10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

___________________________________

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period ended June 30, 2013

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	(I.R.S. Employer
incorporation or organization)	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)

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.

YesxNoo

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

YesxNoo

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

YesoNox

At June 30, 2013, 174,960,000 shares of DTE Energy’s common stock were outstanding, substantially all of which were held by non-affiliates.

DTE Energy Company

Quarterly Report on Form 10-Q

Quarter Ended June 30, 2013

TABLE OF CONTENTS

	Page
Definitions	1
Forward-Looking Statements	3
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements	4
Consolidated Statements of Operations (Unaudited)	4
Consolidated Statements of Comprehensive Income (Unaudited)	5
Consolidated Statements of Financial Position (Unaudited)	6
Consolidated Statements of Cash Flows (Unaudited)	8
Consolidated Statement of Changes in Equity (Unaudited)	9
Notes to Consolidated Financial Statements (Unaudited)	10
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
Item 3. Quantitative and Qualitative Disclosures About Market Risk	52
Item 4. Controls and Procedures	55
PART II — OTHER INFORMATION
Item 1. Legal Proceedings	56
Item 1A. Risk Factors	56
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	57
Item 6. Exhibits	57
SIGNATURE	58
EX-12-54
EX-31-83
EX-31-84
EX-32-83
EX-32-84
EX-101.INS XBRL INSTANCE DOCUMENT
EX-101.SCH XBRL TAXONOMY EXTENSION SCHEMA
EX-101.CAL XBRL TAXONOMY EXTENSION CALCULATION LINKBASE
EX-101.DEF XBRL TAXONOMY EXTENSION DEFINITION DATABASE
EX-101.LAB XBRL TAXONOMY EXTENSION LABEL LINKBASE
EX-101.PRE XBRL TAXONOMY EXTENSION PRESENTATION LINKBASE

DEFINITIONS

ASC	Accounting Standards Codification
ASU	Accounting Standards Update
Citizens	Citizens Fuel Gas Company, which distributes natural gas in Adrian, Michigan
Company	DTE Energy Company and any subsidiary companies
Customer Choice	Michigan legislation giving customers the option to choose alternative suppliers for electricity and natural gas.
DTE Electric	DTE Electric Company (a direct wholly owned subsidiary of DTE Energy Company) and subsidiary companies. Formerly known as The Detroit Edison Company.
DTE Energy	DTE Energy Company, directly or indirectly the parent of DTE Electric, DTE Gas and numerous non-utility subsidiaries
DTE Gas	DTE Gas Company (an indirect wholly owned subsidiary of DTE Energy) and subsidiary companies. Formerly known as Michigan Consolidated Gas Company.
EPA	United States Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FTRs	Financial transmission rights are financial instruments that entitle the holder to receive payments related to costs incurred for congestion on the transmission grid.
GCR	A Gas Cost Recovery mechanism authorized by the MPSC that allows DTE Gas to recover through rates its natural gas costs.
MCIT	Michigan Corporate Income Tax
MDEQ	Michigan Department of Environmental Quality
MISO	Midwest Independent System Operator is an Independent System Operator and the Regional Transmission Organization serving the Midwest United States and Manitoba, Canada.
MPSC	Michigan Public Service Commission
Non-utility	An entity that is not a public utility. Its conditions of service, prices of goods and services and other operating related matters are not directly regulated by the MPSC.
NRC	United States Nuclear Regulatory Commission
Production tax credits	Tax credits as authorized under Sections 45K and 45 of the Internal Revenue Code that are designed to stimulate investment in and development of alternate fuel sources. The amount of a production tax credit can vary each year as determined by the Internal Revenue Service.
PSCR	A Power Supply Cost Recovery mechanism authorized by the MPSC that allows DTE Electric to recover through rates its fuel, fuel-related and purchased power costs.
RDM	A Revenue Decoupling Mechanism authorized by the MPSC that is designed to minimize the impact on revenues of changes in average customer usage.
Securitization	DTE Electric financed specific stranded costs at lower interest rates through the sale of rate reduction bonds by a wholly-owned special purpose entity, The Detroit Edison Securitization Funding LLC.
Subsidiaries	The direct and indirect subsidiaries of DTE Energy Company
VIE	Variable Interest Entity

1

Units of Measurement
Bcf	Billion cubic feet of natural gas
Bcfe	Conversion metric using a standard ratio of one barrel of oil and/or natural gas liquids to 6 Mcf of natural gas equivalents.
BTU	Heat value (energy content) of fuel
dth/d	Decatherms per day
kWh	Kilowatthour of electricity
Mcf	Thousand cubic feet of natural gas
MMcf	Million cubic feet of natural gas
MW	Megawatt of electricity
MWh	Megawatthour of electricity

2

FORWARD-LOOKING STATEMENTS

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

• impact of regulation by the FERC, MPSC, NRC 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;

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

• economic conditions and population changes in our geographic area resulting in changes in demand, customer conservation, increased thefts of electricity and natural gas and high levels of uncollectible accounts receivable;

• 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;

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

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

• the timing and extent of changes in interest rates;

• the level of borrowings;

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

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

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

• unplanned outages;

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

• employee relations and the impact of collective bargaining agreements;

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

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

• the effects of competition;

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

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

• binding arbitration, litigation and related appeals; and

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

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

3

Part I — FINANCIAL INFORMATION

Item 1. Financial Statements

DTE Energy Company

Consolidated Statements of Operations (Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(In millions, except per share amounts)
Operating Revenues	$	2,225		$	2,013		$	4,741		$	4,252
Operating Expenses
Fuel, purchased power and gas	940			697			1,964			1,586
Operation and maintenance	705			703			1,440			1,424
Depreciation, depletion and amortization	268			244			527			471
Taxes other than income	84			79			178			174
Asset (gains) and losses, reserves and impairments, net	5			(4		)	(1		)	(9		)
	2,002			1,719			4,108			3,646
Operating Income	223			294			633			606
Other (Income) and Deductions
Interest expense	112			109			221			222
Interest income	(3		)	(3		)	(5		)	(5		)
Other income	(46		)	(41		)	(90		)	(78		)
Other expenses	9			11			16			18
	72			76			142			157
Income Before Income Taxes	151			218			491			449
Income Tax Expense	44			70			149			143
Income from Continuing Operations	107			148			342			306
Loss from Discontinued Operations, net of tax	—			(1		)	—			(1		)
Net Income	107			147			342			305
Less: Net Income Attributable to Noncontrolling Interest	2			1			3			3
Net Income Attributable to DTE Energy Company	$	105		$	146		$	339		$	302
Basic Earnings per Common Share
Income from continuing operations	$	0.60		$	0.87		$	1.94		$	1.78
Loss from discontinued operations, net of tax	—			(0.01		)	—			(0.01		)
Total	$	0.60		$	0.86		$	1.94		$	1.77
Diluted Earnings per Common Share
Income from continuing operations	$	0.60		$	0.87		$	1.94		$	1.78
Loss from discontinued operations, net of tax	—			(0.01		)	—			(0.01		)
Total	$	0.60		$	0.86		$	1.94		$	1.77
Weighted Average Common Shares Outstanding
Basic	174			170			174			170
Diluted	175			171			174			171
Dividends Declared per Common Share	$	0.66		$	0.59		$	1.28		$	1.18

See Notes to Consolidated Financial Statements (Unaudited)

4

DTE Energy Company

Consolidated Statements of Comprehensive Income (Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(In millions)
Net income	$	107		$	147		$	342		$	305
Other comprehensive income (loss), net of tax:
Benefit obligations:
Benefit obligations, net of taxes of $1, $1, $2 and $3, respectively	2			3			5			6
	2			3			5			6
Net unrealized gains on investments:
Gains during the period, net of taxes of $—, $—, $— and $—	—			—			—			1
	—			—			—			1
Foreign currency translation, net of taxes of $(1), $—, $(1) and $—	(1		)	(1		)	(2		)	—
Other comprehensive income	1			2			3			7
Comprehensive income	108			149			345			312
Less comprehensive income attributable to noncontrolling interests	2			1			3			3
Comprehensive income attributable to DTE Energy Company	$	106		$	148		$	342		$	309

See Notes to Consolidated Financial Statements (Unaudited)

5

DTE Energy Company

Consolidated Statements of Financial Position (Unaudited)

	June 30,			December 31,
	2013			2012
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	46		$	65
Restricted cash, principally Securitization	112			122
Accounts receivable (less allowance for doubtful accounts of $63 and $62, respectively)
Customer	1,314			1,336
Other	102			126
Inventories
Fuel and gas	378			527
Materials and supplies	249			234
Deferred income taxes	—			21
Derivative assets	90			108
Regulatory assets	90			182
Other	115			194
	2,496			2,915
Investments
Nuclear decommissioning trust funds	1,080			1,037
Other	574			554
	1,654			1,591
Property
Property, plant and equipment	24,356			23,631
Less accumulated depreciation, depletion and amortization	(9,166		)	(8,947		)
	15,190			14,684
Other Assets
Goodwill	2,018			2,018
Regulatory assets	3,790			4,235
Securitized regulatory assets	326			413
Intangible assets	138			135
Notes receivable	106			112
Derivative assets	27			39
Other	199			197
	6,604			7,149
Total Assets	$	25,944		$	26,339

See Notes to Consolidated Financial Statements (Unaudited)

6

DTE Energy Company

Consolidated Statements of Financial Position (Unaudited) — (Continued)

	June 30,			December 31,
	2013			2012
	(In millions, except shares)
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	808		$	848
Accrued interest	97			93
Dividends payable	229			107
Short-term borrowings	216			240
Current portion long-term debt, including capital leases	879			817
Derivative liabilities	90			125
Gas inventory equalization	73			—
Other	570			538
	2,962			2,768
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	6,116			6,220
Securitization bonds	201			302
Junior subordinated debentures	480			480
Capital lease obligations	9			12
	6,806			7,014
Other Liabilities
Deferred income taxes	3,280			3,191
Regulatory liabilities	954			1,031
Asset retirement obligations	1,784			1,719
Unamortized investment tax credit	51			56
Derivative liabilities	16			26
Accrued pension liability	1,355			1,498
Accrued postretirement liability	702			1,160
Nuclear decommissioning	164			159
Other	283			306
	8,589			9,146
Commitments and Contingencies (Notes 7 and 12)
Equity
Common stock, without par value, 400,000,000 shares authorized, 174,960,000 and 172,351,680 shares issued and outstanding, respectively	3,762			3,587
Retained earnings	3,945			3,944
Accumulated other comprehensive loss	(155		)	(158		)
Total DTE Energy Company Equity	7,552			7,373
Noncontrolling interests	35			38
Total Equity	7,587			7,411
Total Liabilities and Equity	$	25,944		$	26,339

See Notes to Consolidated Financial Statements (Unaudited)

7

DTE Energy Company

Consolidated Statements of Cash Flows (Unaudited)

	Six Months Ended June 30,
	2013			2012
	(In millions)
Operating Activities
Net income	$	342		$	305
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	527			482
Deferred income taxes	123			81
Asset (gains) and losses, reserves and impairments, net	—			(7		)
Changes in assets and liabilities, exclusive of changes shown separately (Note 15)	275			300
Net cash from operating activities	1,267			1,161
Investing Activities
Plant and equipment expenditures — utility	(708		)	(708		)
Plant and equipment expenditures — non-utility	(197		)	(131		)
Proceeds from sale of assets	15			15
Restricted cash for debt redemption, principally Securitization	10			15
Proceeds from sale of nuclear decommissioning trust fund assets	27			36
Investment in nuclear decommissioning trust funds	(35		)	(44		)
Other	(23		)	(15		)
Net cash used for investing activities	(911		)	(832		)
Financing Activities
Issuance of long-term debt	371			496
Redemption of long-term debt	(515		)	(140		)
Short-term borrowings, net	(24		)	(380		)
Issuance of common stock	19			20
Dividends on common stock	(215		)	(199		)
Other	(11		)	(9		)
Net cash used for financing activities	(375		)	(212		)
Net Increase (Decrease) in Cash and Cash Equivalents	(19		)	117
Cash and Cash Equivalents at Beginning of Period	65			68
Cash and Cash Equivalents at End of Period	$	46		$	185

See Notes to Consolidated Financial Statements (Unaudited)

8

DTE Energy Company

Consolidated Statements of Changes in Equity (Unaudited)

							Accumulated Other Comprehensive Loss			Non-Controlling Interest
	Common Stock			Retained Earnings
	Shares	Amount											Total
	(Dollars in millions, shares in thousands)
Balance, December 31, 2012	172,352	$	3,587	$	3,944		$	(158	)	$	38		$	7,411
Net income	—	—		339			—			3			342
Dividends declared on common stock	—	—		(338		)	—			—			(338		)
Issuance of common stock	296	19		—			—			—			19
Contribution of common stock to pension plan	1,504	100		—			—			—			100
Foreign currency translation, net of tax	—	—		—			(2		)	—			(2		)
Benefit obligations, net of tax	—	—		—			5			—			5
Stock-based compensation, distributions to noncontrolling interests and other	808	56		—			—			(6		)	50
Balance, June 30, 2013	174,960	$	3,762	$	3,945		$	(155	)	$	35		$	7,587

See Notes to Consolidated Financial Statements (Unaudited)

9

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited)

NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION

Corporate Structure

DTE Energy owns the following businesses:

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

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

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

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

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

Basis of Presentation

These Consolidated Financial Statements should be read in conjunction with the Notes to Consolidated Financial Statements included in the 2012 Annual Report on Form 10-K.

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.

The Consolidated Financial Statements are unaudited, but in the Company's opinion include all adjustments necessary to a fair statement of the results for the interim periods. All adjustments are of a normal recurring nature, except as otherwise disclosed in these Consolidated Financial Statements and Notes to Consolidated Financial Statements. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2013.

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

Principles of Consolidation

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

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

10

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

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

The Company has variable interests in VIEs through certain of its long-term purchase contracts. As of June 30, 2013, the carrying amount of assets and liabilities in the Consolidated Statements of Financial Position that relate to its variable interests under long-term purchase contracts are predominately related to working capital accounts and generally represent the amounts owed by the Company for the deliveries associated with the current billing cycle under the contracts. The Company has not provided any form of financial support associated with these long-term contracts. There is no significant potential exposure to loss as a result of its variable interests through these long-term purchase contracts.

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

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

The following table summarizes the major balance sheet items for consolidated VIEs as of June 30, 2013 and December 31, 2012. All amounts included in the tables are considered restricted given they are 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.

	June 30, 2013						December 31, 2012
	Securitization		Other		Total		Securitization		Other		Total
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	8	$	8	$	—	$	10	$	10
Restricted cash	90		6		96		102		7		109
Accounts receivable	39		16		55		34		7		41
Inventories	—		91		91		—		141		141
Other current assets	—		1		1		—		1		1
Property, plant and equipment	—		103		103		—		93		93
Securitized regulatory assets	326		—		326		413		—		413
Other assets	6		9		15		7		11		18
	$	461	$	234	$	695	$	556	$	270	$	826
LIABILITIES
Accounts payable and accrued current liabilities	$	9	$	33	$	42	$	11	$	14	$	25
Current portion long-term debt, including capital leases	189		8		197		177		8		185
Current regulatory liabilities	45		—		45		50		—		50
Other current liabilities	—		3		3		—		4		4
Mortgage bonds, notes and other	—		23		23		—		25		25
Securitization bonds	201		—		201		302		—		302
Capital lease obligations	—		8		8		—		11		11
Other long-term liabilities	8		2		10		7		2		9
	$	452	$	77	$	529	$	547	$	64	$	611

11

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

Amounts for non-consolidated VIEs as of June 30, 2013 and December 31, 2012 are as follows:

	June 30, 2013		December 31, 2012
	(In millions)
Other investments	$	136	$	130
Notes receivable	6		6

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

Comprehensive Income

Comprehensive income is the change in common shareholders’ equity during a period from transactions and events from non-owner sources, including net income. As shown in the following tables, amounts recorded to accumulated other comprehensive loss for the three and six months ended June 30, 2013 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 transition amounts related to pension and other postretirement benefit plans, and foreign currency translation adjustments.

	Changes in Accumulated Other Comprehensive Loss by Component (a)
	For The Three Months Ended June 30, 2013
	Net Unrealized Gain/(Loss) on Derivatives			Net Unrealized Gain/(Loss) on Investments			Benefit Obligations (b)			Foreign Currency Translation			Total
	(In millions)
Beginning balance, March 31, 2013	$	(4	)	$	(8	)	$	(145	)	$	1		$	(156	)
Other comprehensive income before reclassifications	—			—			—			(1		)	(1		)
Amounts reclassified from accumulated other comprehensive income	—			—			2			—			2
Net current-period other comprehensive income	—			—			2			(1		)	1
Ending balance, June 30, 2013	$	(4	)	$	(8	)	$	(143	)	$	—		$	(155	)

	Changes in Accumulated Other Comprehensive Loss by Component (a)
	For The Six Months Ended June 30, 2013
	Net Unrealized Gain/(Loss) on Derivatives			Net Unrealized Gain/(Loss) on Investments			Benefit Obligations (b)			Foreign Currency Translation			Total
	(In millions)
Beginning balance, December 31, 2012	$	(4	)	$	(8	)	$	(148	)	$	2		$	(158	)
Other comprehensive income before reclassifications	—			—			—			(2		)	(2		)
Amounts reclassified from accumulated other comprehensive income	—			—			5			—			5
Net current-period other comprehensive income	—			—			5			(2		)	3
Ending balance, June 30, 2013	$	(4	)	$	(8	)	$	(143	)	$	—		$	(155	)

______________________________________

(a) All amounts are net of tax.

(b) The amounts reclassified from accumulated other comprehensive income are included in the computation of the net periodic pension cost (see Retirement Benefits and Trusteed Assets Note 13).

12

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

Intangible Assets

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

	June 30,		December 31,
	2013		2012
	(In millions)
Emission allowances	$	4	$	6
Renewable energy credits	47		44
Contract intangible assets	141		139
	192		189
Less accumulated amortization	40		34
Intangible assets, net	152		155
Less current intangible assets	14		20
	$	138	$	135

Emission allowances and renewable energy credits are charged to expense, using average cost, as the allowances and credits are consumed in the operation of the business. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 3 to 28 years.

Income Taxes

The Company's effective tax rate from continuing operations for the three months ended June 30, 2013 was 29 percent as compared to 32 percent for the three months ended June 30, 2012. The Company's effective tax rate from continuing operations for the six months ended June 30, 2013 was 30 percent as compared to 32 percent for the six months ended June 30, 2012. The decrease in the effective tax rate in 2013 is due primarily to higher production tax credits.

The Company had $3 million of unrecognized tax benefits at June 30, 2013, that, if recognized, would favorably impact its effective tax rate. The Company believes that it is possible that there will be a decrease in the unrecognized tax benefits of up to $1 million in the next twelve months.

13

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

NOTE 3 — FAIR VALUE

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The Company makes certain assumptions it believes that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and its counterparties is incorporated in the valuation of assets and liabilities through the use of credit reserves, the impact of which was immaterial at June 30, 2013 and December 31, 2012. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

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

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

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

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

14

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2013 and December 31, 2012:

	June 30, 2013															December 31, 2012
	Level 1			Level 2			Level 3			Netting (a)			Net Balance			Level 1			Level 2			Level 3			Netting (a)			Net Balance
	(In millions)
Assets:
Cash equivalents (b)	$	—		$	112		$	—		$	—		$	112		$	—		$	123		$	—		$	—		$	123
Nuclear decommissioning trusts	749			331			—			—			1,080			694			343			—			—			1,037
Other investments (c) (d)	72			47			—			—			119			66			44			—			—			110
Derivative assets:
Commodity Contracts:
Natural Gas	365			107			32			(490		)	14			555			66			24			(605		)	40
Electricity	—			219			98			(220		)	97			—			226			134			(258		)	102
Other	45			8			2			(49		)	6			6			3			2			(6		)	5
Total derivative assets	410			334			132			(759		)	117			561			295			160			(869		)	147
Total	$	1,231		$	824		$	132		$	(759	)	$	1,428		$	1,321		$	805		$	160		$	(869	)	$	1,417
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(1	)	$	—		$	—		$	(1	)	$	—		$	—		$	—		$	—		$	—
Interest rate contracts	—			—			—			—			—			—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(362		)	(86		)	(62		)	469			(41		)	(526		)	(73		)	(62		)	605			(56		)
Electricity	—			(221		)	(86		)	247			(60		)	—			(240		)	(111		)	258			(93		)
Other	(47		)	(5		)	—			48			(4		)	(6		)	(1		)	—			6			(1		)
Total derivative liabilities	(409		)	(313		)	(148		)	764			(106		)	(532		)	(315		)	(173		)	869			(151		)
Total	$	(409	)	$	(313	)	$	(148	)	$	764		$	(106	)	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)
Net Assets (Liabilities) at the end of the period	$	822		$	511		$	(16	)	$	5		$	1,322		$	789		$	490		$	(13	)	$	—		$	1,266
Assets:
Current	$	379		$	389		$	101		$	(667	)	$	202		$	493		$	372		$	120		$	(754	)	$	231
Noncurrent (e)	852			435			31			(92		)	1,226			828			433			40			(115		)	1,186
Total Assets	$	1,231		$	824		$	132		$	(759	)	$	1,428		$	1,321		$	805		$	160		$	(869	)	$	1,417
Liabilities:
Current	$	(368	)	$	(263	)	$	(119	)	$	660		$	(90	)	$	(466	)	$	(269	)	$	(144	)	$	754		$	(125	)
Noncurrent	(41		)	(50		)	(29		)	104			(16		)	(66		)	(46		)	(29		)	115			(26		)
Total Liabilities	$	(409	)	$	(313	)	$	(148	)	$	764		$	(106	)	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)
Net Assets (Liabilities) at the end of the period	$	822		$	511		$	(16	)	$	5		$	1,322		$	789		$	490		$	(13	)	$	—		$	1,266

_______________________________________

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

(b) At June 30, 2013, available-for-sale securities of $112 million included $96 million and $16 million of cash equivalents included in Restricted cash and Other investments, respectively, on the Consolidated Statements of Financial Position. At December 31, 2012, available-for-sale securities of $123 million, included $109 million and $14 million of cash equivalents included in Restricted cash and Other investments, respectively, on the Consolidated Statements of Financial Position.

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

(d) Available-for-sale equity securities of $6 million at June 30, 2013 and $5 million at December 31, 2012, are included in Other investments on the Consolidated Statements of Financial Position.

(e) Includes $119 million and $110 million at June 30, 2013 and December 31, 2012, respectively, of Other investments that are included in the Consolidated Statements of Financial Position in Other investments.

