Insurance Coverage for Extra Expense when Power Plant Unavailable		490,000,000
Period of Coverage of Policy for Extra Expenses		3 years
Primary Coverage		1,500,000,000.0
Coverage for Stabilization Decontamination Debris Removal Repair and Replacement of Property and Decommissioning		1,250,000,000.00
Combined Coverage Limit for Total Property Damage		2,750,000,000.00
Insurance Deductible for Nuclear Power Plant		1,000,000			1,000,000
Total Limit for Property Damage for Non-Nuclear Events		2,000,000,000			2,000,000,000
Limit of Coverage for Aggregate Extra Expenses for Non-Nuclear Events		328,000,000
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		35,000,000
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		127,000,000
Limit Deferred Premium Charges Per Year		19,000,000
Company Obligated to Pay DOE Fee of Fermi 2 Electricity Generated and Sold				1
Court of Appeals proposal to congress to reduce nuclear waste fee, amount					0
Synthetic Fuel [Member]
Loss Contingencies [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted		1,000,000,000			1,000,000,000
Reduced Emissions Fuel Guarantees [Member]
Loss Contingencies [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted		172,000,000			172,000,000
Guarantee Type, Other [Member]
Loss Contingencies [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted		60,000,000			60,000,000
Surety Bond [Member]
Loss Contingencies [Line Items]
Performance Bonds Outstanding		$ 49,000,000			$ 49,000,000
Represented Employees [Member]
Loss Contingencies [Line Items]
Number of Represented Employees		4,900			4,900
Cleanup completed and site closed [Member] | Gas [Member]
Loss Contingencies [Line Items]
Number of Former MGP Sites		3
Partial closure expected by end of fiscal year [Member] | Gas [Member]
Loss Contingencies [Line Items]
Number of Former MGP Sites		2

XML

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2014

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

A reconciliation of both calculations is presented in the following table as of December 31:

	2014		2013		2012
	(In millions, expect per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	905	$	661	$	610
Average number of common shares outstanding	177		175		171
Weighted average net restricted shares outstanding	—		1		1
Dividends declared — common shares	$	475	$	453	$	413
Dividends declared — net restricted shares	1		1		1
Total distributed earnings	$	476	$	454	$	414
Net income less distributed earnings	$	429	$	207	$	196
Distributed (dividends per common share)	$	2.69	$	2.59	$	2.42
Undistributed	2.42		1.17		1.14
Total Basic Earnings per Common Share	$	5.11	$	3.76	$	3.56
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	905	$	661	$	610
Average number of common shares outstanding	177		175		171
Average incremental shares from assumed exercise of options	—		—		1
Common shares for dilutive calculation	177		175		172
Weighted average net restricted shares outstanding	—		1		1
Dividends declared — common shares	$	475	$	453	$	413
Dividends declared — net restricted shares	1		1		1
Total distributed earnings	$	476	$	454	$	414
Net income less distributed earnings	$	429	$	207	$	196
Distributed (dividends per common share)	$	2.69	$	2.59	$	2.42
Undistributed	2.41		1.17		1.13
Total Diluted Earnings per Common Share	$	5.10	$	3.76	$	3.55

XML

Retirement Benefits and Trusteed Assets (Pension Plan - Other Changes in Plan Assets and Benefit Obligations recognized in Reg Assets and OCI) (Details) (Pension Plan, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Pension Plan
Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income
Net actuarial (gain) loss	$ 805	$ (581)
Amortization of net actuarial loss	(157)	(208)
Prior service cost	(7)	0
Total recognized Regulatory assets and Other comprehensive income	641	(789)
Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income	820	(561)
Estimated amounts to be amortized from Regulatory assets and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year
Future amortization of net actuarial loss into net periodic benefit cost	$ 206	$ 151

