DTE Energy (DTE) 10-K 2014 FY Annual report

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.

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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

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FORWARD-LOOKING STATEMENTS

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

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• 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

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UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table provides information about our purchases of equity securities that are registered by the Company pursuant to Section 12 of the Exchange Act of 1934 for the quarter ended December 31, 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 margin increased 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 expense decreased $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 amortizationexpense increased $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 deductions decreased $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.

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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 margin increased $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 maintenanceexpense increased $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 deductions increased $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 revenues increased $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 expense increased $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 amortizationexpense increased $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 deductions decreased $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 revenues increased $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 maintenanceexpense increased $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, net increased 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 deductions decreased 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 credits increased 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 margin increased $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 2014 net loss of $57 million represented an increase of $13 million from the 2013 net 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 2013 net loss of $44 million represented an improvement of $3 million from the 2012 net 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)
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	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