Cash Equivalents

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

15

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

Nuclear Decommissioning Trusts and Other Investments

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

Derivative Assets and Liabilities

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

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the three months and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30, 2013												Three Months Ended June 30, 2012
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of March 31	$	(34	)	$	(9	)	$	2		$	(41	)	$	6		$	25		$	6		$	37
Transfers into Level 3	—			—			—			—			1			—			—			1
Transfers out of Level 3	—			—			—			—			—			—			—			—
Total gains (losses):
Included in earnings	(2		)	18			(1		)	15			(1		)	56			(3		)	52
Recorded in regulatory assets/liabilities	—			—			3			3			—			—			4			4
Purchases, issuances and settlements:
Settlements	6			3			(2		)	7			(4		)	(31		)	(2		)	(37		)
Net Assets (Liabilities) as of June 30	$	(30	)	$	12		$	2		$	(16	)	$	2		$	50		$	5		$	57
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 June 30, 2013 and 2012 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(1	)	$	33		$	(1	)	$	31		$	(2	)	$	38		$	(3	)	$	33

16

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

	Six Months Ended June 30, 2013												Six Months Ended June 30, 2012
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of December 31	$	(38	)	$	23		$	2		$	(13	)	$	6		$	32		$	6		$	44
Transfers into Level 3	—			—			—			—			1			28			—			29
Transfers out of Level 3	(2		)	—			—			(2		)	(2		)	—			—			(2		)
Total gains (losses):
Included in earnings	(10		)	26			(1		)	15			6			41			(2		)	45
Recorded in regulatory assets/liabilities	—			—			4			4			—			—			5			5
Purchases, issuances and settlements:
Purchases	—			1			—			1			—			—			—			—
Settlements	20			(38		)	(3		)	(21		)	(9		)	(51		)	(4		)	(64		)
Net Assets (Liabilities) as of June 30	$	(30	)	$	12		$	2		$	(16	)	$	2		$	50		$	5		$	57
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 June 30, 2013 and 2012 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(6	)	$	27		$	(1	)	$	20		$	4		$	38		$	(2	)	$	40

Derivatives are transferred between levels primarily due to changes in the source data used to construct price curves as a result of changes in market liquidity. Transfers in and transfers out are reflected as if they had occurred at the beginning of the period. The following table shows transfers between the levels of the fair value hierarchy for the three months and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30, 2013					Three Months Ended June 30, 2012
	Level 1	Level 2		Level 3		Level 1	Level 2		Level 3
	(In millions)
Transfers into Level 1 from	$ N/A	$	—	$	—	$ N/A	$	—	$	—
Transfers into Level 2 from	—	N/A		—		—	N/A		—
Transfers into Level 3 from	—	—		N/A		—	1		N/A

	Six Months Ended June 30, 2013					Six Months Ended June 30, 2012
	Level 1	Level 2		Level 3		Level 1	Level 2		Level 3
	(In millions)
Transfers into Level 1 from	$ N/A	$	—	$	—	$ N/A	$	—	$	—
Transfers into Level 2 from	—	N/A		2		—	N/A		2
Transfers into Level 3 from	—	—		N/A		—	29		N/A

The following table presents the unobservable inputs related to Level 3 assets and liabilities as of June 30, 2013:

	June 30, 2013
Commodity Contracts	Derivative Assets		Derivative Liabilities			Valuation Techniques	Unobservable Input	Range							Weighted Average
	(In millions)
Natural Gas	$	32	$	(62	)	Discounted Cash Flow	Forward basis price (per MMBtu)	$	(2.63	)	—	$	0.54	/MMBtu	$	0.01	/MMBtu
Electricity	$	98	$	(86	)	Discounted Cash Flow	Forward basis price (per MWh)	$	(8	)	—	$	17	/MWh	$	3	/MWh

17

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

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

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

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

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

Fair Value of Financial Instruments

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

The following table presents the carrying amount and fair value of financial instruments as of June 30, 2013 and December 31, 2012:

	June 30, 2013								December 31, 2012
	Carrying		Fair Value						Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Amount		Level 1		Level 2		Level 3
	(In millions)
Notes receivable, excluding capital leases	$	36	$	—	$	—	$	36	$	39	$	—	$	—	$	39
Dividends payable	229		229		—		—		107		107		—		—
Short-term borrowings	216		—		216		—		240		—		240		—
Long-term debt	7,671		487		6,556		1,008		7,813		507		7,453		933

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

Nuclear Decommissioning Trust Funds

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

18

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

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

	June 30, 2013		December 31, 2012
	(In millions)
Fermi 2	$	1,063	$	1,021
Fermi 1	3		3
Low level radioactive waste	14		13
Total	$	1,080	$	1,037

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(In millions)
Realized gains	$	11		$	8		$	19		$	14
Realized losses	$	(7	)	$	(7	)	$	(14	)	$	(11	)
Proceeds from sales of securities	$	15		$	25		$	27		$	36

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:

	June 30, 2013				December 31, 2012
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
	(In millions)
Equity securities	$	679	$	161	$	631	$	122
Debt securities	390		15		399		27
Cash and cash equivalents	11		—		7		—
	$	1,080	$	176	$	1,037	$	149

The debt securities at both June 30, 2013 and December 31, 2012 had an average maturity of approximately 6 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. DTE Electric recognized $52 million and $44 million of unrealized losses as Regulatory assets at June 30, 2013 and December 31, 2012, respectively. Since the decommissioning of Fermi 1 is funded by DTE Electric rather than through a regulatory recovery mechanism, there is no corresponding regulatory asset treatment. Therefore, unrealized losses incurred by the Fermi 1 trust are recognized in earnings immediately. There were no unrealized losses recognized in the three and six months ended June 30, 2013 and June 30, 2012 for Fermi 1.

Other Securities

At June 30, 2013 and December 31, 2012, the securities were comprised primarily of money market and equity securities. During the three and six months ended June 30, 2013 and June 30, 2012, no amounts of unrealized losses on available-for-sale securities were reclassified out of other comprehensive income into net income for the periods. Gains related to trading securities held at June 30, 2013 and June 30, 2012 were $8 million and $5 million, respectively.

NOTE 4 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

The Company recognizes all derivatives at their fair value as Derivative Assets or Liabilities on the Consolidated Statements of Financial Position unless they qualify for certain scope exceptions, including the normal purchases and normal sales exception. Further, derivatives that qualify and are designated for hedge accounting are classified as either hedges of a

19

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge), or as hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge). For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the value of the underlying exposure is deferred in Accumulated other comprehensive income and later reclassified into earnings when the underlying transaction occurs. Gains or losses from the ineffective portion of cash flow hedges are recognized in earnings immediately. For fair value hedges, changes in fair values for the derivative and hedged item are recognized in earnings each period. For derivatives that do not qualify or are not designated for hedge accounting, changes in the fair value are recognized in earnings each period.

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

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

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

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

Power and Industrial Projects — Business units within this segment manage and operate onsite energy and pulverized coal projects, coke batteries, landfill gas recovery and power generation assets. These businesses utilize fixed-priced contracts in the marketing and management of their assets. These contracts are generally not derivatives and are therefore accounted for under the accrual method.

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

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

Corporate and Other — Interest Rate Risk — The Company uses interest rate swaps, treasury locks and other derivatives to hedge the risk associated with interest rate market volatility. In 2004 and 2000, the Company entered into a series of interest rate derivatives to limit its sensitivity to market interest rate risk associated with the issuance of long-term debt. Such instruments were designated as cash flow hedges. The Company subsequently issued long-term debt and terminated these hedges at a cost that is included in Other comprehensive loss. Amounts recorded in Other comprehensive loss will be reclassified to interest expense through 2033. In 2013, the Company estimates reclassifying less than $1 million of losses to earnings.

20

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

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 June 30, 2013 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to have a material adverse effect on the Company’s financial statements.

Derivative Activities

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

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

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

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

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

The following tables present the fair value of derivative instruments as of June 30, 2013 and December 31, 2012:

	June 30, 2013					December 31, 2012
	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	—		$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	—		(1		)	—		—
Commodity Contracts:
Natural Gas	504		(510		)	645		(661		)
Electricity	317		(307		)	360		(351		)
Other	55		(52		)	11		(7		)
Total derivatives not designated as hedging instruments:	$	876	$	(870	)	$	1,016	$	(1,019	)
Total derivatives:
Current	$	757	$	(750	)	$	862	$	(879	)
Noncurrent	119		(120		)	154		(141		)
Total derivatives	$	876	$	(870	)	$	1,016	$	(1,020	)

21

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

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

The Company also provides and receives collateral in the form of letters of credit which can be offset against net derivative assets and liabilities as well as accounts receivable and payable. The Company had issued letters of credit of approximately $37 million and $63 million at June 30, 2013 and December 31, 2012, respectively, which could be used to offset our net derivative liabilities. Letters of credit received from third parties which could be used to offset our net derivative assets were not material for the periods presented. Such balances of letters of credit are excluded from the tables below and are not netted with the recognized assets and liabilities in the Consolidated Statements of Financial Position.

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

As of June 30, 2013, the total cash collateral posted, net of cash collateral received, was $2 million. As of December 31, 2012, the total cash collateral received, net of cash collateral posted, was $20 million. As of June 30, 2013, derivative assets and derivative liabilities are shown net of cash collateral of $14 million and $19 million, respectively. There was no cash collateral related to unrealized positions to net against derivative assets and liabilities as of December 31, 2012. The Company recorded cash collateral paid of $6 million and cash collateral received of $3 million not related to unrealized derivative positions as of June 30, 2013. The Company recorded cash collateral paid of $4 million and cash collateral received of $24 million not related to unrealized derivative positions as of December 31, 2012. These amounts are included in accounts receivable and accounts payable and are recorded net by counterparty.

The following table presents the netting offsets of derivative assets and liabilities at June 30, 2013 and December 31, 2012:

	June 30, 2013									December 31, 2012
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position			Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position
	(In millions)
Derivative assets:
Commodity Contracts:
Natural Gas	$	504		$	(490	)	$	14		$	645		$	(605	)	$	40
Electricity	317			(220		)	97			360			(258		)	102
Other	55			(49		)	6			11			(6		)	5
Total derivative assets	$	876		$	(759	)	$	117		$	1,016		$	(869	)	$	147
Derivative liabilities:
Foreign currency exchange contracts	$	(1	)	$	—		$	(1	)	$	—		$	—		$	—
Interest rate contracts	—			—			—			(1		)	—			(1		)
Commodity Contracts:
Natural Gas	(510		)	469			(41		)	(661		)	605			(56		)
Electricity	(307		)	247			(60		)	(351		)	258			(93		)
Other	(52		)	48			(4		)	(7		)	6			(1		)
Total derivative liabilities	$	(870	)	$	764		$	(106	)	$	(1,020	)	$	869		$	(151	)

22

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

The following table presents the netting offsets of derivative assets and liabilities at June 30, 2013 and December 31, 2012:

	June 30, 2013												December 31, 2012
	Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent			Current			Noncurrent			Current			Noncurrent
	(In millions)
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	757		$	119		$	(750	)	$	(120	)	$	862		$	154		$	(879	)	$	(141	)
Counterparty netting	(653		)	(92		)	653			92			(754		)	(115		)	754			115
Collateral adjustment	(14		)	—			7			12			—			—			—			—
Total derivatives as reported	$	90		$	27		$	(90	)	$	(16	)	$	108		$	39		$	(125	)	$	(26	)

The effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for the three and six months ended June 30, 2013 and 2012 is as follows:

	Location of Gain (Loss) Recognized in Income on Derivatives	Gain (Loss) Recognized in Income on Derivatives for the Three Months Ended June 30,					Gain (Loss) Recognized in Income on Derivatives for the Six Months Ended June 30,
Derivatives not Designated as Hedging Instruments		2013			2012		2013			2012
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	(1	)	$	1	$	(1	)	$	1
Commodity Contracts:
Natural Gas	Operating Revenue	46			1		36			3
Natural Gas	Fuel, purchased power and gas	(46		)	5		(32		)	(5		)
Electricity	Operating Revenue	10			37		30			35
Other	Operating Revenue	(1		)	3		—			11
Total		$	8		$	47	$	33		$	45

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

The effects of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position were $3 million and $4 million in unrealized gains related to FTRs recognized in Regulatory liabilities for the three and six months ended June 30, 2013, respectively.

The following represents the cumulative gross volume of derivative contracts outstanding as of June 30, 2013:

Commodity	Number of Units
Natural Gas (MMBtu)	574,820,998
Electricity (MWh)	64,291,746
Foreign Currency Exchange ($ CAD)	34,772,009
FTR (MWh)	16,224,782

Various non-utility subsidiaries of the Company have entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade. Certain of these provisions (known as “hard triggers”) state specific circumstances under which the Company can be asked to post collateral upon the occurrence of a credit downgrade, while other provisions (known as “soft triggers”) are not as specific.

23

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

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 June 30, 2013, 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 $313 million.

NOTE 5 — 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 activity of the discontinued business for the three and six months ended June 30, 2012 is shown below. The amounts exclude general corporate overhead costs, and the related tax effects, and no portion of corporate interest costs were allocated to discontinued operations.

	Three Months Ended			Six Months Ended
	June 30, 2012			June 30, 2012
	(In millions)
Operating Revenues	$	12		$	22
Operation and Maintenance	5			10
Depreciation, Depletion and Amortization	6			11
Taxes Other Than Income	1			1
Operating Income	—			—
Other (Income) and Deductions	2			3
Income Tax Benefit	(1		)	(2		)
Net Income Attributable to DTE Energy Company	$	(1	)	$	(1	)

NOTE 6 — ASSET RETIREMENT OBLIGATIONS

A reconciliation of the asset retirement obligations for the six months ended June 30, 2013 follows:

	(In millions)
Asset retirement obligations at December 31, 2012	$	1,719
Accretion	52
Revision in estimated cash flows	13
Asset retirement obligations at June 30, 2013	$	1,784

NOTE 7 — REGULATORY MATTERS

Energy Optimization (EO) Plans

In May 2013, DTE Electric and DTE Gas filed separate applications for approval of their respective reconciliations of their 2012 EO plan expenses. DTE Electric's EO reconciliation includes a cumulative $26 million net over-recovery and DTE Gas's EO reconciliation includes a cumulative $7 million net over-recovery for their 2012 EO plans. DTE Electric and DTE Gas proposed that the calculated over-recoveries for 2012 be carried forward into 2013 and used as beginning balances for the 2013 reconciliations. In July 2013, DTE Electric and DTE Gas filed separate applications with the MPSC for the biennial review of their EO plans.

24

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

Renewable Energy Plan (REP)

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

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

Accounting Authority

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

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

Transitional Reconciliation Mechanism (TRM)

On July 19, 2013, DTE Electric filed its TRM application proposing a transitional tariff option for certain former PLD customers and a modified line extension provision. The application also proposes a recovery mechanism for the deferred incremental revenue requirement described above. The application further discusses that DTE Electric will be requesting recovery, in subsequent PSCR cases, of PLD transmission delivery service costs incurred while DTE Electric is temporarily relying upon PLD to operate and maintain PLD's system during the system conversion period. If the MPSC determines that the transmission costs are not recoverable in the PSCR, the Company requested recovery as part of the TRM.

Power Supply Cost Recovery Proceedings

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

2010 PSCR Year —In March 2011, DTE Electric filed the 2010 PSCR reconciliation calculating a net under-recovery of $52.6 million that includes an over-recovery of $15.6 million for the 2009 PSCR year. In addition, the 2010 PSCR reconciliation includes an under-recovery of $7.1 million for the reconciliation of the 2007-2008 Pension Equalization Mechanism, and an over-refund of $3.8 million for the 2011 refund of the self-implemented rate increase related to the 2009 electric rate case filing. On April 25, 2013, the MPSC approved the 2010 PSCR net under-recovery of $52.6 million and the recovery of this amount as part of the 2011 PSCR reconciliation. The order also approved DTE Electric's Pension Equalization Mechanism reconciliation and authorized a one month surcharge in June 2013 and approved the recovery of the over-refund of the self-implemented rate increase related to the 2009 electric rate case filing as part of the 2011 PSCR reconciliation.

2012 Plan Year— In September 2011, DTE Energy filed its 2012 PSCR plan case seeking approval of a levelized PSCR factor of 4.18 mills/kWh above the amount included in base rates for all PSCR customers. The filing supports a total power supply expense forecast of $1.4 billion. The plan also includes approximately $158 million for the recovery of its projected 2011 PSCR under-recovery. On June 28, 2013, the MPSC approved DTE Energy's 2012 PSCR plan.

25

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

DTE Gas Revenue Decoupling Mechanism (RDM)

In May 2013, DTE Gas filed an application with the MPSC for approval of its RDM reconciliation for the period July 1, 2012 through October 31, 2012. DTE Gas's RDM application proposed the recovery of a net under-recovery of approximately $5.2 million.

DTE Gas Depreciation Filing

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

NOTE 8 — COMMON STOCK

Common Stock

On March 12, 2013, the Company contributed $50 million of DTE Energy common stock to the DTE Energy Company Affiliates Employee Benefit Plans Master Trust. The contribution consisted of 750,075 shares valued at $66.66 per share. On June 12, 2013, the Company contributed $50 million of DTE Energy common stock to the DTE Energy Company Affiliates Employee Benefit Plans Master Trust. The contribution consisted of 753,579 shares valued at $66.35 per share. The shares for both contributions were valued at the closing market price of DTE Energy common stock on the contribution dates in accordance with fair value measurement and accounting requirements.

NOTE 9 — 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 for the three months and six months ended June 30:

26

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

	Three Months Ended					Six Months Ended
	June 30					June 30
	2013			2012		2013		2012
	(In millions, except per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	105		$	146	$	339	$	302
Average number of common shares outstanding	174			170		174		170
Weighted average net restricted shares outstanding	1			1		1		1
Dividends declared — common shares	$	114		$	100	$	222	$	200
Dividends declared — net restricted shares	1			1		—		1
Total distributed earnings	$	115		$	101	$	222	$	201
Net income less distributed earnings	$	(10	)	$	45	$	117	$	101
Distributed (dividends per common share)	$	0.66		$	0.59	$	1.28	$	1.18
Undistributed	(0.06		)	0.27		0.66		0.59
Total Basic Earnings per Common Share	$	0.60		$	0.86	$	1.94	$	1.77
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	105		$	146	$	339	$	302
Average number of common shares outstanding	175			170		174		170
Average incremental shares from assumed exercise of options	—			1		—		1
Common shares for dilutive calculation	175			171		174		171
Weighted average net restricted shares outstanding	1			1		1		1
Dividends declared — common shares	$	114		$	100	$	222	$	200
Dividends declared — net restricted shares	1			1		—		1
Total distributed earnings	$	115		$	101	$	222	$	201
Net income less distributed earnings	$	(10	)	$	45	$	117	$	101
Distributed (dividends per common share)	$	0.66		$	0.59	$	1.28	$	1.18
Undistributed	(0.06		)	0.27		0.66		0.59
Total Diluted Earnings per Common Share	$	0.60		$	0.86	$	1.94	$	1.77

27

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

NOTE 10 — LONG-TERM DEBT

Debt Issuance

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

Company	Month Issued	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March	Mortgage Bonds (a)	4.00	%	2043	$	375
						$	375

_______________________________________

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

Debt Redemptions

In 2013, the following debt was redeemed:

	Month	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March	Securitization Bonds	6.42	%	2013	$	88
DTE Electric	March	Tax Exempt Revenue Bonds (a)	5.30	%	2030	51
DTE Electric	April	Other Long-Term Debt	Various		2013	13
DTE Energy	Various	Other Long-Term Debt	Various		2013	3
DTE Gas	April	Senior Notes	5.26	%	2013	60
DTE Energy	June	Senior Notes	Variable		2013	300
						$	515

_______________________________________

(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.

NOTE 11 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

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

The agreements require the Company to maintain a total funded debt to capitalization ratio of no more than 0.65 to 1. In the agreements, “total funded debt” means all indebtedness of the Company and its consolidated subsidiaries, including capital lease obligations, hedge agreements and guarantees of third parties’ debt, but excluding contingent obligations, nonrecourse and junior subordinated debt and certain equity-linked securities and, except for calculations at the end of the second quarter, certain DTE Gas short-term debt. “Capitalization” means the sum of (a) total funded debt plus (b) “consolidated net worth,” which is equal to consolidated total stockholders’ equity of the Company and its consolidated subsidiaries (excluding pension effects under certain FASB statements), as determined in accordance with accounting principles generally accepted in the United States of America. At June 30, 2013, the total funded debt to total capitalization ratios for DTE Energy, DTE Electric and DTE Gas are 0.48 to 1, 0.53 to 1 and 0.44 to 1, respectively, and are in compliance with this financial covenant. The availability under the facilities in place at June 30, 2013 is shown in the following table:

28

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

	DTE Energy		DTE Electric		DTE Gas		Total
	(In millions)
Unsecured letter of credit facility, expiring in May 2014	$	50	$	—	$	—	$	50
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Unsecured revolving credit facility, expiring April 2018	1,200		300		300		1,800
Total credit facilities at June 30, 2013	1,375		300		300		1,975
Amounts outstanding at June 30, 2013:
Commercial paper issuances	101		96		19		216
Letters of credit	184		—		—		184
	285		96		19		400
Net availability at June 30, 2013	$	1,090	$	204	$	281	$	1,575

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $38 million which are used for various corporate purposes.

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 June 30, 2013, a $40 million letter of credit was in place, raising the capacity under this facility to $140 million. The $40 million letter of credit is included in the table above. The amount outstanding under this agreement was $64 million and $65 million at June 30, 2013 and December 31, 2012, respectively.

NOTE 12 — COMMITMENTS AND CONTINGENCIES

Environmental

Electric

Air - DTE Electric is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze, mercury, and other air pollution. These rules have led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, mercury and other emissions. To comply with these requirements, DTE Electric spent approximately $1.9 billion through 2012. The Company estimates DTE Electric will make capital expenditures of approximately $335 million in 2013 and up to approximately $1.8 billion of additional capital expenditures through 2021 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants. The Cross State Air Pollution Rule (CSAPR), finalized in July 2011, required further reductions of sulfur dioxide and nitrogen oxides emissions beginning in 2012. On December 30, 2011, the U.S. Court of Appeals for the District of Columbia (D.C.) Circuit granted the motions to stay the rule, leaving DTE Electric temporarily subject to the previously existing Clean Air Interstate Rule (CAIR). On August 21, 2012, the Court issued its decision, vacating CSAPR and leaving CAIR in place. The EPA's petition seeking a rehearing of the U.S. Court of Appeals' decision regarding the CSAPR was denied on January 24, 2013. On June 24, 2013, the U.S. Supreme Court granted EPA's petition asking the Court to review the D.C. Circuit Court's decision on CSAPR. A ruling by the Supreme Court is not expected before 2014. Notwithstanding the appeal filed with the Supreme Court, the EPA and a number of states have started working on the framework of revised CSAPR regulations which we anticipate to be proposed in the next few years.

The Mercury and Air Toxics Standard (MATS) rule, formerly known as the Electric Generating Unit Maximum Achievable Control Technology (EGU MACT) Rule was finalized on December 16, 2011. The MATS rule requires reductions of mercury and other hazardous air pollutants beginning in 2015. 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 operate in compliance with MATS.

29

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

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

In August 2010, the U.S. Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and DTE Electric, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require DTE Electric to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require DTE Electric to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from DTE Electric's fleet of coal-fired power plants until the new control equipment is operating. On August 23, 2011, the U.S. District Court judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy and DTE Electric. On October 20, 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit. On March 28, 2013, the Court of Appeals remanded the case to the U.S. District Court for review of the procedural component of the New Source Review notification requirements.

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

On March 13, 2013, The Sierra Club filed suit against DTE Energy and DTE Electric alleging violations of the Clean Air Act at four of DTE Electric's coal-fired power plants. The plaintiffs allege 1,499 6-minute periods of excess opacity of air emissions from 2007-2012 at those facilities. The suit asks that the court enjoin the Company from operating the power plants except in complete compliance with applicable laws and permit requirements, pay civil penalties, conduct beneficial environmental mitigation projects, pay attorney fees and require the installation of any necessary pollution controls or to convert and/or operate the plants' boilers on natural gas to avoid additional violations and to off-set historic unlawful emissions. The resolution of this matter is not expected to have a material effect on the Company's operations or financial statements.