XML

Consolidated Statements of Financial Position (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current Assets
Cash and cash equivalents	$ 48	$ 52
Restricted cash, principally Securitization	120	123
Accounts receivable (less allowance for doubtful accounts of $54 and $55, respectively)
Customer	1,504	1,542
Other	94	127
Inventories
Fuel and gas	512	363
Materials and supplies	292	265
Derivative assets	128	99
Regulatory assets	76	26
Other	313	209
Total Current Assets	3,087	2,806
Investments
Nuclear decommissioning trust funds	1,241	1,191
Other	628	603
Total Investments	1,869	1,794
Property
Property, plant and equipment	26,538	25,123
Less accumulated depreciation, depletion and amortization	(9,718)	(9,323)
Property, plant and equipment, net	16,820	15,800
Other Assets
Goodwill	2,018	2,018
Regulatory assets	3,651	2,837
Securitized regulatory assets	34	231
Intangible assets	102	122
Notes receivable	90	102
Derivative assets	44	27
Other	259	198
Total Noncurrent Assets	6,198	5,535
Total Assets	27,974	25,935
Current Liabilities
Accounts payable	973	962
Accrued interest	86	90
Dividends payable	122	116
Short-term borrowings	398	131
Current portion long-term debt, including capital leases	274	898
Derivative liabilities	77	195
Regulatory liabilities	153	302
Other	494	495
Total Current Liabilities	2,577	3,189
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	7,860	6,618
Securitization bonds	0	105
Junior subordinated debentures	480	480
Capital lease obligations	3	11
Total Long-Term Debt (net of current portion)	8,343	7,214
Other Liabilities
Deferred income taxes	3,776	3,321
Regulatory liabilities	667	862
Asset retirement obligations	1,962	1,827
Unamortized investment tax credit	41	47
Derivative liabilities	8	43
Accrued pension liability	1,280	653
Accrued postretirement liability	515	350
Nuclear decommissioning	182	178
Other	281	297
Total Noncurrent Liabilities	8,712	7,578
Commitments and Contingencies (Notes 8 and 17)
Equity
Common stock, without par value, 400,000,000 shares authorized, 176,991,231 and 177,087,230 shares issued and outstanding, respectively	3,904	3,907
Retained earnings	4,578	4,150
Accumulated other comprehensive loss	(155)	(136)
Total DTE Energy Company Equity	8,327	7,921
Noncontrolling interests	15	33
Total Equity	8,342	7,954
Total Liabilities and Equity	$ 27,974	$ 25,935

XML

Financial and Other Derivative Instruments (Netting Offsets of Derivative Assets and Liabilites) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Offsetting Assets [Line Items]
Total fair value of derivatives	$ 1,178	$ 833
Derivative Asset, Fair Value, Gross Liability	(1,006)	(707)
Net Amounts of Assets Presented in the Statements of Financial Position	172	126
Fair Value Gross Amounts of Recognized (Liabilities)	(1,110)	(936)
Derivative Liability, Fair Value, Gross Asset	1,025	698
Net Amounts of (Liabilities) Presented in the Statements of Financial Position	(85)	(238)
Natural Gas Commodity Contract [Member]
Offsetting Assets [Line Items]
Total fair value of derivatives	787	396
Derivative Asset, Fair Value, Gross Liability	(681)	(382)
Net Amounts of Assets Presented in the Statements of Financial Position	106	14
Fair Value Gross Amounts of Recognized (Liabilities)	(718)	(503)
Derivative Liability, Fair Value, Gross Asset	679	395
Net Amounts of (Liabilities) Presented in the Statements of Financial Position	(39)	(108)
Electricity Commodity Contract [Member]
Offsetting Assets [Line Items]
Total fair value of derivatives	342	400
Derivative Asset, Fair Value, Gross Liability	(280)	(291)
Net Amounts of Assets Presented in the Statements of Financial Position	62	109
Fair Value Gross Amounts of Recognized (Liabilities)	(342)	(398)
Derivative Liability, Fair Value, Gross Asset	298	269
Net Amounts of (Liabilities) Presented in the Statements of Financial Position	(44)	(129)
Other Commodity Contract [Member]
Offsetting Assets [Line Items]
Total fair value of derivatives	45	37
Derivative Asset, Fair Value, Gross Liability	(42)	(34)
Net Amounts of Assets Presented in the Statements of Financial Position	3	3
Fair Value Gross Amounts of Recognized (Liabilities)	(45)	(34)
Derivative Liability, Fair Value, Gross Asset	45	34
Net Amounts of (Liabilities) Presented in the Statements of Financial Position	0	0
Other Derivative Contract [Member]
Offsetting Assets [Line Items]
Total fair value of derivatives	4	0
Derivative Asset, Fair Value, Gross Liability	(3)	0
Net Amounts of Assets Presented in the Statements of Financial Position	1	0
Fair Value Gross Amounts of Recognized (Liabilities)	(5)	(1)
Derivative Liability, Fair Value, Gross Asset	3	0
Net Amounts of (Liabilities) Presented in the Statements of Financial Position	$ (2)	$ (1)

XML

Significant Accounting Policies (Notes)

12 Months Ended

Dec. 31, 2014

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.