Water — In response to an EPA regulation, DTE Electric would be required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of completed studies and expected future studies, DTE Electric may be required to install technologies to reduce the impacts of the water intake structures. The initial rule published in 2004 was subsequently remanded and a proposed rule published in 2011. The proposed rule specified an eight year compliance timeline. In July 2012, the EPA announced that a notice of its final action on the rule will be issued in June 2013. On June 27, 2013, the EPA announced an agreement to extend the deadline for issuance of the final rule until November 4, 2013. On April 19, 2013, the EPA proposed revised steam electric effluent guidelines regulating wastewater streams from coal-fired power plants including multiple possible options for compliance. The rules are expected to be finalized by May 2014. DTE Electric is in the process of reviewing the proposal and will provide comments to the EPA within the allotted time. However, it is not possible at this time to quantify the impacts of these developing requirements.

Contaminated and Other Sites — Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. The facilities, which produced gas, have been designated as manufactured gas plant (MGP) sites. DTE Electric conducted remedial investigations at contaminated sites, including three former MGP sites. The investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites, including the area surrounding an ash landfill, electrical distribution substations, electric generating power plants, and underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is expected to be incurred over the next several years. At June 30, 2013 and December 31, 2012, the Company had $9 million accrued for remediation. Any change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect

30

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

the Company’s financial position and cash flows. The Company believes that the likelihood of a materially greater liability than the accrued amount is remote based on current knowledge of the conditions at each site.

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

Gas

Contaminated 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. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites. Cleanup activities associated with these sites will be conducted over the next several years.

The MPSC has established a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites. Accordingly, Gas segment recognizes a liability and corresponding Regulatory asset for estimated investigation and remediation costs at former MGP sites. As of June 30, 2013 and December 31, 2012, the Company had $30 million and $29 million accrued for remediation, respectively.

Any change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows. The Company anticipates the cost amortization methodology approved by the MPSC for DTE Gas, which allows DTE Gas to amortize the MGP costs over a ten-year period beginning with the year subsequent to the year the MGP costs were incurred and the cost deferral and rate recovery mechanism for Citizens Fuel Gas approved by the City of Adrian, will prevent environmental costs from having a material adverse impact on the Company’s results of operations.

Non-utility

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

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

The Company received two NOVs from the Pennsylvania Department of Environmental Protection (PADEP) in 2010 alleging violations of the permit for the Pennsylvania coke battery facility in connection with coal pile storm water runoff. The Company has implemented best management practices to address this issue. The Company recently received a permit to upgrade its existing waste water treatment system and is currently seeking a permit from the PADEP to upgrade its wastewater treatment technology to a biological treatment facility. The Company expects to spend less than $6 million on the existing waste water treatment system to comply with existing water discharge requirements and to upgrade its coal pile storm water runoff management program.

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

31

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

Other

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

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

Nuclear Operations

Property Insurance

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

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

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

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

Under the NEIL policies, DTE Electric could be liable for maximum assessments of up to approximately $33 million per event if the loss associated with any one event at any insured 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 $117.5 million could be levied against each licensed nuclear facility, but not more than $17.5 million per year per facility. Thus, deferred premium charges could be levied against all owners of licensed nuclear facilities in the event of a nuclear incident at any of these facilities.

32

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

Nuclear Fuel Disposal Costs

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

DTE Electric is a party in the litigation against the DOE for both past and future costs associated with the DOE's failure to accept spent nuclear fuel under the timetable set forth in the Federal Nuclear Waste Policy Act of 1982. In July 2012, DTE Electric executed a settlement agreement with the federal government for costs associated with the DOE's delay in acceptance of spent nuclear fuel from Fermi 2 for permanent storage. The settlement provided for a payment of approximately $48 million, received in August 2012, for delay-related costs experienced by DTE Electric through 2010, and a claims process for submittal of delay-related costs from 2011 through 2013. DTE Electric has begun the claims process and currently no claims submitted have been denied. The settlement proceeds reduced the cost of the dry cask storage facility assets. In February 2013, the U.S. Court of Appeals for the District of Columbia granted a motion to reopen the fee adequacy litigation to review the DOE's latest fee adequacy report which was released in January 2013. DTE Electric will continue to pay fees to the U.S. government's nuclear waste fund pending further action by the D.C. Circuit. 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 June 30, 2013 is approximately $1.2 billion. Payment under these guarantees is considered remote.

Reduced Emissions Fuel Guarantees

The Company has provided certain guarantees and indemnities in conjunction with the sales of interests in its reduced emissions fuel facilities. The guarantees cover potential commercial, environmental, and tax-related obligations and will survive until 90 days after expiration of all applicable statutes of limitations. The Company estimates that its maximum potential liability under these guarantees at June 30, 2013 is approximately $103 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 $61 million at June 30, 2013. Payment under these guarantees is considered remote.

The Company is periodically required to obtain performance surety bonds in support of obligations to various governmental entities and other companies in connection with its operations. As of June 30, 2013, the Company had approximately $41 million of performance bonds outstanding. In the event that such bonds are called for nonperformance, the Company would be obligated to reimburse the issuer of the performance bond. The Company is released from the performance bonds as the contractual performance is completed and does not believe that a material amount of any currently outstanding performance bonds will be called.

33

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

Labor Contracts

Our contracts with several bargaining units for the majority of our represented employees were due to expire in June and October 2013. Early negotiations resulted in new contracts that became effective March 23, 2013. The new contracts will expire in June and October 2017.

Purchase Commitments

As of June 30, 2013, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments and energy trading contracts. The Company estimates that these commitments will be approximately $4.4 billion from 2013 through 2052.

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

Bankruptcies

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

The Company's utilities provide services to the city of Detroit, Michigan (Detroit). Detroit filed for Chapter 9 bankruptcy protection on July 18, 2013. Based on average monthly revenues and typical billing and payment cycles, the Company estimates that it has pre-petition accounts receivable of approximately $18 million. Detroit has been paying amounts owed in a timely manner and its account is substantially current. The Company does not expect Detroit's bankruptcy filing to have a material impact on its financial results.

Other Contingencies

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

See Notes 4 and 7 for a discussion of contingencies related to derivatives and regulatory matters.

34

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

NOTE 13 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

The following table details the components of net periodic benefit costs for pension benefits and other postretirement benefits:

	Pension						Other Postretirement
	Benefits						Benefits
	2013			2012			2013			2012
Three Months Ended June 30	(In millions)
Service cost	$	25		$	20		$	12		$	18
Interest cost	47			51			21			31
Expected return on plan assets	(66		)	(61		)	(27		)	(23		)
Amortization of:
Net actuarial loss	50			43			15			20
Prior service credit	—			—			(36		)	(7		)
Net periodic benefit cost	$	56		$	53		$	(15	)	$	39

	Pension						Other Postretirement
	Benefits						Benefits
	2013			2012			2013			2012
Six Months Ended June 30	(In millions)
Service cost	$	49		$	41		$	28		$	36
Interest cost	95			102			45			61
Expected return on plan assets	(133		)	(122		)	(54		)	(46		)
Amortization of:
Net actuarial loss	101			85			32			39
Prior service credit	—			—			(59		)	(14		)
Net transition liability	—			—			—			1
Settlements	—			2			—			—
Net periodic benefit cost	$	112		$	108		$	(8	)	$	77

Pension and Other Postretirement Contributions

During the first six months of 2013, the Company contributed $150 million to its pension plans, including a contribution of DTE Energy common stock of $100 million. See Note 8. At the discretion of management, and depending upon financial market conditions, the Company may make up to an additional $125 million contribution to its pension plans in 2013.

In January 2013, the Company contributed $145 million to its other postretirement benefit plans. At the discretion of management, the Company may make up to an additional $120 million contribution to its other postretirement benefit plans in 2013.

Re-Measurement of Other Postretirement Benefit Obligation

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

Based on the impact of such benefit cost savings on the 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. As a result of the re-measurement, the accumulated postretirement benefit obligation (ABPO) was reduced by $258 million. The Company's Accrued postretirement benefit liability at March 31, 2013 was $721 million as compared to $1.2 billion at December 31, 2012, a reduction of $439 million.

35

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

The reduction reflects the impact of the re-measurement of the plan, January 2013 plan contributions and recognition of first quarter 2013 postretirement benefit costs and benefit payments.

Beginning April 2013, net postretirement benefit costs were recorded based on the updated actuarial assumptions and benefit changes resulting from the new labor contracts. As a result of the re-measurement, fiscal year 2013 postretirement benefit costs are expected to decrease by approximately $69 million to an annual net benefit of approximately $40 million.

NOTE 14 — STOCK-BASED COMPENSATION

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
	(In millions)
Stock-based compensation expense	$	35	$	23	$	63	$	40
Tax benefit	14		9		25		15
Stock-based compensation cost capitalized in property, plant and equipment	2		1		4		2

Stock Options

The following table summarizes our stock option activity for the six months ended June 30, 2013:

	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In millions)
Options outstanding at December 31, 2012	1,192,670		$	41.86
Exercised	(370,959	)	$	40.53
Forfeited or expired	(10,370	)	$	41.46
Options outstanding at June 30, 2013	811,341		$	42.48	$	22
Options exercisable at June 30, 2013	811,341		$	42.48	$	22

As of June 30, 2013, the weighted average remaining contractual life for the exercisable shares is 4.36 years. During the six months ended June 30, 2013, 200,844 options vested. As of June 30, 2013, all options were vested.

The intrinsic value of options exercised for the six months ended June 30, 2013 and 2012 was $10 million and $17 million, respectively. No option expense was recognized for the six months ended June 30, 2013 and $0.5 million of option expense was recognized for the six months ended June 30, 2012.

The Company includes both historical and implied share-price volatility in option volatility. Implied volatility is derived from exchange traded options on DTE Energy common stock. The Company’s expected option life estimate is based on historical data.

Restricted Stock Awards

The following table summarizes the Company’s restricted stock awards activity for the six months ended June 30, 2013:

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at December 31, 2012	597,648		$	48.33
Grants	118,610		$	64.52
Forfeitures	(2,996	)	$	51.33
Vested and issued	(212,191	)	$	50.21
Balance at June 30, 2013	501,071		$	68.35

36

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

Performance Share Awards

The following table summarizes the Company’s performance share activity for the six months ended June 30, 2013:

	Performance Shares
Balance at December 31, 2012	1,634,364
Grants	534,027
Forfeitures	(22,906	)
Payouts	(548,624	)
Balance at June 30, 2013	1,596,861

Unrecognized Compensation Costs

As of June 30, 2013, there was $84 million of total unrecognized compensation cost related to non-vested stock incentive plan arrangements. That cost is expected to be recognized over a weighted-average period of 1.41 years.

NOTE 15 — SUPPLEMENTAL CASH FLOW INFORMATION

A detailed analysis of the changes in assets and liabilities that are reported in the Consolidated Statements of Cash Flows follows:

	Six Months Ended June 30,
	2013			2012
	(In millions)
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	70		$	120
Inventories	133			81
Accrued/prepaid pensions	(42		)	6
Accounts payable	(29		)	(4		)
Income taxes payable/receivable	(20		)	(39		)
Derivative assets and liabilities	(15		)	26
Postretirement obligation	(174		)	(142		)
Gas inventory equalization	73			65
Other assets	324			299
Other liabilities	(45		)	(112		)
	$	275		$	300

Supplementary non-cash information is as follows:

	Six Months Ended June 30,
	2013			2012
	(In millions)
Common stock issued for employee benefit and compensation plans	$	165		$	129
Change in capital expenditures not paid	$	(17	)	$	(55	)

NOTE 16 — SEGMENT AND RELATED INFORMATION

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

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

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

37

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

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

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

Energy Trading consists of energy marketing and trading operations.

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

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(In millions)
Inter-segment Revenues
Electric	$	7		$	8		$	13		$	15
Gas	1			1			2			2
Gas Storage and Pipelines	2			3			4			4
Power and Industrial Projects	185			192			390			383
Energy Trading	12			10			23			24
Corporate and Other	(7		)	(7		)	(15		)	(17		)
	$	200		$	207		$	417		$	411

38

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited) — (Continued)

Financial data of the business segments follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(In millions)
Operating Revenues
Electric	$	1,265		$	1,290		$	2,484		$	2,488
Gas	248			214			852			723
Gas Storage and Pipelines	31			27			58			52
Power and Industrial Projects	429			449			919			898
Energy Trading	451			239			844			500
Corporate & Other	1			1			1			2
Reconciliation & Eliminations	(200		)	(207		)	(417		)	(411		)
Total	$	2,225		$	2,013		$	4,741		$	4,252
Net Income (Loss) Attributable to DTE Energy by Segment:
Electric	$	89		$	127		$	204		$	223
Gas	8			4			104			56
Gas Storage and Pipelines	16			17			33			34
Power and Industrial Projects	7			10			19			18
Energy Trading	(2		)	4			5			2
Corporate & Other	(13		)	(15		)	(26		)	(30		)
Discontinued operations	—			(1		)	—			(1		)
Net Income Attributable to DTE Energy	$	105		$	146		$	339		$	302

39

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

DTE Energy is a diversified energy company and is 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.

Net income attributable to DTE Energy in the second quarter of 2013 was $105 million, or $0.60 per diluted share, compared to net income attributable to DTE Energy of $146 million, or $0.86 per diluted share, in the second quarter of 2012. Net income attributable to DTE Energy in the six months ended June 30, 2013 was $339 million, or $1.94 per diluted share, compared to net income attributable to DTE Energy of $302 million, or $1.77 per diluted share, in the comparable period of 2012. The decrease in net income in the second quarter is primarily due to lower earnings in the Electric segment. The increase in net income for the six months ended June 30, 2013 is primarily due to higher earnings in the Gas segment, partially offset by lower earnings in the Electric segment.

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

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

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

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

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

CAPITAL INVESTMENTS

Our utility businesses require significant base capital investments each year in order to maintain and improve the reliability of asset bases, including power generation plants, distribution systems, storage fields and other facilities and fleets. DTE Electric's capital investments over the 2013-2017 period are estimated at $5.0 billion for base infrastructure, $900 million for mandated environmental compliance requirements and $500 million for renewable energy and energy efficiency expenditures. DTE Electric plans to seek regulatory approval in general rate case filings and renewable energy plan filings for capital expenditures consistent with prior ratemaking treatment.

DTE Gas's capital investments over the 2013-2017 period are estimated at $680 million for base infrastructure and $400 million for gas main renewal and meter move out and pipeline integrity programs. In April 2013, the MPSC issued an order approving an infrastructure recovery mechanism (IRM) and authorized the recovery of the cost of service related to $77 million of annual investment in its gas main renewal and meter move out and pipeline integrity programs. DTE Gas plans to seek regulatory approval in general rate case filings for base infrastructure capital expenditures consistent with prior ratemaking treatment.

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ENVIRONMENTAL MATTERS

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

DTE Electric is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. These rules will lead to additional emission controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, DTE Electric spent approximately $1.9 billion through 2012. It is estimated that DTE Electric will make capital expenditures of approximately $335 million in 2013 and up to approximately $1.8 billion of additional capital expenditures through 2021 based on current regulations.

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

See Note 12 of the Notes to the Consolidated Financial Statements.

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:

• improving Electric and Gas customer satisfaction;

• effectively managing rate competitiveness and affordability;

• continuing to pursue regulatory stability and investment recovery for our utilities;

• managing the growth of our utility asset base;

• continuing to improve employee engagement;

• optimizing our cost structure across all business segments;

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

• investing in businesses that integrate our assets and leverage our skills and expertise.

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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.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(In millions)
Net Income (Loss) Attributable to DTE Energy by Segment:
Electric	$	89		$	127		$	204		$	223
Gas	8			4			104			56
Gas Storage and Pipelines	16			17			33			34
Power and Industrial Projects	7			10			19			18
Energy Trading	(2		)	4			5			2
Corporate and Other	(13		)	(15		)	(26		)	(30		)
Income From Continuing Operations Attributable to DTE Energy Company	105			147			339			303
Discontinued Operations	—			(1		)	—			(1		)
Net Income Attributable to DTE Energy Company	$	105		$	146		$	339		$	302

ELECTRIC

Our Electric segment consists principally of DTE Electric.

Electric results are discussed below:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(In millions)
Operating Revenues	$	1,265		$	1,290		$	2,484		$	2,488
Fuel and Purchased Power	435			428			807			805
Gross Margin	830			862			1,677			1,683
Operation and Maintenance	343			334			674			689
Depreciation and Amortization	221			204			435			391
Taxes Other Than Income	64			60			134			128
Asset (Gains) and Losses, Reserves and Impairments, Net	1			(1		)	—			(1		)
Operating Income	201			265			434			476
Other (Income) and Deductions	65			64			122			122
Income Tax Expense	47			74			108			131
Net Income Attributable to DTE Energy Company	$	89		$	127		$	204		$	223
Operating Income as a Percent of Operating Revenues	16		%	21		%	17		%	19		%

Gross margin decreased $32 million and $6 million in the three and six months ended June 30, 2013, respectively. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statement of Operations.

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

	Three Months			Six Months
	(In millions)
Weather	$	(37	)	$	(18	)
Securitization bond and tax surcharge	9			24
Renewable energy program	4			8
Low income energy assistance surcharge	(10		)	(20		)
Regulatory mechanisms and other	2			—
Decrease in gross margin	$	(32	)	$	(6	)

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2013	2012	2013	2012
	(In thousands of MWh)
Electric Sales
Residential	3,345	3,587	7,199	7,287
Commercial	4,158	4,247	8,081	8,132
Industrial	2,675	2,563	5,111	4,938
Other	216	221	468	479
	10,394	10,618	20,859	20,836
Interconnection sales (a)	792	859	1,565	1,385
Total Electric Sales	11,186	11,477	22,424	22,221
Electric Deliveries
Retail and Wholesale	10,394	10,618	20,859	20,836
Electric Customer Choice, including self generators (b)	1,287	1,312	2,547	2,567
Total Electric Sales and Deliveries	11,681	11,930	23,406	23,403

______________________________

(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 increased $9 million and decreased $15 million in the three and six months ended June 30, 2013, respectively. The increase in the second quarter was due primarily to higher power plant generation expenses of $12 million, increased uncollectible expense of $8 million, higher restoration and line clearance expenses of $6 million, increased distribution operations expenses of $5 million, increased energy optimization and renewable energy expenses of $4 million and increased legal liability expenses of $3 million, partially offset by lower employee benefit expenses of $21 million and decreased low income energy assistance expenses of $10 million. The decrease in the six-month period was primarily due to lower employee benefit expenses of $31 million, decreased low income energy assistance expenses of $20 million and lower power plant generation expenses of $3 million, partially offset by increased uncollectible expense of $9 million, higher energy optimization and renewable energy expenses of $8 million, increased distribution operations expenses of $8 million, higher restoration and line clearance expenses of $3 million and increased legal liability expenses of $3 million.

Depreciation and amortization expense increased $17 million and $44 million in the three and six months ended June 30, 2013, respectively. The increase in the second quarter was due to higher amortization of regulatory assets of $14 million and increased expense due to a higher depreciable base of $3 million. The increase in the six-month period was due to $35 million of higher amortization of regulatory assets and $9 million of increased expense due to a higher depreciable base.

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

On June 25, 2012, our Fermi 2 nuclear power plant was manually shutdown after one of the plant's two non-safety related feed-water pumps failed. Supported by a detailed analysis, DTE Electric decided to operate the plant with one feed-water pump at a reduced power level until the second feed-water pump is returned to service. The plant was restarted on July 30,

43

2012 which restored production to nominal 68% of full capacity. We expect that a substantial portion of the property damage will be covered by existing insurance coverage, subject to deductibles. We are able to purchase sufficient power from MISO to continue to provide uninterrupted service to our customers. We are seeking recovery of the related incremental purchased power costs through the PSCR process. It is estimated that the repair to the plant will be complete by the fourth quarter of 2013.

In June 2013, the City of Detroit announced a transition of its Public Lighting Department's customers to the DTE Electric distribution system over a five to seven year system conversion period. See Note 7 of the Notes to Consolidated Financial Statements.

GAS

Our Gas segment consists of DTE Gas and Citizens.

Gas results are discussed below:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(In millions)
Operating Revenues	$	248		$	214		$	852		$	723
Cost of Gas	80			62			379			338
Gross Margin	168			152			473			385
Operation and Maintenance	105			97			211			197
Depreciation and Amortization	24			23			47			46
Taxes Other Than Income	15			14			31			32
Operating Income	24			18			184			110
Other (Income) and Deductions	11			12			23			24
Income Tax Expense	5			2			57			30
Net Income Attributable to DTE Energy Company	$	8		$	4		$	104		$	56
Operating Income as a Percent of Operating Revenues	10		%	8		%	22		%	15		%

Gross margin increased $16 million and $88 million in the three and six months ended June 30, 2013, respectively. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statement of Operations. The following table details changes in various gross margin components relative to the comparable prior period:

	Three Months			Six Months
	(In millions)
Weather	$	10		$	51
2012 rate order	3			14
Lost and stolen gas	3			13
Energy optimization revenue	1			6
Uncollectible tracking mechanism	11			21
Revenue decoupling mechanism	(10		)	(11		)
Other	(2		)	(6		)
Increase in gross margin	$	16		$	88

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2013	2012	2013	2012
Gas Markets (in Bcf)
Gas sales	18	14	76	61
End user transportation	32	34	87	82
	50	48	163	143
Intermediate transportation	76	61	152	144
	126	109	315	287

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Operation and maintenance expense increased $8 million and $14 million in the three and six months ended June 30, 2013, respectively. The increase in the second quarter was primarily due to higher maintenance and repair costs of $7 million, higher transmission expenses of $4 million and increased uncollectible expenses of $2 million, partially offset by lower employee benefit expenses of $5 million. The increase in the six-month period was primarily due to higher maintenance and repair costs of $7 million, higher transmission expenses of $7 million, increased energy optimization expenses of $5 million and higher uncollectible expenses of $3 million, partially offset by lower employee benefit expenses of $8 million.

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

GAS STORAGE AND PIPELINES

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

Gas Storage and Pipelines results are discussed below:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(In millions)
Operating Revenues	$	31		$	27		$	58		$	52
Operation and Maintenance	7			6			12			10
Depreciation and Amortization	4			2			8			4
Taxes Other Than Income	1			1			2			2
Operating Income	19			18			36			36
Other (Income) and Deductions	(8		)	(10		)	(19		)	(20		)
Income Tax Expense	10			10			21			21
Net Income	17			18			34			35
Noncontrolling interest	1			1			1			1
Net Income Attributable to DTE Energy	$	16		$	17		$	33		$	34

Net income attributable to DTE Energy decreased $1 million for both the three months and six months ended June 30, 2013. The second quarter 2013 decrease was primarily driven by lower gas storage revenue, offset by higher net income from the Bluestone and Susquehanna projects. The decrease in the six-month period was driven by lower gas storage revenue, offset by higher earnings from an equity investment and higher net income from the Bluestone and Susquehanna projects.