For further discussion of recovery mechanisms authorized by the MPSC see Note 8 to the Consolidated Financial Statements, "Regulatory Matters".

Non-utility businesses recognize revenues as services are provided and products are delivered. For discussion of derivative contracts see Note 12 to the Consolidated Financial Statements, "Financial and Other Derivative Instruments".

Other Income

Other income is recognized for non-operating income such as equity earnings, allowance for equity funds used 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 $78 million, $81 million and $63 million of Other income for the years ended December 31, 2014, 2013 and 2012, 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.

Changes in Accumulated Other Comprehensive 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. The amounts recorded to accumulated other comprehensive loss include unrealized gains and losses from derivatives accounted for as cash flow hedges, unrealized gains and losses on available-for-sale securities and 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 foreign currency translation adjustments.

The following table summarizes the changes in Accumulated other comprehensive loss by component for the years ended December 31, 2014 and 2013:

	Changes in Accumulated Other Comprehensive Loss by Component (a)
	Net Unrealized Gain/(Loss) on Derivatives			Net Unrealized Gain/(Loss) on Investments			Benefit Obligations (b)			Foreign Currency Translation			Total
	(In millions)
Balance, January 1, 2013	$	(4	)	$	(8	)	$	(148	)	$	2		$	(158	)
Other comprehensive income (loss) before reclassifications	—			2			13			(2		)	13
Amounts reclassified from accumulated other comprehensive income	—			—			9			—			9
Net current-period other comprehensive income (loss)	—			2			22			(2		)	22
Balance, December 31, 2013	$	(4	)	$	(6	)	$	(126	)	$	—		$	(136	)
Other comprehensive income (loss) before reclassifications	—			1			(25		)	(2		)	(26		)
Amounts reclassified from accumulated other comprehensive income	—			—			7			—			7
Net current-period other comprehensive income (loss)	—			1			(18		)	(2		)	(19		)
Balance, December 31, 2014	$	(4	)	$	(5	)	$	(144	)	$	(2	)	$	(155	)

______________________________________

(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 18 to the Consolidated Financial Statements "Retirement Benefits and Trusteed Assets").

Cash, 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 $773 million and $815 million are included in customer accounts receivable at December 31, 2014 and 2013, 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 $43 million and $4 million as of December 31, 2014 and 2013, respectively, at DTE Gas is determined using the last-in, first-out (LIFO) method. At December 31, 2014, the replacement cost of gas remaining in storage exceeded the LIFO cost by $110 million. At December 31, 2013, the replacement cost of gas remaining in storage exceeded the LIFO cost by $170 million.

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

Property is stated at cost and includes construction-related labor, materials, overheads and AFUDC for utility property. 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 $16 million and $26 million of expenses related to Fermi 2 refueling outages were accrued at December 31, 2014 and 2013, respectively. Amounts are accrued on a pro-rata basis, generally over an 18-month period, that coincides with scheduled refueling outages at Fermi 2. This accrual of outage costs matches the regulatory recovery of these costs in rates set by the MPSC. See Note 8 to the Consolidated Financial Statements, "Regulatory Matters".

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, 2014		December 31, 2013
	(In millions)
Emission allowances	$	1	$	2
Renewable energy credits	45		51
Contract intangible assets	122		126
	168		179
Less accumulated amortization	57		45
Intangible assets, net	111		134
Less current intangible assets	9		12
	$	102	$	122

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 27 years. Intangible assets amortization expense was $12 million in 2014, $14 million in 2013 and $6 million in 2012.

The following table summarizes the estimated amortization expense expected to be recognized during each year through 2019:

Estimated amortization expense	(In millions)
2015	$	12
2016	$	11
2017	$	8
2018	$	8
2019	$	6

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 11 of the Consolidated Financial Statements, "Fair Value".