Outlook — Our Gas Storage and Pipelines business expects to maintain its steady growth by developing an asset portfolio with multiple growth platforms through investment in new projects and expansions. Millennium Pipeline has secured customers for its Phase One and Two expansions, which are scheduled to be in service in 2013. Millennium's total capacity with the Phase One and Two expansions will increase from 525,000 dth/d to over 800,000 dth/d. Additionally, Bluestone, a 44-mile lateral pipeline in Susquehanna County, Pennsylvania and Broome County, New York designed to initially flow over 600,000 dth/d to Millennium Pipeline and Tennessee Pipeline, is in service and volumes are increasing. Through our agreement with Southwestern Energy, Bluestone lateral and Susquehanna gathering system are strategically positioned for future growth of the Marcellus shale.

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POWER AND INDUSTRIAL PROJECTS

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

Power and Industrial Projects results are discussed below:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(In millions)
Operating Revenues	$	429		$	449		$	919		$	898
Operation and Maintenance	422			444			903			883
Depreciation and Amortization	17			14			35			29
Taxes other than Income	3			3			8			9
Asset (Gains) and Losses, Reserves and Impairments, Net	4			(2		)	1			(7		)
Operating Income (Loss)	(17		)	(10		)	(28		)	(16		)
Other (Income) and Deductions	(16		)	(11		)	(25		)	(15		)
Income Taxes
Expense	(1		)	—			(1		)	(1		)
Production Tax Credits	(8		)	(10		)	(23		)	(20		)
	(9		)	(10		)	(24		)	(21		)
Net Income	8			11			21			20
Noncontrolling interest	1			1			2			2
Net Income Attributable to DTE Energy Company	$	7		$	10		$	19		$	18

Operating revenues decreased $20 million and increased $21 million in the three and six months ended June 30, 2013, respectively. The decrease in the second quarter of 2013was primarily due to a $26 million decrease from lower price and volumes associated with the steel business, a $19 million decrease from lower volumes associated with coal transportation and marketing activities, and an $11 million decrease associated with lower volumes from REF projects, of which $6 million represent affiliate transactions, partially offset by a $33 million increase primarily due to newly acquired on-site projects. The increase in the six-month period was primarily due to a $70 million increase from newly acquired on-site projects, a $16 million increase associated with higher volumes from REF projects, of which $9 million represent affiliate transactions, partially offset by a $34 million decrease in price and volumes associated with the steel business, and $33 million due to lower volumes associated with coal transportation and marketing activities.

Operation and maintenance expense decreased $22 million and increased $20 million in the three and six months ended June 30, 2013, respectively. The decrease in the second quarter of 2013was primarily due to a $22 million decrease from lower price and volumes associated with the steel business, an $18 million decrease from lower volumes associated with coal transportation and marketing activities, and a $12 million decrease associated with lower volumes from REF projects, of which $6 million represent affiliate transactions, partially offset by a $29 million increase primarily due to the newly acquired on-site projects. The increase in the six-month period was primarily due to a $59 million increase from newly acquired on-site projects, an $18 million increase associated with higher volumes from REF projects, of which $9 million represent affiliate transactions, partially offset by a $31 million decrease due to lower volumes associated with coal transportation and marketing activities, and a $28 million decrease in price and volumes associated with the steel business.

Asset (gains) losses, reserves and impairments, net were lower by $6 million and $8 million in the three and six months ended June 30, 2013, respectively, due primarily due to a $6 million asset impairment at an on-site facility in the three-month period.

Other (income) and deductions increased by $5 million and $10 million in the three and six months ended June 30, 2013, respectively. The increase in the second quarter wasdue primarily to $5 million in gains recognized in connection with sales of a membership interests in REF facilities (treated as sales of tax credits for financial reporting purposes). The year to date increase wasdue primarily to $6 million in gains recognized in connection with sales of membership interests in REF facilities (treated as sales of tax credits for financial reporting purposes), and a $4 million increase related to higher equity earnings at various projects.

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Outlook - The Company has constructed and placed in service nine REF facilities including three facilities located at third party owned coal-fired power plants. The Company has sold membership interests in four of the facilities. We continue to optimize these facilities by seeking investors for facilities operating at DTE Electric and other utility sites. Additionally, we intend to relocate three underutilized facilities, located at DTE Electric sites, to alternative coal-fired power plants which may provide increased production and emission reduction opportunities in 2013 and future years. One of the underutilized facilities is currently being relocated to a third party owned coal-fired power plant. The proceeds from executed and planned sales of membership interests in the REF facilities are expected to be received by the Company on an installment basis, and the Company will recognize the related gains (treated as sales of tax credits for financial reporting purposes) as production tax credits are generated by the respective facilities.

We expect reduced production levels of metallurgical coke and pulverized coal supplied to steel industry customers for 2013. Substantially all of the metallurgical coke margin is maintained under long-term contracts. We have four biomass-fired power generation facilities in operation, and we are converting an additional facility to be placed in service in 2013. Our on-site energy services will continue to be delivered in accordance with the terms of long-term contracts. We will begin construction on a new natural gas-fired cogeneration and two landfill gas to energy projects during the year which will be completed in 2014. We will continue to look for additional investment opportunities and other energy projects at favorable prices.

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

ENERGY TRADING

Energy Trading focuses on physical and financial power, natural gas and coal marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, and optimization of contracted natural gas pipeline transportation and storage, and generating capacity positions. Energy Trading also provides natural gas, power and related services, and the supply or purchase of renewable energy credits to various customers which may include the management of associated storage and transportation contracts on the customers’ behalf.

Energy Trading results are discussed below:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2013			2012		2013		2012
	(In millions)
Operating Revenues	$	451		$	239	$	844	$	500
Fuel, Purchased Power and Gas	432			210		789		456
Gross Margin	19			29		55		44
Operation and Maintenance	19			19		40		35
Depreciation and Amortization	1			—		1		—
Taxes Other Than Income	—			1		2		2
Operating Income (Loss)	(1		)	9		12		7
Other (Income) and Deductions	2			2		4		4
Income Tax Expense (Benefit)	(1		)	3		3		1
Net Income (Loss) Attributable to DTE Energy Company	$	(2	)	$	4	$	5	$	2

Gross margin decreased $10 million and increased $11 million for the three and six months ended June 30, 2013, respectively. The overall decrease in gross margin for the second quarter was primarily due to lower gains in the power full requirements strategy. The overall increase in gross margin for the six months ended June 30, 2013 was primarily due to favorable economic performance in our power full requirements strategy due to the absence of the unseasonably mild temperatures that negatively impacted loads during 2012.

The second quarter decrease of $10 million represents a $1 million decrease in realized margins and a $9 million decrease in unrealized margins. The $1 million decrease in realized margins is due to $19 million of unfavorable results, primarily in our power full requirements, power trading, and gas structured strategies, offset by $18 million of favorable results, primarily in our gas trading and gas storage strategies. The $9 million decrease in unrealized margins is due to $19 million of unfavorable results, primarily in our gas trading and gas transportation strategies, offset by $10 million of favorable results, primarily in our power trading, gas structured, and gas storage strategies.

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The $11 million increase for the six months ended June 30, 2013 represents a $14 million increase in realized margins and $3 million decrease in unrealized margins. The $14 million increase in realized margins is due to $34 million of favorable results, primarily in our gas trading, gas full requirements, and power full requirements strategies, offset by $20 million of unfavorable results, primarily in our power trading and gas transportation strategies. The $3 million decrease in unrealized margins is due to $26 million of unfavorable results, primarily in our gas trading strategy, offset by $23 million of favorable results, primarily in our gas structured, power trading, and power full requirements strategies.

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

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

See Notes 3 and 4 of the Notes to Consolidated Financial Statements.

CORPORATE AND OTHER

Corporate and Other includes various holding company activities and holds certain non-utility debt and energy-related investments. Net losses of $13 million and $26 million in the three and six months ended June 30, 2013, respectively, were improvements of $2 million and $4 million, respectively, from the losses in the comparable 2012 periods.

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 5 of the Notes to Consolidated Financial Statements.

CAPITAL RESOURCES AND LIQUIDITY

Cash Requirements

We use cash to maintain and expand our electric and natural gas utilities and to grow our non-utility businesses, retire and pay interest on long-term debt and pay dividends. We believe that we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements. In 2013, we expect that cash from operations will be approximately $1.8 billion. We anticipate base level utility capital investments, environmental, renewable and energy optimization expenditures and expenditures for non-utility businesses in 2013 of approximately $2.2 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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	Six Months Ended June 30,
	2013			2012
	(In millions)
Cash and Cash Equivalents
Cash Flow From (Used For)
Operating activities:
Net income	$	342		$	305
Depreciation, depletion and amortization	527			482
Deferred income taxes	123			81
Asset (gains) and losses, reserves and impairments, net	—			(7		)
Working capital and other	275			300
	1,267			1,161
Investing activities:
Plant and equipment expenditures — utility	(708		)	(708		)
Plant and equipment expenditures — non-utility	(197		)	(131		)
Proceeds from sale of assets	15			15
Other	(21		)	(8		)
	(911		)	(832		)
Financing activities:
Issuance of long-term debt	371			496
Redemption of long-term debt	(515		)	(140		)
Short-term borrowings, net	(24		)	(380		)
Issuance of common stock	19			20
Dividends on common stock and other	(226		)	(208		)
	(375		)	(212		)
Net Increase (Decrease) in Cash and Cash Equivalents	$	(19	)	$	117

Cash from Operating Activities

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

Cash from operations in the six months ended June 30, 2013 was $106 million higher than the comparable 2012 period. The operating cash flow comparison primarily reflects higher net income after adjusting for non-cash and non-operating items (depreciation, depletion and amortization, deferred income taxes and asset (gains) and losses, reserves and impairments, net)partially offset by lower cash generated from working capital items.

Cash from 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 businesses is primarily to maintain and improve our electric generation and electric and natural gas distribution infrastructure and to comply with environmental regulations and renewable energy requirements.

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

Net cash used for investing activities was higher by $79 million in 2013 due primarily to increased capital expenditures by our non-utility businesses.

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Cash from Financing Activities

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

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

Net cash used for financing activities was higher by $163 million in 2013 due primarily to redemption of long-term debt, partially offset by decreased payments of short-term borrowings and lower issuances 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 delayed collection of underrecoveries of our various recovery and tracking mechanisms as a result of timing of MPSC orders. Energy prices are likely to be a source of volatility with regard to working capital requirements for the foreseeable future. We are continuing our efforts to identify opportunities to improve cash flow through working capital initiatives and maintaining flexibility in the timing and extent of our long-term capital projects.

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

DTE Energy has approximately $1.6 billion of available liquidity at June 30, 2013, consisting of cash and amounts available under unsecured revolving credit agreements.

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

During the first six months of 2013, the Company contributed $150 million to its pension plans, including a contribution of DTE Energy common stock of $100 million. At the discretion of management, and depending upon financial market condition, the Company may make up to an additional $125 million contribution to its pension plans in 2013. In January 2013, the Company contributed $145 million to its other postretirement benefit plans. At the discretion of management, the Company may make up to an additional $120 million contribution to its other postretirement benefit plans in 2013.

Various non-utility subsidiaries of the Company have entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade. As of June 30, 2013, the value of the transactions for which the Company would have been exposed to collateral requests had DTE Energy’s credit rating been below investment grade on such date was approximately $313 million. In circumstances where an entity is downgraded below investment grade and collateral requests are made as a result, the requesting parties often agree to accept less than the full amount of their exposure to the downgraded entity. In addition, the Company maintains adequate credit facilities to meet this obligation should such an occurrence arise.

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

See Notes 7, 8, 10, 11 and 13 of the Notes to Consolidated Financial Statements.

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FAIR VALUE

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

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

The Company manages its mark-to-market (MTM) risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, 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 Company has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). For further discussion of the fair value hierarchy. See Note 3 of the Notes to Consolidated Financial Statements.

The following tables provide details on changes in our MTM net asset (or liability) position for the six months ended June 30, 2013:

	Total
	(In millions)
MTM at December 31, 2012	$	(4	)
Reclassify to realized upon settlement	(32		)
Changes in fair value recorded to income	33
Amounts recorded to unrealized income	1
Changes in fair value recorded in regulatory liabilities	4
Amounts recorded in other comprehensive income, pretax	1
Change in collateral held by others	5
Option premiums paid and other	4
MTM at June 30, 2013	$	11

The table below shows the maturity of our MTM positions:

Source of Fair Value	2013			2014			2015			2016  and  Beyond		Total Fair Value
	(In millions)
Level 1	$	9		$	(3	)	$	(5	)	$	—	$	1
Level 2	15			2			4			—		21
Level 3	(22		)	5			1			—		(16		)
MTM before collateral adjustments	$	2		$	4		$	—		$	—	6
Collateral adjustments												5
MTM at June 30, 2013												$	11

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Market Price Risk

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

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

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

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

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

Credit Risk

Bankruptcies

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

The Company's utilities provide services to the city of Detroit, Michigan (Detroit). Detroit filed for Chapter 9 bankruptcy protection on July 18, 2013. Based on average monthly revenues and typical billing and payment cycles, the Company estimates that it has pre-petition accounts receivable of approximately $18 million. Detroit has been paying amounts owed in a timely manner and its account is substantially current. The Company does not expect Detroit's bankruptcy filing to have a material impact on its financial results.

Other

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

52

Trading Activities

We are exposed to credit risk through trading activities. Credit risk is the potential loss that may result if our trading counterparties fail to meet their contractual obligations. We utilize both external and internal credit assessments when determining the credit quality of our trading counterparties. The following table displays the credit quality of our trading counterparties as of June 30, 2013:

	Credit Exposure Before Cash Collateral		Cash Collateral		Net Credit Exposure
	(In millions)
Investment Grade (a)
A− and Greater	$	84	$	—	$	84
BBB+ and BBB	248		—		248
BBB−	107		—		107
Total Investment Grade	439		—		439
Non-investment grade (b)	2		—		2
Internally Rated — investment grade (c)	139		—		139
Internally Rated — non-investment grade (d)	19		—		19
Total	$	599	$	—	$	599

_______________________________________

(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 35 percent 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 one percent 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 15 percent 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 three percent 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 June 30, 2013, we had a floating rate debt-to-total debt ratio of approximately three percent (excluding securitized debt).

Foreign Currency Exchange Risk

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

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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 June 30, 2013 and 2012 by a hypothetical 10% and calculating the resulting change in the fair values.

The results of the sensitivity analysis calculations as of June 30, 2013 and 2012:

	Assuming a 10% Increase in Rates						Assuming a 10% Decrease in Rates
	As of June 30,						As of June 30,
Activity	2013			2012			2013			2012			Change in the Fair Value of
	(In millions)
Coal contracts	$	—		$	2		$	—		$	(1	)	Commodity contracts
Natural gas contracts	$	(12	)	$	(9	)	$	12		$	10		Commodity contracts
Electricity contracts	$	6		$	2		$	(6	)	$	(3	)	Commodity contracts
Interest rate risk	$	(264	)	$	(233	)	$	279		$	246		Long-term debt
Foreign currency exchange risk	$	—		$	—		$	—		$	—		Forward contracts
Discount rates	$	—		$	—		$	—		$	—		Commodity contracts

For further discussion of market risk, see Note 4 of the Notes to Consolidated Financial Statements.

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Item 4.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 June 30, 2013, which is the end of the period covered by this report. Based on this evaluation, the Company's CEO and CFO have concluded that such disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms and (ii) is accumulated and communicated to the Company's management, including its CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.

(b) 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 June 30, 2013 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

55

Part II — OTHER INFORMATION

Item 1. Legal Proceedings

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

In August 2010, the U.S. Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and DTE Electric, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require DTE Electric to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require DTE Electric to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from DTE Electric's fleet of coal-fired power plants until the new control equipment is operating. On August 23, 2011, the U.S. District Court judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy and DTE Electric. On October 20, 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit. On March 28, 2013, the Court of Appeals remanded the case to the U.S. District Court for review of the procedural component of the New Source Review notification requirements.

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

On March 13, 2013, The Sierra Club filed suit against DTE Energy and DTE Electric alleging violations of the Clean Air Act at four of DTE Electric's coal-fired power plants. The plaintiffs allege 1,499 6-minute periods of excess opacity of air emissions from 2007-2012 at those facilities. The suit asks that the court enjoin DTE Energy and DTE Electric from operating the power plants except in complete compliance with applicable laws and permit requirements, pay civil penalties, conduct beneficial environmental mitigation projects, pay attorney fees and require the installation of any necessary pollution controls or to convert and/or operate the plants' boilers on natural gas to avoid additional violations and to off-set historic unlawful emissions. The resolution of this matter is not expected to have a material effect on the Company's operations or financial statements.

For additional discussion on legal matters, see Notes 7 and 12 of the Notes to Consolidated Financial Statements.

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 have provided a brief explanation of the more significant risks associated with our businesses in Part 1, Item 1A. Risk Factors in the Company's 2012 Form 10-K. Although we have tried to identify and discuss key risk factors, others could emerge in the future. In addition to the risk factors set forth in our 10-K, the following updated risk could affect our performance.

A work interruption may adversely affect us. Unions represent approximately 4,900 of our employees. Our contracts with several bargaining units for the majority of our represented employees were due to expire in June and October 2013. Early negotiations resulted in new contracts that became effective March 23, 2013. The new contracts will expire on June 5, 2017 for the DTE Electric bargaining units and on October 9, 2017 for the DTE Gas bargaining units. A union choosing to strike would

56

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.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

On June 12, 2013, the Company contributed $50 million of DTE Energy common stock to the DTE Energy Company Affiliates Employee Benefit Plans Master Trust. The contribution consisted of 753,579 shares valued at $66.35 per share, the closing market price of DTE Energy common stock on that date in accordance with fair value measurement and accounting requirements. The shares were contributed to the trust in a private placement transaction made in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act of 1933 as amended.

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 for the quarter ended June 30, 2013:

	Number of Shares Purchased (a)	Average Price Paid per Share (a)		Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Average Price Paid per Share	Maximum Dollar Value that May Yet Be Purchased Under the Plans or Programs
04/01/2013 — 04/30/2013	3,148	$	69.19	—	—	—
05/01/2013 — 05/31/2013	850	69.09		—	—	—
06/01/2013 — 06/30/2013	17,247	65.02		—	—	—
Total	21,245			—

_______________________________________

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

Item 6. Exhibits

	(i) Exhibits filed herewith:
12-54	Computation of Ratio of Earnings to Fixed Charges
31-83	Chief Executive Officer Section 302 Form 10-Q Certification of Periodic Report
31-84	Chief Financial Officer Section 302 Form 10-Q 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 furnished herewith:
32-83	Chief Executive Officer Section 906 Form 10-Q Certification of Periodic Report
32-84	Chief Financial Officer Section 906 Form 10-Q Certification of Periodic Report

57

Signature

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)
Date: July 26, 2013	By	/s/  DONNA M. ENGLAND
		Donna M. England Chief Accounting Officer (Principal Accounting Officer)

58

EX-12.54

Exhibit 12-54

DTE ENERGY COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
	Six Months Ended		Twelve Months Ended December 31
(Millions of Dollars)	June 30, 2013		2012		2011	2010	2009	2008
Earnings:
Pretax earnings	481		1,035		989	968	778	518
Adjustments	(7	)	(4	)	6	1	4	(3	)
Fixed Charges	234		463		520	567	572	540
Net earnings	708		1,494		1,515	1,536	1,354	1,055
Fixed Charges:
Interest expense	219		441		490	543	545	503
Adjustments	15		22		30	24	27	37
Fixed Charges	234		463		520	567	572	540
Ratio of earnings to fixed charges	3.03		3.23		2.91	2.71	2.37	1.95

EX-31.83

Exhibit 31-83

FORM 10-Q CERTIFICATION

I, Gerard M. Anderson, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of DTE Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/S/ GERARD M. ANDERSON	Date:	July 26, 2013
Gerard M. Anderson Chairman of the Board, President and Chief Executive Officer of DTE Energy Company

EX-31.84

Exhibit 31-84

FORM 10-Q CERTIFICATION

I, David E. Meador, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of DTE Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/S/ DAVID E. MEADOR	Date:	July 26, 2013
David E. Meador Executive Vice President and Chief Financial Officer of DTE Energy Company

EX-32.83

Exhibit 32-83

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of DTE Energy Company (the “Company”) for the quarter ended June 30, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Gerard M. Anderson, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge and belief:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	July 26, 2013	/S/ GERARD M. ANDERSON
		Gerard M. Anderson Chairman of the Board, President and Chief Executive Officer of DTE Energy Company

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.84

Exhibit 32-84

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of DTE Energy Company (the “Company”) for the quarter ended June 30, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David E. Meador, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge and belief:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	July 26, 2013	/S/ DAVID E. MEADOR
		David E. Meador Executive Vice President and Chief Financial Officer of DTE Energy Company

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Stock-Based Compensation Stock-Based Compensation (Details 3)	6 Months Ended
	Jun. 30, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Awards Outstanding Shares	1,596,861	1,634,364
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	534,027
Restricted Stock Award Activity Forfeitures	(22,906)
Restricted Stock Award Activity Vested and Issued	(548,624)

XML

Supplemental Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$ 70	$ 120
Inventories	133	81
Accrued/prepaid pension costs	(42)	6
Accounts payable	(29)	(4)
Income taxes payable/receivable	(20)	(39)
Derivative assets and liabilities	(15)	26
Postretirement obligation	(174)	(142)
Period Increase Decrease in Gas Inventory Equlaization	73	65
Other assets	324	299
Other liabilities	(45)	(112)
Total Changes in Assets and Liabilities, Exclusive of Changes Shown Separately	$ 275	$ 300

XML

Earnings Per Share (Notes)

6 Months Ended

Jun. 30, 2013

Earnings Per Share [Abstract]

EARNINGS PER SHARE

EARNINGS PER SHARE

The Company reports both basic and diluted earnings per share. The calculation of diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period from the exercise of stock options. A reconciliation of both calculations is presented in the following table for the three months and six months ended June 30:

	Three Months Ended					Six Months Ended
	June 30					June 30
	2013			2012		2013		2012
	(In millions, except per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	105		$	146	$	339	$	302
Average number of common shares outstanding	174			170		174		170
Weighted average net restricted shares outstanding	1			1		1		1
Dividends declared — common shares	$	114		$	100	$	222	$	200
Dividends declared — net restricted shares	1			1		—		1
Total distributed earnings	$	115		$	101	$	222	$	201
Net income less distributed earnings	$	(10	)	$	45	$	117	$	101
Distributed (dividends per common share)	$	0.66		$	0.59	$	1.28	$	1.18
Undistributed	(0.06		)	0.27		0.66		0.59
Total Basic Earnings per Common Share	$	0.60		$	0.86	$	1.94	$	1.77
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	105		$	146	$	339	$	302
Average number of common shares outstanding	175			170		174		170
Average incremental shares from assumed exercise of options	—			1		—		1
Common shares for dilutive calculation	175			171		174		171
Weighted average net restricted shares outstanding	1			1		1		1
Dividends declared — common shares	$	114		$	100	$	222	$	200
Dividends declared — net restricted shares	1			1		—		1
Total distributed earnings	$	115		$	101	$	222	$	201
Net income less distributed earnings	$	(10	)	$	45	$	117	$	101
Distributed (dividends per common share)	$	0.66		$	0.59	$	1.28	$	1.18
Undistributed	(0.06		)	0.27		0.66		0.59
Total Diluted Earnings per Common Share	$	0.60		$	0.86	$	1.94	$	1.77

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Fair Value (Details Textuals) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2013 dte_instances	Jun. 30, 2012	Jun. 30, 2013 dte_instances	Jun. 30, 2012	Dec. 31, 2012
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Cash Equivalents Included in Restricted Cash	$ 96,000,000		$ 96,000,000		$ 109,000,000
Fair Value of Cash Equivalents Included in Other Investments	16,000,000		16,000,000		14,000,000
Other investments	119,000,000		119,000,000		110,000,000
Maturity in Years for Cash and Cash Equivalents			3 months
Number of Certain Forward Market and Basis Prices Used	2		2
Average Maturity of Debt Securities			6 years		6 years
Unrealized losses recognized as regulatory assets	52,000,000		52,000,000		44,000,000
Fermi I Corresponding Regulatory Asset Treatment	0		0
Other than Temporary Impairment Losses, Investments, Portion Recognized in Earnings, Net	0	0	0	0
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, before Tax	0	0	0	0
Trading Securities, Change in Unrealized Holding Gain (Loss)			8,000,000	5,000,000
Cash Equivalents [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Available-for-sale Securities, Fair Value Disclosure	112,000,000		112,000,000		123,000,000
Equity [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Available-for-sale Securities, Fair Value Disclosure	$ 6,000,000		$ 6,000,000		$ 5,000,000

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Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) Consolidated Statements of Comprehensive Income (Unaudited) (Parentheticals) (Tax Effect [Member], USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Tax Effect [Member]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Benefit Plan Improvement, Tax Effect	$ 1	$ 1	$ 2	$ 3
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	0	0	0	0
Other Comprehensive Income (Loss), Foreign Currency Translation Gain (Loss) Arising During Period, Tax	$ (1)	$ 0	$ (1)	$ 0

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Significant Accounting Policies (Notes)

6 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

SIGNIFICANT ACCOUNTING POLICIES

Comprehensive Income

Comprehensive income is the change in common shareholders’ equity during a period from transactions and events from non-owner sources, including net income. As shown in the following tables, amounts recorded to accumulated other comprehensive loss for the three and six months ended June 30, 2013 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 transition amounts related to pension and other postretirement benefit plans, and foreign currency translation adjustments.

	Changes in Accumulated Other Comprehensive Loss by Component (a)
	For The Three Months Ended June 30, 2013
	Net Unrealized Gain/(Loss) on Derivatives			Net Unrealized Gain/(Loss) on Investments			Benefit Obligations (b)			Foreign Currency Translation			Total
	(In millions)
Beginning balance, March 31, 2013	$	(4	)	$	(8	)	$	(145	)	$	1		$	(156	)
Other comprehensive income before reclassifications	—			—			—			(1		)	(1		)
Amounts reclassified from accumulated other comprehensive income	—			—			2			—			2
Net current-period other comprehensive income	—			—			2			(1		)	1
Ending balance, June 30, 2013	$	(4	)	$	(8	)	$	(143	)	$	—		$	(155	)

	Changes in Accumulated Other Comprehensive Loss by Component (a)
	For The Six Months Ended June 30, 2013
	Net Unrealized Gain/(Loss) on Derivatives			Net Unrealized Gain/(Loss) on Investments			Benefit Obligations (b)			Foreign Currency Translation			Total
	(In millions)
Beginning balance, December 31, 2012	$	(4	)	$	(8	)	$	(148	)	$	2		$	(158	)
Other comprehensive income before reclassifications	—			—			—			(2		)	(2		)
Amounts reclassified from accumulated other comprehensive income	—			—			5			—			5
Net current-period other comprehensive income	—			—			5			(2		)	3
Ending balance, June 30, 2013	$	(4	)	$	(8	)	$	(143	)	$	—		$	(155	)

______________________________________

(a) All amounts are net of tax.

(b) The amounts reclassified from accumulated other comprehensive income are included in the computation of the net periodic pension cost (see Retirement Benefits and Trusteed Assets Note 13).

Intangible Assets

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

	June 30,		December 31,
	2013		2012
	(In millions)
Emission allowances	$	4	$	6
Renewable energy credits	47		44
Contract intangible assets	141		139
	192		189
Less accumulated amortization	40		34
Intangible assets, net	152		155
Less current intangible assets	14		20
	$	138	$	135

Emission allowances and renewable energy credits are charged to expense, using average cost, as the allowances and credits are consumed in the operation of the business. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 3 to 28 years.

Income Taxes

The Company's effective tax rate from continuing operations for the three months ended June 30, 2013 was 29 percent as compared to 32 percent for the three months ended June 30, 2012. The Company's effective tax rate from continuing operations for the six months ended June 30, 2013 was 30 percent as compared to 32 percent for the six months ended June 30, 2012. The decrease in the effective tax rate in 2013 is due primarily to higher production tax credits.

The Company had $3 million of unrecognized tax benefits at June 30, 2013, that, if recognized, would favorably impact its effective tax rate. The Company believes that it is possible that there will be a decrease in the unrecognized tax benefits of up to $1 million in the next twelve months.

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Segment Information (Notes)

6 Months Ended

Jun. 30, 2013

Segment Reporting [Abstract]

SEGMENT INFORMATION

SEGMENT AND RELATED INFORMATION

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

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

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

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

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

Energy Trading consists of energy marketing and trading operations.

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

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(In millions)
Inter-segment Revenues
Electric	$	7		$	8		$	13		$	15
Gas	1			1			2			2
Gas Storage and Pipelines	2			3			4			4
Power and Industrial Projects	185			192			390			383
Energy Trading	12			10			23			24
Corporate and Other	(7		)	(7		)	(15		)	(17		)
	$	200		$	207		$	417		$	411

Financial data of the business segments follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(In millions)
Operating Revenues
Electric	$	1,265		$	1,290		$	2,484		$	2,488
Gas	248			214			852			723
Gas Storage and Pipelines	31			27			58			52
Power and Industrial Projects	429			449			919			898
Energy Trading	451			239			844			500
Corporate & Other	1			1			1			2
Reconciliation & Eliminations	(200		)	(207		)	(417		)	(411		)
Total	$	2,225		$	2,013		$	4,741		$	4,252
Net Income (Loss) Attributable to DTE Energy by Segment:
Electric	$	89		$	127		$	204		$	223
Gas	8			4			104			56
Gas Storage and Pipelines	16			17			33			34
Power and Industrial Projects	7			10			19			18
Energy Trading	(2		)	4			5			2
Corporate & Other	(13		)	(15		)	(26		)	(30		)
Discontinued operations	—			(1		)	—			(1		)
Net Income Attributable to DTE Energy	$	105		$	146		$	339		$	302

XML

Long-Term Debt (Details 1) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013
Extinguishment of Debt [Line Items]
Extinguishment of Debt, Amount	$ 515
Securitization Bonds [Member]
Extinguishment of Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.42%
Extinguishment of Debt, Amount	88
Tax Exempt Revenue Bonds [Member]
Extinguishment of Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.30%
Extinguishment of Debt, Amount	51
Long-term Debt [Member]
Extinguishment of Debt [Line Items]
Extinguishment of Debt, Amount	3
Senior Notes [Member]
Extinguishment of Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.26%
Extinguishment of Debt, Amount	60
Senior Notes 1 [Member]
Extinguishment of Debt [Line Items]
Extinguishment of Debt, Amount	300
Long Term Debt, Other [Member]
Extinguishment of Debt [Line Items]
Extinguishment of Debt, Amount	$ 13

XML

Financial and Other Derivative Instruments Financial and Other Derivative Instruments (Details 2) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Derivative [Line Items]
Derivative Assets, Current	$ 90	$ 108
Derivative Assets, Noncurrent	27	39
Derivative Liabilities, Current	(90)	(125)
Derivative Liabilities, Noncurrent	(16)	(26)
Derivative Asset [Member]
Derivative [Line Items]
Derivative Assets, Current	757	862
Derivative Assets, Noncurrent	119	154
Derivative Liabilities [Member]
Derivative [Line Items]
Derivative Liabilities, Current	(750)	(879)
Derivative Liabilities, Noncurrent	(120)	(141)
Counterparty Netting [Member]
Derivative [Line Items]
Derivative Assets, Current	(653)	(754)
Derivative Assets, Noncurrent	(92)	(115)
Derivative Liabilities, Current	653	754
Derivative Liabilities, Noncurrent	92	115
Collateral Adjustment [Member]
Derivative [Line Items]
Derivative Assets, Current	(14)	0
Derivative Assets, Noncurrent	0	0
Derivative Liabilities, Current	7	0
Derivative Liabilities, Noncurrent	12	0
Derivative [Member]
Derivative [Line Items]
Derivative Assets, Current	90	108
Derivative Assets, Noncurrent	27	39
Derivative Liabilities, Current	(90)	(125)
Derivative Liabilities, Noncurrent	$ (16)	$ (26)

XML

Long-Term Debt (Notes)

6 Months Ended

Jun. 30, 2013

Long-term Debt, Unclassified [Abstract]

Long-term Debt [Text Block]

LONG-TERM DEBT

Debt Issuance

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

Company	Month Issued	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March	Mortgage Bonds (a)	4.00	%	2043	$	375
						$	375

_______________________________________

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

Debt Redemptions

In 2013, the following debt was redeemed:

	Month	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March	Securitization Bonds	6.42	%	2013	$	88
DTE Electric	March	Tax Exempt Revenue Bonds (a)	5.30	%	2030	51
DTE Electric	April	Other Long-Term Debt	Various		2013	13
DTE Energy	Various	Other Long-Term Debt	Various		2013	3
DTE Gas	April	Senior Notes	5.26	%	2013	60
DTE Energy	June	Senior Notes	Variable		2013	300
						$	515

_______________________________________

(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.

XML

Fair Value Fair Value (Details 3) (USD $)	6 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2012
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ (870,000,000)	$ (1,020,000,000)
Derivative Asset, Fair Value, Gross Asset	876,000,000	1,016,000,000
Electricity [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Liability, Fair Value, Gross Liability	(60,000,000)	(93,000,000)
Derivative Asset, Fair Value, Gross Asset	97,000,000	102,000,000
Natural Gas [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Liability, Fair Value, Gross Liability	(41,000,000)	(56,000,000)
Derivative Asset, Fair Value, Gross Asset	14,000,000	40,000,000
Fair Value, Inputs, Level 3 [Member] | Electricity [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Maximum Weighted Average Range for Unobservable Inputs	17	16
Weighted Average of Unobservable Fair Value Inputs	3	3
Minimum Weighted Average Range for Unobservable Inputs	(8)	(2)
Derivative Liability, Fair Value, Gross Liability	(86,000,000)	(111,000,000)
Derivative Asset, Fair Value, Gross Asset	98,000,000	134,000,000
Fair Value, Inputs, Level 3 [Member] | Natural Gas [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Maximum Weighted Average Range for Unobservable Inputs	0.54	1.95
Weighted Average of Unobservable Fair Value Inputs	0.01	0.03
Minimum Weighted Average Range for Unobservable Inputs	(2.63)	(0.63)
Derivative Liability, Fair Value, Gross Liability	(62,000,000)	(62,000,000)
Derivative Asset, Fair Value, Gross Asset	$ 32,000,000	$ 24,000,000

XML

Segment Information (Details Textuals)	Jun. 30, 2013 customers
Entity Information [Line Items]
Number of Electric Customers	2,100,000
Number of Gas Customers	1,200,000
Number of Citizens Gas Customers	17,000

XML

Financial and Other Derivative Instruments (Details 3) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 8	$ 47	$ 33	$ 45
Foreign currency exchange contracts [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(1)	1	(1)	1
Natural Gas [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	46	1	36	3
Natural Gas [Member] | Fuel, purchased power and gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(46)	5	(32)	(5)
Electricity [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	10	37	30	35
Other [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ (1)	$ 3	$ 0	$ 11

XML

Segment Information (Tables)

6 Months Ended

Jun. 30, 2013

Segment Reporting [Abstract]

Inter segment billing for goods and services [Table Text Block]

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(In millions)
Inter-segment Revenues
Electric	$	7		$	8		$	13		$	15
Gas	1			1			2			2
Gas Storage and Pipelines	2			3			4			4
Power and Industrial Projects	185			192			390			383
Energy Trading	12			10			23			24
Corporate and Other	(7		)	(7		)	(15		)	(17		)
	$	200		$	207		$	417		$	411

Schedule of Segment Reporting Information, by Segment [Table Text Block]

Financial data of the business segments follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(In millions)
Operating Revenues
Electric	$	1,265		$	1,290		$	2,484		$	2,488
Gas	248			214			852			723
Gas Storage and Pipelines	31			27			58			52
Power and Industrial Projects	429			449			919			898
Energy Trading	451			239			844			500
Corporate & Other	1			1			1			2
Reconciliation & Eliminations	(200		)	(207		)	(417		)	(411		)
Total	$	2,225		$	2,013		$	4,741		$	4,252
Net Income (Loss) Attributable to DTE Energy by Segment:
Electric	$	89		$	127		$	204		$	223
Gas	8			4			104			56
Gas Storage and Pipelines	16			17			33			34
Power and Industrial Projects	7			10			19			18
Energy Trading	(2		)	4			5			2
Corporate & Other	(13		)	(15		)	(26		)	(30		)
Discontinued operations	—			(1		)	—			(1		)
Net Income Attributable to DTE Energy	$	105		$	146		$	339		$	302

XML

Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

	Changes in Accumulated Other Comprehensive Loss by Component (a)
	For The Three Months Ended June 30, 2013
	Net Unrealized Gain/(Loss) on Derivatives			Net Unrealized Gain/(Loss) on Investments			Benefit Obligations (b)			Foreign Currency Translation			Total
	(In millions)
Beginning balance, March 31, 2013	$	(4	)	$	(8	)	$	(145	)	$	1		$	(156	)
Other comprehensive income before reclassifications	—			—			—			(1		)	(1		)
Amounts reclassified from accumulated other comprehensive income	—			—			2			—			2
Net current-period other comprehensive income	—			—			2			(1		)	1
Ending balance, June 30, 2013	$	(4	)	$	(8	)	$	(143	)	$	—		$	(155	)

	Changes in Accumulated Other Comprehensive Loss by Component (a)
	For The Six Months Ended June 30, 2013
	Net Unrealized Gain/(Loss) on Derivatives			Net Unrealized Gain/(Loss) on Investments			Benefit Obligations (b)			Foreign Currency Translation			Total
	(In millions)
Beginning balance, December 31, 2012	$	(4	)	$	(8	)	$	(148	)	$	2		$	(158	)
Other comprehensive income before reclassifications	—			—			—			(2		)	(2		)
Amounts reclassified from accumulated other comprehensive income	—			—			5			—			5
Net current-period other comprehensive income	—			—			5			(2		)	3
Ending balance, June 30, 2013	$	(4	)	$	(8	)	$	(143	)	$	—		$	(155	)

______________________________________

(a) All amounts are net of tax.

(b) The amounts reclassified from accumulated other comprehensive income are included in the computation of the net periodic pension cost (see Retirement Benefits and Trusteed Assets Note 13).

Schedule of Finite-Lived Intangible Assets by Major Class [Table Text Block]

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

	June 30,		December 31,
	2013		2012
	(In millions)
Emission allowances	$	4	$	6
Renewable energy credits	47		44
Contract intangible assets	141		139
	192		189
Less accumulated amortization	40		34
Intangible assets, net	152		155
Less current intangible assets	14		20
	$	138	$	135

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Organization and Basis of Presentation (Tables)

6 Months Ended

Jun. 30, 2013

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

Schedule of Variable Interest Entities [Table Text Block]

	June 30, 2013						December 31, 2012
	Securitization		Other		Total		Securitization		Other		Total
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	8	$	8	$	—	$	10	$	10
Restricted cash	90		6		96		102		7		109
Accounts receivable	39		16		55		34		7		41
Inventories	—		91		91		—		141		141
Other current assets	—		1		1		—		1		1
Property, plant and equipment	—		103		103		—		93		93
Securitized regulatory assets	326		—		326		413		—		413
Other assets	6		9		15		7		11		18
	$	461	$	234	$	695	$	556	$	270	$	826
LIABILITIES
Accounts payable and accrued current liabilities	$	9	$	33	$	42	$	11	$	14	$	25
Current portion long-term debt, including capital leases	189		8		197		177		8		185
Current regulatory liabilities	45		—		45		50		—		50
Other current liabilities	—		3		3		—		4		4
Mortgage bonds, notes and other	—		23		23		—		25		25
Securitization bonds	201		—		201		302		—		302
Capital lease obligations	—		8		8		—		11		11
Other long-term liabilities	8		2		10		7		2		9
	$	452	$	77	$	529	$	547	$	64	$	611

Summary of amounts for non-consolidated VIEs [Table Text Block

Amounts for non-consolidated VIEs as of June 30, 2013 and December 31, 2012 are as follows:

	June 30, 2013		December 31, 2012
	(In millions)
Other investments	$	136	$	130
Notes receivable	6		6

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Fair Value (Details 1) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis
Beginning Balance	$ (41)	$ 37	$ (13)	$ 44
Transfers into Level 3	0	1	0	29
Transfer out of Level 3	0	0	(2)	(2)
Total gains: [Abstract]
Included in earnings	15	52	15	45
Recorded in regulatory assets/liabilities	3	4	4	5
Purchases issuances and settlements [Abstract]
Purchases			1	0
Settlements	7	(37)	(21)	(64)
Ending Balance	(16)	57	(16)	57
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	31	33	20	40
Natural Gas [Member]
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis
Beginning Balance	(34)	6	(38)	6
Transfers into Level 3	0	1	0	1
Transfer out of Level 3	0	0	(2)	(2)
Total gains: [Abstract]
Included in earnings	(2)	(1)	(10)	6
Recorded in regulatory assets/liabilities	0	0	0	0
Purchases issuances and settlements [Abstract]
Purchases			0	0
Settlements	6	(4)	20	(9)
Ending Balance	(30)	2	(30)	2
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	(1)	(2)	(6)	4
Electricity [Member]
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis
Beginning Balance	(9)	25	23	32
Transfers into Level 3	0	0	0	28
Transfer out of Level 3	0	0	0	0
Total gains: [Abstract]
Included in earnings	18	56	26	41
Recorded in regulatory assets/liabilities	0	0	0	0
Purchases issuances and settlements [Abstract]
Purchases			1	0
Settlements	3	(31)	(38)	(51)
Ending Balance	12	50	12	50
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	33	38	27	38
Other [Member]
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis
Beginning Balance	2	6	2	6
Transfers into Level 3	0	0	0	0
Transfer out of Level 3	0	0	0	0
Total gains: [Abstract]
Included in earnings	(1)	(3)	(1)	(2)
Recorded in regulatory assets/liabilities	3	4	4	5
Purchases issuances and settlements [Abstract]
Purchases			0	0
Settlements	(2)	(2)	(3)	(4)
Ending Balance	2	5	2	5
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	$ (1)	$ (3)	$ (1)	$ (2)

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Short-Term Credit Arrangements and Borrowings (Tables)

6 Months Ended

Jun. 30, 2013

Short-term Debt [Abstract]

Schedule of Short-term Debt [Table Text Block]

The availability under the facilities in place at June 30, 2013 is shown in the following table:

	DTE Energy		DTE Electric		DTE Gas		Total
	(In millions)
Unsecured letter of credit facility, expiring in May 2014	$	50	$	—	$	—	$	50
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Unsecured revolving credit facility, expiring April 2018	1,200		300		300		1,800
Total credit facilities at June 30, 2013	1,375		300		300		1,975
Amounts outstanding at June 30, 2013:
Commercial paper issuances	101		96		19		216
Letters of credit	184		—		—		184
	285		96		19		400
Net availability at June 30, 2013	$	1,090	$	204	$	281	$	1,575

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Organization and Basis of Presentation (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012	Dec. 31, 2011
Assets [Abstract]
Cash and cash equivalents	$ 46	$ 65	$ 185	$ 68
Restricted cash	112	122
Accounts receivable	1,314	1,336
Other current assets	115	194
Property, plant and equipment	15,190	14,684
Securitized regulatory assets	326	413
Other assets	199	197
Total Assets	25,944	26,339
Liabilities [Abstract]
Current portion long-term debt, including, capital leases	879	817
Other current liabilities	570	538
Mortgage bonds, notes and other	6,116	6,220
Securitization bonds	201	302
Capital lease obligations	9	12
Other long term liabilities	283	306
Variable Interest Entity Securitization [Member]
Assets [Abstract]
Cash and cash equivalents	0	0
Restricted cash	90	102
Accounts receivable	39	34
Inventories	0	0
Other current assets	0	0
Property, plant and equipment	0	0
Securitized regulatory assets	326	413
Other assets	6	7
Total Assets	461	556
Liabilities [Abstract]
Accounts payable and accrued current liabilities	9	11
Current portion long-term debt, including, capital leases	189	177
Current regulatory liabilities	45	50
Other current liabilities	0	0
Mortgage bonds, notes and other	0	0
Securitization bonds	201	302
Capital lease obligations	0	0
Other long term liabilities	8	7
Total Liabilities	452	547
Variable Interest Entity, Primary Beneficiary [Member]
Assets [Abstract]
Cash and cash equivalents	8	10
Restricted cash	6	7
Accounts receivable	16	7
Inventories	91	141
Other current assets	1	1
Property, plant and equipment	103	93
Securitized regulatory assets	0	0
Other assets	9	11
Total Assets	234	270
Liabilities [Abstract]
Accounts payable and accrued current liabilities	33	14
Current portion long-term debt, including, capital leases	8	8
Current regulatory liabilities	0	0
Other current liabilities	3	4
Mortgage bonds, notes and other	23	25
Securitization bonds	0	0
Capital lease obligations	8	11
Other long term liabilities	2	2
Total Liabilities	77	64
Consolidated Variable Interest Entity [Member]
Assets [Abstract]
Cash and cash equivalents	8	10
Restricted cash	96	109
Accounts receivable	55	41
Inventories	91	141
Other current assets	1	1
Property, plant and equipment	103	93
Securitized regulatory assets	326	413
Other assets	15	18
Total Assets	695	826
Liabilities [Abstract]
Accounts payable and accrued current liabilities	42	25
Current portion long-term debt, including, capital leases	197	185
Current regulatory liabilities	45	50
Other current liabilities	3	4
Mortgage bonds, notes and other	23	25
Securitization bonds	201	302
Capital lease obligations	8	11
Other long term liabilities	10	9
Total Liabilities	$ 529	$ 611

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Fair Value Fair Value (Details 4) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Fair Value of Financial Instruments [Line Items]
Notes Receivable Excudling Capital Leases	$ 36	$ 39
Dividends Payable, Current	229	107
Short-term Debt	216	240
Long-term Debt	7,671	7,813
Fair Value, Inputs, Level 1 [Member]
Fair Value of Financial Instruments [Line Items]
Notes Receivable, Fair Value Disclosure	0	0
Dividends Payable Fair Value Disclosure	229	107
Short-term Debt, Fair Value	0	0
Long-term Debt, Fair Value	487	507
Fair Value, Inputs, Level 2 [Member]
Fair Value of Financial Instruments [Line Items]
Notes Receivable, Fair Value Disclosure	0	0
Dividends Payable Fair Value Disclosure	0	0
Short-term Debt, Fair Value	216	240
Long-term Debt, Fair Value	6,556	7,453
Fair Value, Inputs, Level 3 [Member]
Fair Value of Financial Instruments [Line Items]
Notes Receivable, Fair Value Disclosure	36	39
Dividends Payable Fair Value Disclosure	0	0
Short-term Debt, Fair Value	0	0
Long-term Debt, Fair Value	$ 1,008	$ 933

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2013

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

A reconciliation of the asset retirement obligations for the six months ended June 30, 2013 follows:

	(In millions)
Asset retirement obligations at December 31, 2012	$	1,719
Accretion	52
Revision in estimated cash flows	13
Asset retirement obligations at June 30, 2013	$	1,784

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Common Stock (Details Textuals) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended	6 Months Ended
	Mar. 31, 2013	Jun. 30, 2013
Class of Stock [Line Items]
Contribution of Common stock to the Pension Plan Value	$ 50	$ 50
Contribution of Common Stock to Pension Plan Shares	750,075	753,579
Contribution of Common Stock to Pension Plans Amount Per Share	$ 66.66	$ 66.35

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Retirement Benefits and Trusteed Assets Retirement Benefits and Trusteed Assets (Details Textuals) (USD $)	6 Months Ended
	Jun. 30, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Contribution of Common Stock to Pension Plan	$ 100,000,000
Retiree Health Care Allowance	3,250
Remeasurement Reduction to Post Retirement Benefit Obligation	258,000,000	439,000,000
Remeasurement Reduction to Post Retirement Benefit Obligation Liability	721,000,000	1,200,000,000
Remeasurement Decrease in Benefit Cost for Postretirement Plans	69,000,000
Annual Decrease in Other Postretirement Benefits Costs due to Remeasurement	40,000,000
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension Contributions	150,000,000
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	125,000,000
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	120,000,000
Defined Benefit Plan, Contributions by Employer	$ 145,000,000
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.30%	4.15%

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Regulatory Matters (Details Textuals) (USD $)	1 Months Ended	60 Months Ended	84 Months Ended	3 Months Ended		6 Months Ended	12 Months Ended					4 Months Ended	12 Months Ended
	Jun. 29, 2013	Jun. 28, 2018	Jun. 28, 2020	Jun. 30, 2013 Electric [Member]	Mar. 31, 2013 Electric [Member]	Jun. 30, 2013 Electric [Member]	Dec. 31, 2012 Electric [Member] mills_per_kWh	Dec. 31, 2011 Electric [Member]	Dec. 31, 2010 Electric [Member]	Dec. 31, 2009 Electric [Member]	Dec. 31, 2008 Electric [Member]	Oct. 31, 2012 Gas [Member]	Dec. 31, 2012 Gas [Member]	Jun. 30, 2013 Gas [Member]	Mar. 31, 2013 Gas [Member]	Jun. 30, 2013 Gas [Member]	Dec. 31, 2012 Gas [Member]
Regulatory Asset and Liability [Line Items]
Accrual for Environmental Loss Contingencies, Gross																$ 30,000,000	$ 29,000,000
EO Reconciliation net over-recovery							26,000,000						7,000,000
REP Surcharge Revenue Recover				15,000,000	100,000,000
REP Time Period						20 years
Years to transition PLD customers to DTE Electric distribution system		5 years	7 years
PSCR Reconciliation Calculating net Under Recovery								158,000,000	52,600,000
Pension Equalization Mechanism Reconciliation surcharge length	1 month
Levelized PSCR Factor							4.18
PSCR Over-recovery										15,600,000
Under-recovery of Pension Equalization Mechanism Reconciliation											7,100,000
Refund of Self-implemented Rate Increase								3,800,000
Power Supply Expense Forecast							1,400,000,000
RDM Application Proposed Recovery												$ 5,200,000
Composite Depreciation Rates														2.51%	2.29%

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Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Mar. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Loss	$ (155)		$ (155)		$ (156)	$ (158)
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Net of Tax	0	0	0	1
Current period change, net of tax Foreign Currency Translation	(1)	(1)	(2)	0
Other Comprehensive Income (Loss), Net of Tax	1		3
Other Comprehensive Income Before Reclassifications	(1)		(2)
Amounts Reclassified From Accumulated Other Comprehensive Income	2		5
Derivative [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net Unrealized Gain/(Loss) on Derivaive	(4)		(4)		(4)	(4)
Current period change, net of tax Net Unrealized Gain/(Loss) on Derivatives Gain (Loss) on Derivatives Arising During Period, Net of Tax	0		0
Other Comprehensive Income Before Reclassifications	0		0
Amounts Reclassified From Accumulated Other Comprehensive Income	0		0
Investments [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net Unrealized Gain/(Loss) on Investments	(8)		(8)		(8)	(8)
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Net of Tax	0		0
Other Comprehensive Income Before Reclassifications	0		0
Amounts Reclassified From Accumulated Other Comprehensive Income	0		0
Pension and Other Postretirement Plans Costs [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Benefit Obligations	(143)		(143)		(145)	(148)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	2		5
Other Comprehensive Income Before Reclassifications	0		0
Amounts Reclassified From Accumulated Other Comprehensive Income	2		5
Foreign currency exchange contracts [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Foreign Currency Translation	0		0		1	2
Current period change, net of tax Foreign Currency Translation	(1)		(2)
Other Comprehensive Income Before Reclassifications	(1)		(2)
Amounts Reclassified From Accumulated Other Comprehensive Income	$ 0		$ 0

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Short-Term Credit Arrangements and Borrowings (Details Textuals) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013 banks	Dec. 31, 2012
Short-term Debt [Line Items]
Revolving Credit Facilities with a Syndicate Number of Banks	19
Number of Banks that Provide Percentage of Commitment in any Facility	1
Maximum Percentage of Commitment to Bank in any Facility	8.70%
Line of Credit Facility, Current Borrowing Capacity	$ 1,975
Maximum Total Funded Debt to Total Capitalization Ratio	0.65
Maximum Total Funded Debt to Total Capitalization Ratio Denominator	1
Letters of Credit Outstanding, Amount	38
Borrowing Capacity Under Financing Agreement With iss Clearing Agent	100
Maximum Additional Margin Financing	50
Line of Credit Facility, Increase, Additional Borrowings	40
Line of Credit Facility Current Borrowing	140
Other Short-term Borrowings	64	65
DTE Energy [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity	1,375
Total Funded Debt to Total Capitalization Ratio	0.48
Total Funded Debt to Total Capitalization Ratio Denominator	1
DTE Electric [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity	300
Total Funded Debt to Total Capitalization Ratio	0.53
Total Funded Debt to Total Capitalization Ratio Denominator	1
DTE Gas [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity	300
Total Funded Debt to Total Capitalization Ratio	0.44
Total Funded Debt to Total Capitalization Ratio Denominator	1
Unsecured Revolving Facility 4 [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity	1,800
Unsecured Revolving Facility 4 [Member] | DTE Energy [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity	1,200
Unsecured Revolving Facility 4 [Member] | DTE Electric [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity	300
Unsecured Revolving Facility 4 [Member] | DTE Gas [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity	$ 300

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Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Comprehensive Income [Policy Text Block]

Comprehensive Income

Comprehensive income is the change in common shareholders’ equity during a period from transactions and events from non-owner sources, including net income. As shown in the following tables, amounts recorded to accumulated other comprehensive loss for the three and six months ended June 30, 2013 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 transition amounts related to pension and other postretirement benefit plans, and foreign currency translation adjustments.

Intangible Assets

Emission allowances and renewable energy credits are charged to expense, using average cost, as the allowances and credits are consumed in the operation of the business. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 3 to 28 years.

Income Tax [Policy Text Block]

Income Taxes

The Company's effective tax rate from continuing operations for the three months ended June 30, 2013 was 29 percent as compared to 32 percent for the three months ended June 30, 2012. The Company's effective tax rate from continuing operations for the six months ended June 30, 2013 was 30 percent as compared to 32 percent for the six months ended June 30, 2012. The decrease in the effective tax rate in 2013 is due primarily to higher production tax credits.

The Company had $3 million of unrecognized tax benefits at June 30, 2013, that, if recognized, would favorably impact its effective tax rate. The Company believes that it is possible that there will be a decrease in the unrecognized tax benefits of up to $1 million in the next twelve months.

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Consolidated Statements of Financial Position (Unaudited) (Parenthetical) (Parentheticals) (USD $) In Millions, except Share data, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Allowance for doubtful accounts	$ 63	$ 62
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	400,000,000	400,000,000
Common stock, shares issued	174,960,000	172,351,680
Common stock, shares outstanding	174,960,000	172,351,680

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Consolidated Statements of Changes in Equity (Unaudited) (USD $) In Millions, except Share data	Total	Common Stock	Retained Earnings	Accumulated Other Comprehensive Loss	Non-controlling Interest	Stockholders' Equity, Total [Member]
Beginning Balance at Dec. 31, 2012	$ 7,411	$ 3,587	$ 3,944	$ (158)	$ 38	$ 7,411
Beginning Balance, shares at Dec. 31, 2012	172,351,680	172,352,000
Net Income	342		339			342
Net Income (Loss) Attributable to Noncontrolling Interest	3				3
Dividends declared on common stock			(338)			(338)
Stock Issued During Period, Shares, New Issues		296,000
Issuance of common stock, value	3,762	19				19
Contribution of Common Stock to Pension Plan Shares	753,579	1,504,000
Contribution of Common Stock to Pension Plan	100	100				100
Foreign currency translation, net of tax	(2)			(2)		(2)
Benefit obligations, net of tax	5			5		5
Stock-based compensation, distributions to noncontrolling interests and other, shares		808,000
Stock-based compensation, distributions to noncontrolling interests and other		56				50
Stockholders' Equity, Other			0
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders					(6)
Ending Balance at Jun. 30, 2013	$ 7,587	$ 3,762	$ 3,945	$ (155)	$ 35	$ 7,587
Ending Balance, shares at Jun. 30, 2013	174,960,000	174,960,000

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Fair Value (Notes)

6 Months Ended

Jun. 30, 2013

Fair Value Disclosures [Abstract]

FAIR VALUE

FAIR VALUE

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The Company makes certain assumptions it believes that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and its counterparties is incorporated in the valuation of assets and liabilities through the use of credit reserves, the impact of which was immaterial at June 30, 2013 and December 31, 2012. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

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

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

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

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

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2013 and December 31, 2012:

	June 30, 2013															December 31, 2012
	Level 1			Level 2			Level 3			Netting (a)			Net Balance			Level 1			Level 2			Level 3			Netting (a)			Net Balance
	(In millions)
Assets:
Cash equivalents (b)	$	—		$	112		$	—		$	—		$	112		$	—		$	123		$	—		$	—		$	123
Nuclear decommissioning trusts	749			331			—			—			1,080			694			343			—			—			1,037
Other investments (c) (d)	72			47			—			—			119			66			44			—			—			110
Derivative assets:
Commodity Contracts:
Natural Gas	365			107			32			(490		)	14			555			66			24			(605		)	40
Electricity	—			219			98			(220		)	97			—			226			134			(258		)	102
Other	45			8			2			(49		)	6			6			3			2			(6		)	5
Total derivative assets	410			334			132			(759		)	117			561			295			160			(869		)	147
Total	$	1,231		$	824		$	132		$	(759	)	$	1,428		$	1,321		$	805		$	160		$	(869	)	$	1,417
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(1	)	$	—		$	—		$	(1	)	$	—		$	—		$	—		$	—		$	—
Interest rate contracts	—			—			—			—			—			—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(362		)	(86		)	(62		)	469			(41		)	(526		)	(73		)	(62		)	605			(56		)
Electricity	—			(221		)	(86		)	247			(60		)	—			(240		)	(111		)	258			(93		)
Other	(47		)	(5		)	—			48			(4		)	(6		)	(1		)	—			6			(1		)
Total derivative liabilities	(409		)	(313		)	(148		)	764			(106		)	(532		)	(315		)	(173		)	869			(151		)
Total	$	(409	)	$	(313	)	$	(148	)	$	764		$	(106	)	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)
Net Assets (Liabilities) at the end of the period	$	822		$	511		$	(16	)	$	5		$	1,322		$	789		$	490		$	(13	)	$	—		$	1,266
Assets:
Current	$	379		$	389		$	101		$	(667	)	$	202		$	493		$	372		$	120		$	(754	)	$	231
Noncurrent (e)	852			435			31			(92		)	1,226			828			433			40			(115		)	1,186
Total Assets	$	1,231		$	824		$	132		$	(759	)	$	1,428		$	1,321		$	805		$	160		$	(869	)	$	1,417
Liabilities:
Current	$	(368	)	$	(263	)	$	(119	)	$	660		$	(90	)	$	(466	)	$	(269	)	$	(144	)	$	754		$	(125	)
Noncurrent	(41		)	(50		)	(29		)	104			(16		)	(66		)	(46		)	(29		)	115			(26		)
Total Liabilities	$	(409	)	$	(313	)	$	(148	)	$	764		$	(106	)	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)
Net Assets (Liabilities) at the end of the period	$	822		$	511		$	(16	)	$	5		$	1,322		$	789		$	490		$	(13	)	$	—		$	1,266

_______________________________________

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

(b) At June 30, 2013, available-for-sale securities of $112 million included $96 million and $16 million of cash equivalents included in Restricted cash and Other investments, respectively, on the Consolidated Statements of Financial Position. At December 31, 2012, available-for-sale securities of $123 million, included $109 million and $14 million of cash equivalents included in Restricted cash and Other investments, respectively, on the Consolidated Statements of Financial Position.

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

(d) Available-for-sale equity securities of $6 million at June 30, 2013 and $5 million at December 31, 2012, are included in Other investments on the Consolidated Statements of Financial Position.

(e) Includes $119 million and $110 million at June 30, 2013 and December 31, 2012, respectively, of Other investments that are included in the Consolidated Statements of Financial Position in Other investments.

Cash Equivalents

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

Nuclear Decommissioning Trusts and Other Investments

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

Derivative Assets and Liabilities

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

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the three months and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30, 2013												Three Months Ended June 30, 2012
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of March 31	$	(34	)	$	(9	)	$	2		$	(41	)	$	6		$	25		$	6		$	37
Transfers into Level 3	—			—			—			—			1			—			—			1
Transfers out of Level 3	—			—			—			—			—			—			—			—
Total gains (losses):
Included in earnings	(2		)	18			(1		)	15			(1		)	56			(3		)	52
Recorded in regulatory assets/liabilities	—			—			3			3			—			—			4			4
Purchases, issuances and settlements:
Settlements	6			3			(2		)	7			(4		)	(31		)	(2		)	(37		)
Net Assets (Liabilities) as of June 30	$	(30	)	$	12		$	2		$	(16	)	$	2		$	50		$	5		$	57
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 June 30, 2013 and 2012 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(1	)	$	33		$	(1	)	$	31		$	(2	)	$	38		$	(3	)	$	33

	Six Months Ended June 30, 2013												Six Months Ended June 30, 2012
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of December 31	$	(38	)	$	23		$	2		$	(13	)	$	6		$	32		$	6		$	44
Transfers into Level 3	—			—			—			—			1			28			—			29
Transfers out of Level 3	(2		)	—			—			(2		)	(2		)	—			—			(2		)
Total gains (losses):
Included in earnings	(10		)	26			(1		)	15			6			41			(2		)	45
Recorded in regulatory assets/liabilities	—			—			4			4			—			—			5			5
Purchases, issuances and settlements:
Purchases	—			1			—			1			—			—			—			—
Settlements	20			(38		)	(3		)	(21		)	(9		)	(51		)	(4		)	(64		)
Net Assets (Liabilities) as of June 30	$	(30	)	$	12		$	2		$	(16	)	$	2		$	50		$	5		$	57
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 June 30, 2013 and 2012 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(6	)	$	27		$	(1	)	$	20		$	4		$	38		$	(2	)	$	40

Derivatives are transferred between levels primarily due to changes in the source data used to construct price curves as a result of changes in market liquidity. Transfers in and transfers out are reflected as if they had occurred at the beginning of the period. The following table shows transfers between the levels of the fair value hierarchy for the three months and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30, 2013					Three Months Ended June 30, 2012
	Level 1	Level 2		Level 3		Level 1	Level 2		Level 3
	(In millions)
Transfers into Level 1 from	$ N/A	$	—	$	—	$ N/A	$	—	$	—
Transfers into Level 2 from	—	N/A		—		—	N/A		—
Transfers into Level 3 from	—	—		N/A		—	1		N/A

	Six Months Ended June 30, 2013					Six Months Ended June 30, 2012
	Level 1	Level 2		Level 3		Level 1	Level 2		Level 3
	(In millions)
Transfers into Level 1 from	$ N/A	$	—	$	—	$ N/A	$	—	$	—
Transfers into Level 2 from	—	N/A		2		—	N/A		2
Transfers into Level 3 from	—	—		N/A		—	29		N/A

The following table presents the unobservable inputs related to Level 3 assets and liabilities as of June 30, 2013:

	June 30, 2013
Commodity Contracts	Derivative Assets		Derivative Liabilities			Valuation Techniques	Unobservable Input	Range							Weighted Average
	(In millions)
Natural Gas	$	32	$	(62	)	Discounted Cash Flow	Forward basis price (per MMBtu)	$	(2.63	)	—	$	0.54	/MMBtu	$	0.01	/MMBtu
Electricity	$	98	$	(86	)	Discounted Cash Flow	Forward basis price (per MWh)	$	(8	)	—	$	17	/MWh	$	3	/MWh

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

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

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

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

Fair Value of Financial Instruments

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

The following table presents the carrying amount and fair value of financial instruments as of June 30, 2013 and December 31, 2012:

	June 30, 2013								December 31, 2012
	Carrying		Fair Value						Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Amount		Level 1		Level 2		Level 3
	(In millions)
Notes receivable, excluding capital leases	$	36	$	—	$	—	$	36	$	39	$	—	$	—	$	39
Dividends payable	229		229		—		—		107		107		—		—
Short-term borrowings	216		—		216		—		240		—		240		—
Long-term debt	7,671		487		6,556		1,008		7,813		507		7,453		933

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

Nuclear Decommissioning Trust Funds

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

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

	June 30, 2013		December 31, 2012
	(In millions)
Fermi 2	$	1,063	$	1,021
Fermi 1	3		3
Low level radioactive waste	14		13
Total	$	1,080	$	1,037

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(In millions)
Realized gains	$	11		$	8		$	19		$	14
Realized losses	$	(7	)	$	(7	)	$	(14	)	$	(11	)
Proceeds from sales of securities	$	15		$	25		$	27		$	36

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:

	June 30, 2013				December 31, 2012
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
	(In millions)
Equity securities	$	679	$	161	$	631	$	122
Debt securities	390		15		399		27
Cash and cash equivalents	11		—		7		—
	$	1,080	$	176	$	1,037	$	149

The debt securities at both June 30, 2013 and December 31, 2012 had an average maturity of approximately 6 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. DTE Electric recognized $52 million and $44 million of unrealized losses as Regulatory assets at June 30, 2013 and December 31, 2012, respectively. Since the decommissioning of Fermi 1 is funded by DTE Electric rather than through a regulatory recovery mechanism, there is no corresponding regulatory asset treatment. Therefore, unrealized losses incurred by the Fermi 1 trust are recognized in earnings immediately. There were no unrealized losses recognized in the three and six months ended June 30, 2013 and June 30, 2012 for Fermi 1.

Other Securities

At June 30, 2013 and December 31, 2012, the securities were comprised primarily of money market and equity securities. During the three and six months ended June 30, 2013 and June 30, 2012, no amounts of unrealized losses on available-for-sale securities were reclassified out of other comprehensive income into net income for the periods. Gains related to trading securities held at June 30, 2013 and June 30, 2012 were $8 million and $5 million, respectively.

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Stock-Based Compensation (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 35	$ 23	$ 63	$ 40
Tax benefit	14	9	25	15
Stock-based compensation cost capitalized in property, plant and equipment	$ 2	$ 1	$ 4	$ 2

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Organization and Basis of Presentation (Notes)

6 Months Ended

Jun. 30, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

ORGANIZATION AND BASIS OF PRESENTATION

Corporate Structure

DTE Energy owns the following businesses:

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

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

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

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

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

Basis of Presentation

These Consolidated Financial Statements should be read in conjunction with the Notes to Consolidated Financial Statements included in the 2012 Annual Report on Form 10-K.

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.

The Consolidated Financial Statements are unaudited, but in the Company's opinion include all adjustments necessary to a fair statement of the results for the interim periods. All adjustments are of a normal recurring nature, except as otherwise disclosed in these Consolidated Financial Statements and Notes to Consolidated Financial Statements. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2013.

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

Principles of Consolidation

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

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

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

The Company has variable interests in VIEs through certain of its long-term purchase contracts. As of June 30, 2013, the carrying amount of assets and liabilities in the Consolidated Statements of Financial Position that relate to its variable interests under long-term purchase contracts are predominately related to working capital accounts and generally represent the amounts owed by the Company for the deliveries associated with the current billing cycle under the contracts. The Company has not provided any form of financial support associated with these long-term contracts. There is no significant potential exposure to loss as a result of its variable interests through these long-term purchase contracts.

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

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

The following table summarizes the major balance sheet items for consolidated VIEs as of June 30, 2013 and December 31, 2012. All amounts included in the tables are considered restricted given they are 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.

	June 30, 2013						December 31, 2012
	Securitization		Other		Total		Securitization		Other		Total
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	8	$	8	$	—	$	10	$	10
Restricted cash	90		6		96		102		7		109
Accounts receivable	39		16		55		34		7		41
Inventories	—		91		91		—		141		141
Other current assets	—		1		1		—		1		1
Property, plant and equipment	—		103		103		—		93		93
Securitized regulatory assets	326		—		326		413		—		413
Other assets	6		9		15		7		11		18
	$	461	$	234	$	695	$	556	$	270	$	826
LIABILITIES
Accounts payable and accrued current liabilities	$	9	$	33	$	42	$	11	$	14	$	25
Current portion long-term debt, including capital leases	189		8		197		177		8		185
Current regulatory liabilities	45		—		45		50		—		50
Other current liabilities	—		3		3		—		4		4
Mortgage bonds, notes and other	—		23		23		—		25		25
Securitization bonds	201		—		201		302		—		302
Capital lease obligations	—		8		8		—		11		11
Other long-term liabilities	8		2		10		7		2		9
	$	452	$	77	$	529	$	547	$	64	$	611

Amounts for non-consolidated VIEs as of June 30, 2013 and December 31, 2012 are as follows:

	June 30, 2013		December 31, 2012
	(In millions)
Other investments	$	136	$	130
Notes receivable	6		6

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Organization and Basis of Presentation (Details 1) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Variable Interest Entity [Line Items]
Notes receivable	$ 106	$ 112
Unconsolidated Variable Interest Entity [Member]
Variable Interest Entity [Line Items]
Other investments	136	130
Notes receivable	$ 6	$ 6

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Fair Value (Tables)

6 Months Ended

Jun. 30, 2013

Fair Value Disclosures [Abstract]

Assets and liabilities measured and recorded at fair value on a recurring basis

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2013 and December 31, 2012:

	June 30, 2013															December 31, 2012
	Level 1			Level 2			Level 3			Netting (a)			Net Balance			Level 1			Level 2			Level 3			Netting (a)			Net Balance
	(In millions)
Assets:
Cash equivalents (b)	$	—		$	112		$	—		$	—		$	112		$	—		$	123		$	—		$	—		$	123
Nuclear decommissioning trusts	749			331			—			—			1,080			694			343			—			—			1,037
Other investments (c) (d)	72			47			—			—			119			66			44			—			—			110
Derivative assets:
Commodity Contracts:
Natural Gas	365			107			32			(490		)	14			555			66			24			(605		)	40
Electricity	—			219			98			(220		)	97			—			226			134			(258		)	102
Other	45			8			2			(49		)	6			6			3			2			(6		)	5
Total derivative assets	410			334			132			(759		)	117			561			295			160			(869		)	147
Total	$	1,231		$	824		$	132		$	(759	)	$	1,428		$	1,321		$	805		$	160		$	(869	)	$	1,417
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(1	)	$	—		$	—		$	(1	)	$	—		$	—		$	—		$	—		$	—
Interest rate contracts	—			—			—			—			—			—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(362		)	(86		)	(62		)	469			(41		)	(526		)	(73		)	(62		)	605			(56		)
Electricity	—			(221		)	(86		)	247			(60		)	—			(240		)	(111		)	258			(93		)
Other	(47		)	(5		)	—			48			(4		)	(6		)	(1		)	—			6			(1		)
Total derivative liabilities	(409		)	(313		)	(148		)	764			(106		)	(532		)	(315		)	(173		)	869			(151		)
Total	$	(409	)	$	(313	)	$	(148	)	$	764		$	(106	)	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)
Net Assets (Liabilities) at the end of the period	$	822		$	511		$	(16	)	$	5		$	1,322		$	789		$	490		$	(13	)	$	—		$	1,266
Assets:
Current	$	379		$	389		$	101		$	(667	)	$	202		$	493		$	372		$	120		$	(754	)	$	231
Noncurrent (e)	852			435			31			(92		)	1,226			828			433			40			(115		)	1,186
Total Assets	$	1,231		$	824		$	132		$	(759	)	$	1,428		$	1,321		$	805		$	160		$	(869	)	$	1,417
Liabilities:
Current	$	(368	)	$	(263	)	$	(119	)	$	660		$	(90	)	$	(466	)	$	(269	)	$	(144	)	$	754		$	(125	)
Noncurrent	(41		)	(50		)	(29		)	104			(16		)	(66		)	(46		)	(29		)	115			(26		)
Total Liabilities	$	(409	)	$	(313	)	$	(148	)	$	764		$	(106	)	$	(532	)	$	(315	)	$	(173	)	$	869		$	(151	)
Net Assets (Liabilities) at the end of the period	$	822		$	511		$	(16	)	$	5		$	1,322		$	789		$	490		$	(13	)	$	—		$	1,266

_______________________________________

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

(b) At June 30, 2013, available-for-sale securities of $112 million included $96 million and $16 million of cash equivalents included in Restricted cash and Other investments, respectively, on the Consolidated Statements of Financial Position. At December 31, 2012, available-for-sale securities of $123 million, included $109 million and $14 million of cash equivalents included in Restricted cash and Other investments, respectively, on the Consolidated Statements of Financial Position.