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 $25 million, $18 million and $21 million for the years ended December 31, 2014, 2013 and 2012, 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.

Other Accounting Policies

See the following notes for other accounting policies impacting the Company’s Consolidated Financial Statements:

Note	Title
7	Asset Retirement Obligations
8	Regulatory Matters
9	Income Taxes
11	Fair Value
12	Financial and Other Derivative Instruments
19	Stock-Based Compensation

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Significant Accounting Policies (Intangible Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Intangible Assets, Gross (Excluding Goodwill)	$ 168	$ 179
Less: Accumulated Amortization	57	45
Intangible Assets, Net	111	134
Less current intangible assets	9	12
Intangible assets, noncurrent	102	122
Renewable Energy Credits [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible Assets, Gross	45	51
Contract Intangible Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible Assets, Gross	122	126
Emission Allowances [Member]
Finite-Lived Intangible Assets [Line Items]
Indefinite-Lived Intangible Assets (Excluding Goodwill)	$ 1	$ 2

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Fair Value (Fair Value of Financial Instruments) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes receivable, excluding capital leases	$ 41	$ 41
Dividends payable	122	116
Short-term borrowings	398	131
Long-term debt, excluding capital leases	8,606	8,094
Estimate of Fair Value Measurement [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes receivable, excluding capital leases	0	0
Dividends payable	122	116
Short-term borrowings	0	0
Long-term debt, excluding capital leases	489	425
Estimate of Fair Value Measurement [Member] | Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes receivable, excluding capital leases	0	0
Dividends payable	0	0
Short-term borrowings	398	131
Long-term debt, excluding capital leases	8,308	7,551
Estimate of Fair Value Measurement [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes receivable, excluding capital leases	41	41
Dividends payable	0	0
Short-term borrowings	0	0
Long-term debt, excluding capital leases	$ 706	$ 499

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Retirement Benefits and Trusteed Assets (Pension Plan - Pension Cost Inclusions) (Details) (Pension Plan, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Plan
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	$ 83	$ 94	$ 82
Interest cost	212	192	204
Expected return on plan assets	(273)	(266)	(244)
Amortization of Net Loss	157	208	176
Special termination benefits	0	0	2
Net pension cost	$ 179	$ 228	$ 220

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Asset Retirement Obligations (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2014
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.
Liabilities balance upon completion of decommissioning	$ 0
Fermi 2 [Member]
Asset Retirement Obligations [Line Items]
Nuclear decommissioning liabilities funded through surcharge and included in ARO balance	$ 1,700,000,000

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Stock-Based Compensation (Notes)

12 Months Ended

Dec. 31, 2014

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. 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. Key provisions of the stock incentive program are:

• Authorized limit is 14,500,000 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.

The following table summarizes the components of stock-based compensation:

	2014		2013		2012
	(In millions)
Stock-based compensation expense	$	103	$	99	$	83
Tax benefit	40		38		33
Stock-based compensation cost capitalized in property, plant and equipment	16		15		5

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.

The following table summarizes our stock option activity for the year ended December 31, 2014:

	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In millions)
Options outstanding at December 31, 2013	723,697		$	42.60
Granted	—		$	—
Exercised	(268,689	)	$	41.14
Forfeited or expired	(10,730	)	$	39.41
Options outstanding and exercisable at December 31, 2014	444,278		$	43.56	$	17

As of December 31, 2014, the weighted average remaining contractual life for the exercisable shares is 3.41 years. As of December 31, 2014, all options were vested. No options vested during 2014.

There were no options granted during 2014, 2013 or 2012. The intrinsic value of options exercised for the years ended December 31, 2014, 2013 and 2012 was $11 million, $12 million and $25 million, respectively. Total option expense recognized was zero for 2014 and 2013 and $0.7 million for 2012.