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

(d) Available-for-sale equity securities of $6 million at June 30, 2013 and $5 million at December 31, 2012, are included in Other investments on the Consolidated Statements of Financial Position.

(e) Includes $119 million and $110 million at June 30, 2013 and December 31, 2012, respectively, of Other investments that are included in the Consolidated Statements of Financial Position in Other investments.

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the three months and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30, 2013												Three Months Ended June 30, 2012
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of March 31	$	(34	)	$	(9	)	$	2		$	(41	)	$	6		$	25		$	6		$	37
Transfers into Level 3	—			—			—			—			1			—			—			1
Transfers out of Level 3	—			—			—			—			—			—			—			—
Total gains (losses):
Included in earnings	(2		)	18			(1		)	15			(1		)	56			(3		)	52
Recorded in regulatory assets/liabilities	—			—			3			3			—			—			4			4
Purchases, issuances and settlements:
Settlements	6			3			(2		)	7			(4		)	(31		)	(2		)	(37		)
Net Assets (Liabilities) as of June 30	$	(30	)	$	12		$	2		$	(16	)	$	2		$	50		$	5		$	57
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 June 30, 2013 and 2012 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(1	)	$	33		$	(1	)	$	31		$	(2	)	$	38		$	(3	)	$	33

	Six Months Ended June 30, 2013												Six Months Ended June 30, 2012
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of December 31	$	(38	)	$	23		$	2		$	(13	)	$	6		$	32		$	6		$	44
Transfers into Level 3	—			—			—			—			1			28			—			29
Transfers out of Level 3	(2		)	—			—			(2		)	(2		)	—			—			(2		)
Total gains (losses):
Included in earnings	(10		)	26			(1		)	15			6			41			(2		)	45
Recorded in regulatory assets/liabilities	—			—			4			4			—			—			5			5
Purchases, issuances and settlements:
Purchases	—			1			—			1			—			—			—			—
Settlements	20			(38		)	(3		)	(21		)	(9		)	(51		)	(4		)	(64		)
Net Assets (Liabilities) as of June 30	$	(30	)	$	12		$	2		$	(16	)	$	2		$	50		$	5		$	57
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 June 30, 2013 and 2012 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(6	)	$	27		$	(1	)	$	20		$	4		$	38		$	(2	)	$	40

Transfers Between Level 1 Level 2 and Level 3 [Table Text Block]

The following table shows transfers between the levels of the fair value hierarchy for the three months and six months ended June 30, 2013 and 2012:

	Three Months Ended June 30, 2013					Three Months Ended June 30, 2012
	Level 1	Level 2		Level 3		Level 1	Level 2		Level 3
	(In millions)
Transfers into Level 1 from	$ N/A	$	—	$	—	$ N/A	$	—	$	—
Transfers into Level 2 from	—	N/A		—		—	N/A		—
Transfers into Level 3 from	—	—		N/A		—	1		N/A

	Six Months Ended June 30, 2013					Six Months Ended June 30, 2012
	Level 1	Level 2		Level 3		Level 1	Level 2		Level 3
	(In millions)
Transfers into Level 1 from	$ N/A	$	—	$	—	$ N/A	$	—	$	—
Transfers into Level 2 from	—	N/A		2		—	N/A		2
Transfers into Level 3 from	—	—		N/A		—	29		N/A

Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Table Text Block]

The following table presents the unobservable inputs related to Level 3 assets and liabilities as of June 30, 2013:

	June 30, 2013
Commodity Contracts	Derivative Assets		Derivative Liabilities			Valuation Techniques	Unobservable Input	Range							Weighted Average
	(In millions)
Natural Gas	$	32	$	(62	)	Discounted Cash Flow	Forward basis price (per MMBtu)	$	(2.63	)	—	$	0.54	/MMBtu	$	0.01	/MMBtu
Electricity	$	98	$	(86	)	Discounted Cash Flow	Forward basis price (per MWh)	$	(8	)	—	$	17	/MWh	$	3	/MWh

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

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

Fair Value of Financial Instruments [Table Text Block]

The following table presents the carrying amount and fair value of financial instruments as of June 30, 2013 and December 31, 2012:

	June 30, 2013								December 31, 2012
	Carrying		Fair Value						Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Amount		Level 1		Level 2		Level 3
	(In millions)
Notes receivable, excluding capital leases	$	36	$	—	$	—	$	36	$	39	$	—	$	—	$	39
Dividends payable	229		229		—		—		107		107		—		—
Short-term borrowings	216		—		216		—		240		—		240		—
Long-term debt	7,671		487		6,556		1,008		7,813		507		7,453		933

Fair Value of Nuclear Decommissioning Trust Fund Assets Text Block [Table]

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

	June 30, 2013		December 31, 2012
	(In millions)
Fermi 2	$	1,063	$	1,021
Fermi 1	3		3
Low level radioactive waste	14		13
Total	$	1,080	$	1,037

Schedule of Realized Gain (Loss) [Table Text Block]

The following table sets forth the gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds:

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(In millions)
Realized gains	$	11		$	8		$	19		$	14
Realized losses	$	(7	)	$	(7	)	$	(14	)	$	(11	)
Proceeds from sales of securities	$	15		$	25		$	27		$	36

Fair Value and Unrealized Gains for Nuclear Decommissioning Trust Fund Table [Table] [Table Text Block]

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

	June 30, 2013				December 31, 2012
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
	(In millions)
Equity securities	$	679	$	161	$	631	$	122
Debt securities	390		15		399		27
Cash and cash equivalents	11		—		7		—
	$	1,080	$	176	$	1,037	$	149

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2013

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

A reconciliation of both calculations is presented in the following table for the three months and six months ended June 30:

	Three Months Ended					Six Months Ended
	June 30					June 30
	2013			2012		2013		2012
	(In millions, except per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	105		$	146	$	339	$	302
Average number of common shares outstanding	174			170		174		170
Weighted average net restricted shares outstanding	1			1		1		1
Dividends declared — common shares	$	114		$	100	$	222	$	200
Dividends declared — net restricted shares	1			1		—		1
Total distributed earnings	$	115		$	101	$	222	$	201
Net income less distributed earnings	$	(10	)	$	45	$	117	$	101
Distributed (dividends per common share)	$	0.66		$	0.59	$	1.28	$	1.18
Undistributed	(0.06		)	0.27		0.66		0.59
Total Basic Earnings per Common Share	$	0.60		$	0.86	$	1.94	$	1.77
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	105		$	146	$	339	$	302
Average number of common shares outstanding	175			170		174		170
Average incremental shares from assumed exercise of options	—			1		—		1
Common shares for dilutive calculation	175			171		174		171
Weighted average net restricted shares outstanding	1			1		1		1
Dividends declared — common shares	$	114		$	100	$	222	$	200
Dividends declared — net restricted shares	1			1		—		1
Total distributed earnings	$	115		$	101	$	222	$	201
Net income less distributed earnings	$	(10	)	$	45	$	117	$	101
Distributed (dividends per common share)	$	0.66		$	0.59	$	1.28	$	1.18
Undistributed	(0.06		)	0.27		0.66		0.59
Total Diluted Earnings per Common Share	$	0.60		$	0.86	$	1.94	$	1.77

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Retirement Benefits and Trusteed Assets (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Service Cost	$ 25	$ 20	$ 49	$ 41
Defined Benefit Plan, Interest Cost	47	51	95	102
Defined Benefit Plan, Expected Return on Plan Assets	(66)	(61)	(133)	(122)
Defined Benefit Plan, Amortization of Gains (Losses)	50	43	101	85
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	0	0	0
Defined Benefit Plan Net Transition Liability			0	0
Defined Benefit Plan, Special Termination Benefits			0	2
Defined Benefit Plan, Net Periodic Benefit Cost	56	53	112	108
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Service Cost	12	18	28	36
Defined Benefit Plan, Interest Cost	21	31	45	61
Defined Benefit Plan, Expected Return on Plan Assets	(27)	(23)	(54)	(46)
Defined Benefit Plan, Amortization of Gains (Losses)	15	20	32	39
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(36)	(7)	(59)	(14)
Defined Benefit Plan Net Transition Liability			0	1
Defined Benefit Plan, Special Termination Benefits			0	0
Defined Benefit Plan, Net Periodic Benefit Cost	$ (15)	$ 39	$ (8)	$ 77

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Supplemental Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2013

Supplemental Cash Flow Elements [Abstract]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

A detailed analysis of the changes in assets and liabilities that are reported in the Consolidated Statements of Cash Flows follows:

	Six Months Ended June 30,
	2013			2012
	(In millions)
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	70		$	120
Inventories	133			81
Accrued/prepaid pensions	(42		)	6
Accounts payable	(29		)	(4		)
Income taxes payable/receivable	(20		)	(39		)
Derivative assets and liabilities	(15		)	26
Postretirement obligation	(174		)	(142		)
Gas inventory equalization	73			65
Other assets	324			299
Other liabilities	(45		)	(112		)
	$	275		$	300

Schedule of Other Significant Noncash Transactions [Table Text Block]

Supplementary non-cash information is as follows:

	Six Months Ended June 30,
	2013			2012
	(In millions)
Common stock issued for employee benefit and compensation plans	$	165		$	129
Change in capital expenditures not paid	$	(17	)	$	(55	)

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Commitments and Contingencies (Details Textuals) (USD $)	6 Months Ended	108 Months Ended		6 Months Ended		6 Months Ended		6 Months Ended
	Jun. 30, 2013 kWh dte_instances facilities	Jun. 27, 2022	Jul. 18, 2013	Jun. 30, 2013 Electric [Member] facilities dte_instances	Dec. 31, 2012 Electric [Member]	Jun. 30, 2013 Gas [Member] facilities	Dec. 31, 2012 Gas [Member]	Jun. 30, 2013 Synthetic Fuel [Member]	Jun. 30, 2013 Emissions [Member]
Loss Contingencies [Line Items]
Environmental Capital Expenditures Through Current Year				$ 1,900,000,000
Environmental Capital Expenditures in Current Year				335,000,000
Environmental Capital Expenditures In Future Years				1,800,000,000
EPA is Alleging Detroit Edison Power Plants Violated New Source Performance Standards				5
Number of NOVs/FOVs currently being discussed with the EPA	2
Sierra Club is Alleging DTE Electric Coal Fired Power Plants Violated the Clean Air Act	4
Exceedances of Opacity Standard				1,499
2004 EPA proposed compliance timeline in years		8 years
Number of Former MGP Sites				3		15
Accrued for remediation related to the sites				9,000,000	9,000,000	30,000,000	29,000,000
Number of Options to Regulate Coal Ash Residue				2
Period Gas Utility Can Amortize MGP Costs						10 years
Number of NOVs	2
Possible Environmental Capital Expenditures to Comply with Requirements	6,000,000
EPA Sulfur Dioxide Ambient Air Quality Standard	1
Waiting Period of Policy	P12W
Insurance Coverage for Extra ExpenseWhen to Necessitate Power Plant when Unavailable	490,000,000
Period of Coverage of Policy for Extra Expenses	3 years
Primary Coverage	500,000,000
Coverage for Stabilization Decontamination Debris Removal Repair and Replacement of Property and Decommissioning	2,250,000,000
Combined Coverage Limit for Total Property Damage	2,750,000,000
Insurance Deductible for Nuclear Power Plant	1,000,000
Total Limit for Property Damage for Non-Nuclear Events	1,800,000,000
Limit for Property Damage for Non-Nuclear Events Aggregate of Extra Expenses	327,000,000
Limit for Property Damage for Non-Nuclear Events Aggregate of Extra Expenses of Period	2 years
Time Period for TRIA Insurance After the First Loss from Terrorism	1 year
NEIL Policies Against Terrorism Loss	3,200,000,000
Amount per Event Loss Associated with Nuclear Power Plants	33,000,000
Time Period for Maximum Assessments for Losses Associated to Events at Nuclear Plants	1 year
Maintenance of Public Liability Insurance for Nuclear Power Plants	375,000,000
Aggregate Limit of Liabilities Arises From Terrorist Act Outside Scope of Trials Subject to One Industry	300,000,000
Deferred Premium Charged Leviied Against Each Licensed Nuclear Facility	117,500,000
Limit Deferred Premium Charges Per Year	17,500,000
Company Obligated to Pay DOE Fee of Fermi 2 Electricity Generated and Sold	1
Settlement Provided for Delay-Related Costs	48,000,000
Days Obligations will Survive After Expiration of All Applicable Statutes of Limiations								90 days	90 days
Guarantor Obligations, Maximum Exposure, Undiscounted								1,200,000,000	103,000,000
Guarantee Obligations Maximum Exposure One	61,000,000
Performance Bonds Outstanding	41,000,000
Long-term Purchase Commitment, Amount	4,400,000,000
estimated future capital expenditures for current year	2,200,000,000
Bankruptcy Claims, Accounts Receivable under Review by Management			$ 18,000,000

XML

Financial and Other Derivative Instruments Financial and Other Derivative Instruments (Details 1) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Netting Offsets of Derivative Assets and Liabilities [Line Items]
Fair Value Gross Amounts of Recognized Assets	$ 876	$ 1,016
Gross Amounts Offset in the Statements of Financial Position	(759)	(869)
Net Amounts of Assets Presented in the Statements of Financial Position	117	147
Fair Value Gross Amounts of Recognized Liabilities	(870)	(1,020)
Gross Amounts Offset in the Statement of Financial Position	764	869
Net Amounts of Liabilities Presented in the Statements of Financial Position	(106)	(151)
Natural Gas [Member]
Netting Offsets of Derivative Assets and Liabilities [Line Items]
Fair Value Gross Amounts of Recognized Assets	504	645
Gross Amounts Offset in the Statements of Financial Position	(490)	(605)
Net Amounts of Assets Presented in the Statements of Financial Position	14	40
Fair Value Gross Amounts of Recognized Liabilities	(510)	(661)
Gross Amounts Offset in the Statement of Financial Position	469	605
Net Amounts of Liabilities Presented in the Statements of Financial Position	(41)	(56)
Electricity [Member]
Netting Offsets of Derivative Assets and Liabilities [Line Items]
Fair Value Gross Amounts of Recognized Assets	317	360
Gross Amounts Offset in the Statements of Financial Position	(220)	(258)
Net Amounts of Assets Presented in the Statements of Financial Position	97	102
Fair Value Gross Amounts of Recognized Liabilities	(307)	(351)
Gross Amounts Offset in the Statement of Financial Position	247	258
Net Amounts of Liabilities Presented in the Statements of Financial Position	(60)	(93)
Other Contract [Member]
Netting Offsets of Derivative Assets and Liabilities [Line Items]
Fair Value Gross Amounts of Recognized Assets	55	11
Gross Amounts Offset in the Statements of Financial Position	(49)	(6)
Net Amounts of Assets Presented in the Statements of Financial Position	6	5
Fair Value Gross Amounts of Recognized Liabilities	(52)	(7)
Gross Amounts Offset in the Statement of Financial Position	48	6
Net Amounts of Liabilities Presented in the Statements of Financial Position	(4)	(1)
Foreign currency exchange contracts [Member]
Netting Offsets of Derivative Assets and Liabilities [Line Items]
Fair Value Gross Amounts of Recognized Liabilities	(1)	0
Gross Amounts Offset in the Statement of Financial Position	0	0
Net Amounts of Liabilities Presented in the Statements of Financial Position	(1)	0
Interest rate contracts [Member]
Netting Offsets of Derivative Assets and Liabilities [Line Items]
Fair Value Gross Amounts of Recognized Liabilities	0	(1)
Gross Amounts Offset in the Statement of Financial Position	0	0
Net Amounts of Liabilities Presented in the Statements of Financial Position	$ 0	$ (1)

XML

Fair Value (Details 5) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	$ 1,080	$ 1,037
Fermi 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	1,063	1,021
Fermi 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	3	3
Low level radioactive waste [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	$ 14	$ 13

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Fair Value (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	$ 112	$ 123
Assets [Abstract]
Nuclear decommissioning trusts	1,080	1,037
Other investments	119	110
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	876	1,016
Assets, Fair Value Disclosure, Recurring	1,428	1,417
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(870)	(1,020)
Derivative Liabilities	(106)	(151)
Derivative Assets (Liabilities), at Fair Value, Net	1,322	1,266
Derivative Assets, Current	90	108
Derivative Assets, Noncurrent	27	39
Derivative Liabilities, Current	90	125
Derivative Liabilities, Noncurrent	16	26
Current Asset [Member]
Derivative liabilities [Abstract]
Derivative Assets, Current	202	231
Non Current Asset [Member]
Derivative liabilities [Abstract]
Derivative Assets, Noncurrent	1,226	1,186
Current Liability [Member]
Derivative liabilities [Abstract]
Derivative Liabilities, Current	(90)	(125)
Noncurrent Liability [Member]
Derivative liabilities [Abstract]
Derivative Liabilities, Noncurrent	(16)	(26)
Interest rate contracts [Member]
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	(1)
Natural Gas [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	14	40
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(41)	(56)
Electricity [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	97	102
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(60)	(93)
Other [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	6	5
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(4)	(1)
Total derivative assets [Member]
Derivative assets [Abstract]
Derivative Assets	117	147
Foreign currency exchange contracts [Member]
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(1)	0
Total derivative liabilities [Member]
Derivative liabilities [Abstract]
Derivative Liabilities	(106)	(151)
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	0	0
Assets [Abstract]
Nuclear decommissioning trusts	749	694
Other investments	72	66
Derivative assets [Abstract]
Assets, Fair Value Disclosure, Recurring	1,231	1,321
Derivative liabilities [Abstract]
Derivative Liabilities	(409)	(532)
Derivative Assets (Liabilities), at Fair Value, Net	822	789
Fair Value, Inputs, Level 1 [Member] | Current Asset [Member]
Derivative liabilities [Abstract]
Derivative Assets, Current	379	493
Fair Value, Inputs, Level 1 [Member] | Non Current Asset [Member]
Derivative liabilities [Abstract]
Derivative Assets, Noncurrent	852	828
Fair Value, Inputs, Level 1 [Member] | Current Liability [Member]
Derivative liabilities [Abstract]
Derivative Liabilities, Current	(368)	(466)
Fair Value, Inputs, Level 1 [Member] | Noncurrent Liability [Member]
Derivative liabilities [Abstract]
Derivative Liabilities, Noncurrent	(41)	(66)
Fair Value, Inputs, Level 1 [Member] | Interest rate contracts [Member]
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Natural Gas [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	365	555
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(362)	(526)
Fair Value, Inputs, Level 1 [Member] | Electricity [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Other [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	45	6
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(47)	(6)
Fair Value, Inputs, Level 1 [Member] | Total derivative assets [Member]
Derivative assets [Abstract]
Derivative Assets	410	561
Fair Value, Inputs, Level 1 [Member] | Foreign currency exchange contracts [Member]
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Total derivative liabilities [Member]
Derivative liabilities [Abstract]
Derivative Liabilities	(409)	(532)
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	112	123
Assets [Abstract]
Nuclear decommissioning trusts	331	343
Other investments	47	44
Derivative assets [Abstract]
Assets, Fair Value Disclosure, Recurring	824	805
Derivative liabilities [Abstract]
Derivative Liabilities	(313)	(315)
Derivative Assets (Liabilities), at Fair Value, Net	511	490
Fair Value, Inputs, Level 2 [Member] | Current Asset [Member]
Derivative liabilities [Abstract]
Derivative Assets, Current	389	372
Fair Value, Inputs, Level 2 [Member] | Non Current Asset [Member]
Derivative liabilities [Abstract]
Derivative Assets, Noncurrent	435	433
Fair Value, Inputs, Level 2 [Member] | Current Liability [Member]
Derivative liabilities [Abstract]
Derivative Liabilities, Current	(263)	(269)
Fair Value, Inputs, Level 2 [Member] | Noncurrent Liability [Member]
Derivative liabilities [Abstract]
Derivative Liabilities, Noncurrent	(50)	(46)
Fair Value, Inputs, Level 2 [Member] | Interest rate contracts [Member]
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	(1)
Fair Value, Inputs, Level 2 [Member] | Natural Gas [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	107	66
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(86)	(73)
Fair Value, Inputs, Level 2 [Member] | Electricity [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	219	226
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(221)	(240)
Fair Value, Inputs, Level 2 [Member] | Other [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	8	3
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(5)	(1)
Fair Value, Inputs, Level 2 [Member] | Total derivative assets [Member]
Derivative assets [Abstract]
Derivative Assets	334	295
Fair Value, Inputs, Level 2 [Member] | Foreign currency exchange contracts [Member]
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(1)	0
Fair Value, Inputs, Level 2 [Member] | Total derivative liabilities [Member]
Derivative liabilities [Abstract]
Derivative Liabilities	(313)	(315)
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	0	0
Assets [Abstract]
Nuclear decommissioning trusts	0	0
Other investments	0	0
Derivative assets [Abstract]
Assets, Fair Value Disclosure, Recurring	132	160
Derivative liabilities [Abstract]
Derivative Liabilities	(148)	(173)
Derivative Assets (Liabilities), at Fair Value, Net	(16)	(13)
Fair Value, Inputs, Level 3 [Member] | Current Asset [Member]
Derivative liabilities [Abstract]
Derivative Assets, Current	101	120
Fair Value, Inputs, Level 3 [Member] | Non Current Asset [Member]
Derivative liabilities [Abstract]
Derivative Assets, Noncurrent	31	40
Fair Value, Inputs, Level 3 [Member] | Current Liability [Member]
Derivative liabilities [Abstract]
Derivative Liabilities, Current	(119)	(144)
Fair Value, Inputs, Level 3 [Member] | Noncurrent Liability [Member]
Derivative liabilities [Abstract]
Derivative Liabilities, Noncurrent	(29)	(29)
Fair Value, Inputs, Level 3 [Member] | Interest rate contracts [Member]
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Natural Gas [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	32	24
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(62)	(62)
Fair Value, Inputs, Level 3 [Member] | Electricity [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	98	134
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(86)	(111)
Fair Value, Inputs, Level 3 [Member] | Other [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	2	2
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Total derivative assets [Member]
Derivative assets [Abstract]
Derivative Assets	132	160
Fair Value, Inputs, Level 3 [Member] | Foreign currency exchange contracts [Member]
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Total derivative liabilities [Member]
Derivative liabilities [Abstract]
Derivative Liabilities	(148)	(173)
Netting Adjustments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	0	0
Assets [Abstract]
Nuclear decommissioning trusts	0	0
Other investments	0	0
Derivative assets [Abstract]
Assets, Fair Value Disclosure, Recurring	(759)	(869)
Derivative liabilities [Abstract]
Derivative Liabilities	764	869
Derivative Assets (Liabilities), at Fair Value, Net	5	0
Netting Adjustments [Member] | Current Asset [Member]
Derivative liabilities [Abstract]
Derivative Assets, Current	(667)	(754)
Netting Adjustments [Member] | Non Current Asset [Member]
Derivative liabilities [Abstract]
Derivative Assets, Noncurrent	(92)	(115)
Netting Adjustments [Member] | Current Liability [Member]
Derivative liabilities [Abstract]
Derivative Liabilities, Current	660	754
Netting Adjustments [Member] | Noncurrent Liability [Member]
Derivative liabilities [Abstract]
Derivative Liabilities, Noncurrent	104	115
Netting Adjustments [Member] | Interest rate contracts [Member]
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Netting Adjustments [Member] | Natural Gas [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	(490)	(605)
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	469	605
Netting Adjustments [Member] | Electricity [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	(220)	(258)
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	247	258
Netting Adjustments [Member] | Other [Member]
Derivative assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	(49)	(6)
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	48	6
Netting Adjustments [Member] | Total derivative assets [Member]
Derivative assets [Abstract]
Derivative Assets	(759)	(869)
Netting Adjustments [Member] | Foreign currency exchange contracts [Member]
Derivative liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Netting Adjustments [Member] | Total derivative liabilities [Member]
Derivative liabilities [Abstract]
Derivative Liabilities	$ 764	$ 869