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

Range of Exercise Prices					Number of Options	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)
$	27.00	—	$	38.00	25,857	$	27.70	4.16
$	38.01	—	$	42.00	82,834	$	41.77	3.16
$	42.01	—	$	45.00	221,487	$	43.93	4.06
$	45.01	—	$	50.00	114,100	$	47.75	2.15
					444,278	$	43.56	3.41

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:

	2014		2013		2012
Fair value of awards vested (in millions)	$	11	$	8	$	9
Restricted common shares awarded	159,590		127,785		167,320
Weighted average market price of shares awarded	$	70.09	$	64.72	$	53.71
Compensation cost charged against income (in millions)	$	10	$	23	$	12

The following table summarizes the Company’s restricted stock awards activity for the year ended December 31, 2014:

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at December 31, 2013	492,329		$	53.76
Grants	159,590		$	70.09
Forfeitures	(16,841	)	$	62.41
Vested and issued	(218,760	)	$	47.77
Balance at December 31, 2014	416,318		$	62.82

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. Awards granted in 2014 were primarily deemed to be equity awards. The stock price and number of probable shares attributable to market conditions for such equity awards are fair valued only at the grant date. Performance shares awarded prior to 2014 are liability awards and are remeasured to fair value at each reporting period. 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:

	2014		2013		2012
	(In millions)
Compensation expense	$	93	$	77	$	71
Cash settlements (a)	$	11	$	9	$	4
Stock settlements (a)	$	61	$	56	$	41

_______________________________________

(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, 2014:

	Performance Shares		Weighted Average Grant Date Fair Value
Balance at December 31, 2013	1,608,789		$	—
Grants	561,335		$	69.32
Forfeitures	(44,250	)	$	69.16
Payouts	(571,177	)	$	—
Balance at December 31, 2014	1,554,697		$	69.32

Unrecognized Compensation Costs

As of December 31, 2014, the total unrecognized compensation cost related to non-vested stock incentive plan arrangements and the weighted average recognition period was as follows:

	Unrecognized Compensation Cost		Weighted Average to be Recognized
	(In millions)		(In years)
Stock awards	$	10	1.06
Performance shares	48		0.98
	$	58	0.99

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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, USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
2015	$ 101
2016	107
2017	111
2018	117
2019	122
2020-2024	660
Total Expected Future Benefit Payments	$ 1,218

XML

Stock-Based Compensation (Unrecognized Compensation Costs) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Share Based Compensation Unrecognized and Non-Vested Cost [Line Items]
Unrecognized Compensation Cost	$ 58
Weighted Average to be Recognized	11 months 25 days
Restricted Stock [Member]
Share Based Compensation Unrecognized and Non-Vested Cost [Line Items]
Unrecognized Compensation Cost	10
Weighted Average to be Recognized	1 year 23 days
Performance Shares [Member]
Share Based Compensation Unrecognized and Non-Vested Cost [Line Items]
Unrecognized Compensation Cost	$ 48
Weighted Average to be Recognized	11 months 22 days

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Stock-Based Compensation (Restricted Stock Award Activity) (Details) (Restricted Stock [Member], USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of awards vested (in millions)	$ 11	$ 8	$ 9
Restricted common shares awarded (in shares)	159,590	127,785	167,320
Weighted average market price of shares awarded	$ 70.09	$ 64.72	$ 53.71
Compensation cost charged against income (in millions)	$ 10	$ 23	$ 12

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Income Taxes (Components of Income Tax Expense) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current income tax expense (benefit)
Federal	$ (16)	$ 74	$ 190
State and other income tax	24	16	49
Total current income taxes	8	90	239
Deferred income tax expense
Federal	289	122	39
State and other income tax	67	42	8
Total deferred income taxes	356	164	47
Income tax expense	364	254	286
Discontinued operations	0	0	(29)
Total	$ 364	$ 254	$ 257

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2014

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

A reconciliation of the asset retirement obligations for 2014 follows:

	(In millions)
Asset retirement obligations at December 31, 2013	$	1,827
Accretion	112
Liabilities incurred	11
Liabilities settled	(12		)
Revision in estimated cash flows	24
Asset retirement obligations at December 31, 2014	$	1,962

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Financial and Other Derivative Instruments (Notes)

12 Months Ended

Dec. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [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 electricity, 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.

DTE 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 MTM and recoverable through the PSCR mechanism when settled. This results in the deferral of unrealized gains and losses as Regulatory assets or liabilities until realized.

DTE 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 natural gas supply requirements through March 2017. 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, 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.

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, 2014 and 2013 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 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, 2014 and 2013:

	December 31, 2014					December 31, 2013
	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	4	$	(5	)	$	—	$	(1	)
Commodity Contracts:
Natural Gas	787		(718		)	396		(503		)
Electricity	342		(342		)	400		(398		)
Other	45		(45		)	37		(34		)
Total derivatives not designated as hedging instruments:	$	1,178	$	(1,110	)	$	833	$	(936	)
Total derivatives:
Current	$	1,083	$	(1,041	)	$	691	$	(773	)
Noncurrent	95		(69		)	142		(163		)
Total derivatives	$	1,178	$	(1,110	)	$	833	$	(936	)

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 $7 million and $19 million at December 31, 2014 and 2013, respectively, which could be used to offset net derivative liabilities. Letters of credit received from third parties which could be used to offset our net derivative assets were approximately $5 million and $1 million at December 31, 2014 and 2013, respectively. 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.

The total cash collateral posted, net of cash collateral received, was $61 million and $12 million as of December 31, 2014 and 2013, respectively. There was no cash collateral related to unrealized positions to net against derivative assets while derivative liabilities are shown net of cash collateral of $19 million as of December 31, 2014. As of December 31, 2013, derivative assets and derivative liabilities are shown net of cash collateral of $26 million and $17 million, respectively. The Company recorded cash collateral paid of $44 million and cash collateral received of $2 million not related to unrealized derivative positions as of December 31, 2014. 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. 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, 2014 and 2013:

	December 31, 2014									December 31, 2013
	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	$	787		$	(681	)	$	106		$	396		$	(382	)	$	14
Electricity	342			(280		)	62			400			(291		)	109
Other	45			(42		)	3			37			(34		)	3
Other derivative contracts (a)	4			(3		)	1			—			—			—
Total derivative assets	$	1,178		$	(1,006	)	$	172		$	833		$	(707	)	$	126
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(718	)	$	679		$	(39	)	$	(503	)	$	395		$	(108	)
Electricity	(342		)	298			(44		)	(398		)	269			(129		)
Other	(45		)	45			—			(34		)	34			—
Other derivative contracts (a)	(5		)	3			(2		)	(1		)	—			(1		)
Total derivative liabilities	$	(1,110	)	$	1,025		$	(85	)	$	(936	)	$	698		$	(238	)

_______________________________________

(a) Primarily includes Foreign currency exchange contracts

The following table presents the netting offsets of derivative assets and liabilities at December 31, 2014 and 2013:

	December 31, 2014												December 31, 2013
	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	$	1,083		$	95		$	(1,041	)	$	(69	)	$	691		$	142		$	(773	)	$	(163	)
Counterparty netting	(955		)	(51		)	955			51			(566		)	(115		)	566			115
Collateral adjustment	—			—			9			10			(26		)	—			12			5
Total derivatives as reported	$	128		$	44		$	(77	)	$	(8	)	$	99		$	27		$	(195	)	$	(43	)

The effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for years ended December 31, 2014 and 2013 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		2014			2013
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	(2	)	$	(1	)
Commodity Contracts:
Natural Gas	Operating Revenue	(30		)	(48		)
Natural Gas	Fuel, purchased power and gas	(5		)	(44		)
Electricity	Operating Revenue	123			82
Other	Operating Revenue	(7		)	—
Total		$	79		$	(11	)

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 MTM 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 MTM method with unrealized and realized gains and losses for sales recorded in Operating revenue and purchases recorded in Fuel, purchased power and gas.

The following represents the cumulative gross volume of derivative contracts outstanding as of December 31, 2014:

Commodity	Number of Units
Natural Gas (MMBtu)	895,599,953
Electricity (MWh)	11,296,153
Foreign Currency Exchange (Canadian dollars)	63,022,462

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 require 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 required 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, 2014, DTE Energy's contractual obligation to post collateral 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 $349 million.

As of December 31, 2014, the Company had approximately $1,058 million of derivatives in net liability positions, for which hard triggers exist. Collateral of approximately $12 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 $973 million. The net remaining amount of approximately $73 million is derived from the $349 million noted above.

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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, 2014
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2015	$ 42
2016	34
2017	28
2018	23
2019	14
Thereafter	78
Total minimum lease payments	$ 219