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Consolidated Statements of Comprehensive Income (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Statement of Income and Comprehensive Income [Abstract]
Net Income	$ 107	$ 147	$ 342	$ 305
Benefit obligations:
Benefit obligation, net of taxes of $1, $1, $2 and $3	2	3	5	6
Total Benefit obligations	2	3	5	6
Net unrealized gains (losses) on derivatives:
Gains during the period, net of taxes of $—, $—, $— and $—	0	0	0	1
Net unrealized gains (losses) on derivatives	0	0	0	1
Foreign currency translation, net of taxes of $(1), $-, $(1) and $-	(1)	(1)	(2)	0
Other Comprehensive income	1	2	3	7
Comprehensive income	108	149	345	312
Less: Comprehensive income attributable to noncontrolling interests	2	1	3	3
Comprehensive income attributable to DTE Energy Company	$ 106	$ 148	$ 342	$ 309

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Asset Retirement Obligations (Notes)

6 Months Ended

Jun. 30, 2013

Asset Retirement Obligation [Abstract]

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS

A reconciliation of the asset retirement obligations for the six months ended June 30, 2013 follows:

	(In millions)
Asset retirement obligations at December 31, 2012	$	1,719
Accretion	52
Revision in estimated cash flows	13
Asset retirement obligations at June 30, 2013	$	1,784

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Consolidated Statements of Financial Position (Unaudited) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Current Assets
Cash and cash equivalents	$ 46	$ 65
Restricted cash, principally Securitization	112	122
Accounts receivable (less allowance for doubtful accounts of $63 and $62, respectively)
Customer	1,314	1,336
Other	102	126
Inventories
Fuel and gas	378	527
Materials and supplies	249	234
Deferred income taxes	0	21
Derivative assets	90	108
Regulatory assets	90	182
Other	115	194
Total Current Assets	2,496	2,915
Investments
Nuclear decommissioning trust funds	1,080	1,037
Other	574	554
Total Investments	1,654	1,591
Property
Property, plant and equipment	24,356	23,631
Less accumulated depreciation, depletion and amortization	(9,166)	(8,947)
Property, plant and equipment, net	15,190	14,684
Other Assets
Goodwill	2,018	2,018
Regulatory assets	3,790	4,235
Securitized regulatory assets	326	413
Intangible Assets	138	135
Notes receivable	106	112
Derivative assets	27	39
Other	199	197
Total Noncurrent Assets	6,604	7,149
Total Assets	25,944	26,339
Current Liabilities
Accounts payable	808	848
Accrued interest	97	93
Dividends payable	229	107
Short-term borrowings	216	240
Current portion long-term debt, including capital leases	879	817
Derivative liabilities	90	125
Gas inventory equalization	73	0
Other	570	538
Total Current Liabilities	2,962	2,768
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	6,116	6,220
Securitization bonds	201	302
Junior subordinated debentures	480	480
Capital lease obligations	9	12
Total Long-Term Debt (net of current portion)	6,806	7,014
Other Liabilities
Deferred income taxes	3,280	3,191
Regulatory liabilities	954	1,031
Asset retirement obligations	1,784	1,719
Unamortized investment tax credit	51	56
Derivative liabilities	16	26
Accrued pension liability	1,355	1,498
Accrued postretirement liability	702	1,160
Nuclear decommissioning	164	159
Other	283	306
Total Noncurrent Liabilities	8,589	9,146
Equity
Common stock, without par value, 400,000,000 shares authorized, 174,960,000 and 172,351,680 shares issued and outstanding, respectively	3,762	3,587
Retained earnings	3,945	3,944
Accumulated other comprehensive loss	(155)	(158)
Total DTE Energy Company Equity	7,552	7,373
Noncontrolling interests	35	38
Total Equity	7,587	7,411
Total Liabilities and Equity	$ 25,944	$ 26,339

XML

Financial and Other Derivative Instruments (Details 4)	Jun. 30, 2013 dte.volumes
Natural Gas [Member]
Derivative [Line Items]
Volume of Commodity Contracts	574,820,998
Electricity [Member]
Derivative [Line Items]
Volume of Commodity Contracts	64,291,746
Foreign currency exchange contracts [Member]
Derivative [Line Items]
Volume of Commodity Contracts	34,772,009
FTR [Member]
Derivative [Line Items]
Volume of Commodity Contracts	16,224,782

XML

Consolidated Statements of Operations (Unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Operating Revenues	$ 2,225	$ 2,013	$ 4,741	$ 4,252
Operating Expenses
Fuel, purchased power and gas	940	697	1,964	1,586
Operation and maintenance	705	703	1,440	1,424
Depreciation, depletion and amortization	268	244	527	471
Taxes other than income	84	79	178	174
Asset (gains) and losses, reserves and impairments, net	5	(4)	(1)	(9)
Total operating expenses	2,002	1,719	4,108	3,646
Operating Income	223	294	633	606
Other (Income) and Deductions
Interest expense	112	109	221	222
Interest income	(3)	(3)	(5)	(5)
Other income	(46)	(41)	(90)	(78)
Other expenses	9	11	16	18
Total Other (Income) and Deductions	72	76	142	157
Income Before Income Taxes	151	218	491	449
Income Tax Expense	44	70	149	143
Income from Continuing Operations	107	148	342	306
Loss from Discontinued Operations, net of tax	0	(1)	0	(1)
Net Income	107	147	342	305
Less: Net Income Attributable to Noncontrolling Interests	2	1	3	3
Net Income Attributable to DTE Energy Company	$ 105	$ 146	$ 339	$ 302
Basic Earnings per Common Share
Net Income Attributable to DTE Energy Company	$ 0.60	$ 0.86	$ 1.94	$ 1.77
Income from continuing operations	$ 0.60	$ 0.87	$ 1.94	$ 1.78
Loss from discontinued operations, net of tax	$ 0.00	$ (0.01)	$ 0.00	$ (0.01)
Diluted Earnings per Common Share
Net Income Attributable to DTE Energy Company	$ 0.60	$ 0.86	$ 1.94	$ 1.77
Income from continuing operations	$ 0.60	$ 0.87	$ 1.94	$ 1.78
Loss from discontinued operations, net of tax	$ 0.00	$ (0.01)	$ 0.00	$ (0.01)
Weighted Average Common Shares Outstanding
Basic	174	170	174	170
Diluted	175	171	174	171
Dividends Declared per Common Share	$ 0.66	$ 0.59	$ 1.28	$ 1.18

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Fair Value (Details 6) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Fair Value, Option, Quantitative Disclosures [Line Items]
Realized gains	$ 11	$ 8	$ 19	$ 14
Realized losses	(7)	(7)	(14)	(11)
Proceeds from sales of securities	$ 15	$ 25	$ 27	$ 36

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Supplemental Cash Flow Information Supplemental Cash Flow Information (Details 1) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Other Significant Noncash Transactions [Line Items]
Stock Issued	$ 165	$ 129
Capital Expenditures Incurred but Not yet Paid	$ (17)	$ (55)

XML

Stock-Based Compensation Stock-Based Compensation (Details 2) (USD $)	6 Months Ended
	Jun. 30, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock Awards Outstanding Shares	501,071	597,648
Weighted Average Grant Date Fair Value Per Share Balance	$ 68.35	$ 48.33
Restricted Stock Awards Activity Shares Granted	118,610
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 64.52
Restricted Stock Award Activity Forfeitures	(2,996)
Restricted Stock Awards Activity Forfeitures Weighted Average Fair Value Per Share	$ 51.33
Restricted Stock Award Activity Vested and Issued	(212,191)
Restricted Stock Award Activity Vested and Isued Weighted Average Fair Value Per Share	$ 50.21

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Financial and Other Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair value of derivative instruments

The following tables present the fair value of derivative instruments as of June 30, 2013 and December 31, 2012:

	June 30, 2013					December 31, 2012
	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	—		$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	—		(1		)	—		—
Commodity Contracts:
Natural Gas	504		(510		)	645		(661		)
Electricity	317		(307		)	360		(351		)
Other	55		(52		)	11		(7		)
Total derivatives not designated as hedging instruments:	$	876	$	(870	)	$	1,016	$	(1,019	)
Total derivatives:
Current	$	757	$	(750	)	$	862	$	(879	)
Noncurrent	119		(120		)	154		(141		)
Total derivatives	$	876	$	(870	)	$	1,016	$	(1,020	)

Netting Offsets of Derivative Assets and Liabilities [Table Text Block]

The following table presents the netting offsets of derivative assets and liabilities at June 30, 2013 and December 31, 2012:

	June 30, 2013									December 31, 2012
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position			Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position
	(In millions)
Derivative assets:
Commodity Contracts:
Natural Gas	$	504		$	(490	)	$	14		$	645		$	(605	)	$	40
Electricity	317			(220		)	97			360			(258		)	102
Other	55			(49		)	6			11			(6		)	5
Total derivative assets	$	876		$	(759	)	$	117		$	1,016		$	(869	)	$	147
Derivative liabilities:
Foreign currency exchange contracts	$	(1	)	$	—		$	(1	)	$	—		$	—		$	—
Interest rate contracts	—			—			—			(1		)	—			(1		)
Commodity Contracts:
Natural Gas	(510		)	469			(41		)	(661		)	605			(56		)
Electricity	(307		)	247			(60		)	(351		)	258			(93		)
Other	(52		)	48			(4		)	(7		)	6			(1		)
Total derivative liabilities	$	(870	)	$	764		$	(106	)	$	(1,020	)	$	869		$	(151	)

Netting Offsets of Derivative Assets and Liabilities Reconciliation to the Statements of Financial Position [Table Text Block]

The following table presents the netting offsets of derivative assets and liabilities at June 30, 2013 and December 31, 2012:

	June 30, 2013												December 31, 2012
	Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent			Current			Noncurrent			Current			Noncurrent
	(In millions)
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	757		$	119		$	(750	)	$	(120	)	$	862		$	154		$	(879	)	$	(141	)
Counterparty netting	(653		)	(92		)	653			92			(754		)	(115		)	754			115
Collateral adjustment	(14		)	—			7			12			—			—			—			—
Total derivatives as reported	$	90		$	27		$	(90	)	$	(16	)	$	108		$	39		$	(125	)	$	(26	)

Gain (Loss) Recognized in Income on Derivative

The effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for the three and six months ended June 30, 2013 and 2012 is as follows:

	Location of Gain (Loss) Recognized in Income on Derivatives	Gain (Loss) Recognized in Income on Derivatives for the Three Months Ended June 30,					Gain (Loss) Recognized in Income on Derivatives for the Six Months Ended June 30,
Derivatives not Designated as Hedging Instruments		2013			2012		2013			2012
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	(1	)	$	1	$	(1	)	$	1
Commodity Contracts:
Natural Gas	Operating Revenue	46			1		36			3
Natural Gas	Fuel, purchased power and gas	(46		)	5		(32		)	(5		)
Electricity	Operating Revenue	10			37		30			35
Other	Operating Revenue	(1		)	3		—			11
Total		$	8		$	47	$	33		$	45

Volume of Commodity Contracts [Table Text Block]

The following represents the cumulative gross volume of derivative contracts outstanding as of June 30, 2013:

Commodity	Number of Units
Natural Gas (MMBtu)	574,820,998
Electricity (MWh)	64,291,746
Foreign Currency Exchange ($ CAD)	34,772,009
FTR (MWh)	16,224,782

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Supplemental Cash Flow Information (Notes)

6 Months Ended

Jun. 30, 2013

Supplemental Cash Flow Information [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

A detailed analysis of the changes in assets and liabilities that are reported in the Consolidated Statements of Cash Flows follows:

	Six Months Ended June 30,
	2013			2012
	(In millions)
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	70		$	120
Inventories	133			81
Accrued/prepaid pensions	(42		)	6
Accounts payable	(29		)	(4		)
Income taxes payable/receivable	(20		)	(39		)
Derivative assets and liabilities	(15		)	26
Postretirement obligation	(174		)	(142		)
Gas inventory equalization	73			65
Other assets	324			299
Other liabilities	(45		)	(112		)
	$	275		$	300

Supplementary non-cash information is as follows:

	Six Months Ended June 30,
	2013			2012
	(In millions)
Common stock issued for employee benefit and compensation plans	$	165		$	129
Change in capital expenditures not paid	$	(17	)	$	(55	)

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Significant Accounting Policies (Details 1) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Finite-Lived Intangible Assets [Line Items]
Emission Allowance	$ 4	$ 6
Renewable Energy Credits	47	44
Contract Intangible Assets	141	139
Intangible Assets, Gross	192	189
Less: Accumulated Amortization	40	34
Finite-Lived Intangible Assets, Net	152	155
Intangible Assets, Current	14	20
Less current intangible assets	$ 138	$ 135

XML

Stock-Based Compensation (Details Textuals) (USD $) In Millions, except Share data, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Schedule of Stock Based Compensation [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	4 years 4 months 11 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Exercisable, Number	200,844
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value	$ 10	$ 17
Stock or Unit Option Plan Expense	0	0.5
Unrecognized Compensation Cost	$ 84
Weighted Average to be Recognized	1 year 4 months 29 days

XML

Financial and Other Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	$ 876	$ 1,016
Derivative Liability Fair Value Gross Liability	(870)	(1,020)
Derivative Assets, Current	90	108
Derivative Assets, Noncurrent	27	39
Derivative Liabilities, Current	90	125
Derivative Liabilities, Noncurrent	16	26
Estimate of Fair Value, Fair Value Disclosure [Member]
Derivatives designated as hedging instruments:
Derivative Assets, Current	757	862
Derivative Assets, Noncurrent	119	154
Derivative Liabilities, Current	(750)	(879)
Derivative Liabilities, Noncurrent	(120)	(141)
Derivative [Member]
Derivatives designated as hedging instruments:
Derivative Assets, Current	90	108
Derivative Assets, Noncurrent	27	39
Derivative Liabilities, Current	90	125
Derivative Liabilities, Noncurrent	16	26
Designated as Hedging Instrument [Member] | Interest rate contracts [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	0	0
Derivative Liability Fair Value Gross Liability	0	(1)
Not Designated as Hedging Instrument [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	876	1,016
Derivative Liability Fair Value Gross Liability	(870)	(1,019)
Not Designated as Hedging Instrument [Member] | Foreign currency exchange contracts [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	0	0
Derivative Liability Fair Value Gross Liability	(1)	0
Not Designated as Hedging Instrument [Member] | Natural Gas [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	504	645
Derivative Liability Fair Value Gross Liability	(510)	(661)
Not Designated as Hedging Instrument [Member] | Electricity [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	317	360
Derivative Liability Fair Value Gross Liability	(307)	(351)
Not Designated as Hedging Instrument [Member] | Other [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	55	11
Derivative Liability Fair Value Gross Liability	$ (52)	$ (7)

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Earnings Per Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Basic Earnings per Share
Net Income Attributable to DTE Energy Company	$ 105	$ 146	$ 339	$ 302
Average number of common shares outstanding	174	170	174	170
Weighted average net restricted shares outstanding	1	1	1	1
Dividends declared - common shares	114	100	222	200
Dividends declared - net restricted shares	1	1	0	1
Total distributed earnings	115	101	222	201
Net income less distributed earnings	(10)	45	117	101
Distributed (dividends per common share)	$ 0.66	$ 0.59	$ 1.28	$ 1.18
Undistributed	$ (0.06)	$ 0.27	$ 0.66	$ 0.59
Total Basic Earnings per Common Share	$ 0.60	$ 0.86	$ 1.94	$ 1.77
Diluted Earnings per Share
Net Income Attributable to DTE Energy Company	105	146	339	302
Average number of common shares outstanding	174	170	174	170
Average incremental shares from assumed exercise of options	0	1	0	1
Common shares for dilutive calculation	175	171	174	171
Weighted average net restricted shares outstanding	1	1	1	1
Dividends declared - common shares	114	100	222	200
Dividends declared - net restricted shares	1	1	0	1
Total distributed earnings	115	101	222	201
Net income less distributed earnings	$ (10)	$ 45	$ 117	$ 101
Distributed (dividends per common share)	$ 0.66	$ 0.59	$ 1.28	$ 1.18
Undistributed	$ (0.06)	$ 0.27	$ 0.66	$ 0.59
Total Diluted Earnings per Common Share	$ 0.60	$ 0.86	$ 1.94	$ 1.77

XML

Organization and Basis of Presentation (Details Textuals) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013 customers
Legal Entities [Line Items]
Number of Electric Customers	2,100,000
Number of Gas Customers	1,200,000
Significant Potential Exposure to Loss Due to VIE Long-Term Purchase Contracts	$ 0

XML

Retirement Benefits and Trusteed Assets (Tables)

6 Months Ended

Jun. 30, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Schedule of Costs of Retirement Plans [Table Text Block]

The following table details the components of net periodic benefit costs for pension benefits and other postretirement benefits:

	Pension						Other Postretirement
	Benefits						Benefits
	2013			2012			2013			2012
Three Months Ended June 30	(In millions)
Service cost	$	25		$	20		$	12		$	18
Interest cost	47			51			21			31
Expected return on plan assets	(66		)	(61		)	(27		)	(23		)
Amortization of:
Net actuarial loss	50			43			15			20
Prior service credit	—			—			(36		)	(7		)
Net periodic benefit cost	$	56		$	53		$	(15	)	$	39

	Pension						Other Postretirement
	Benefits						Benefits
	2013			2012			2013			2012
Six Months Ended June 30	(In millions)
Service cost	$	49		$	41		$	28		$	36
Interest cost	95			102			45			61
Expected return on plan assets	(133		)	(122		)	(54		)	(46		)
Amortization of:
Net actuarial loss	101			85			32			39
Prior service credit	—			—			(59		)	(14		)
Net transition liability	—			—			—			1
Settlements	—			2			—			—
Net periodic benefit cost	$	112		$	108		$	(8	)	$	77

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Stock-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2013

Share-based Compensation [Abstract]

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

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
	(In millions)
Stock-based compensation expense	$	35	$	23	$	63	$	40
Tax benefit	14		9		25		15
Stock-based compensation cost capitalized in property, plant and equipment	2		1		4		2

Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]

The following table summarizes our stock option activity for the six months ended June 30, 2013:

	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In millions)
Options outstanding at December 31, 2012	1,192,670		$	41.86
Exercised	(370,959	)	$	40.53
Forfeited or expired	(10,370	)	$	41.46
Options outstanding at June 30, 2013	811,341		$	42.48	$	22
Options exercisable at June 30, 2013	811,341		$	42.48	$	22

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

The following table summarizes the Company’s restricted stock awards activity for the six months ended June 30, 2013:

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at December 31, 2012	597,648		$	48.33
Grants	118,610		$	64.52
Forfeitures	(2,996	)	$	51.33
Vested and issued	(212,191	)	$	50.21
Balance at June 30, 2013	501,071		$	68.35

Summary of Performance Share Activity [Table Text Block]

The following table summarizes the Company’s performance share activity for the six months ended June 30, 2013:

	Performance Shares
Balance at December 31, 2012	1,634,364
Grants	534,027
Forfeitures	(22,906	)
Payouts	(548,624	)
Balance at June 30, 2013	1,596,861

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Discontinued Operations Discontinued Operations (Notes)

6 Months Ended

Jun. 30, 2013

Discontinued Operations [Abstract]

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

DISCONTINUED OPERATIONS

Sale of Unconventional Gas Production Business

In December 2012, the Company sold its 100% equity interest in its Unconventional Gas Production business which consisted of gas and oil production assets in the western Barnett and Marble Falls shale areas of Texas. The activity of the discontinued business for the three and six months ended June 30, 2012 is shown below. The amounts exclude general corporate overhead costs, and the related tax effects, and no portion of corporate interest costs were allocated to discontinued operations.

	Three Months Ended			Six Months Ended
	June 30, 2012			June 30, 2012
	(In millions)
Operating Revenues	$	12		$	22
Operation and Maintenance	5			10
Depreciation, Depletion and Amortization	6			11
Taxes Other Than Income	1			1
Operating Income	—			—
Other (Income) and Deductions	2			3
Income Tax Benefit	(1		)	(2		)
Net Income Attributable to DTE Energy Company	$	(1	)	$	(1	)

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Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013
Asset Retirement Obligations [Line Items]
Asset retirement obligations	$ 1,719
Accretion	52
Asset Retirement Obligation, Revision of Estimate	13
Asset retirement obligations	$ 1,784

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Discontinued Operations Discontinued Operations (Tables)

6 Months Ended

Jun. 30, 2013

Discontinued Operations [Abstract]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]

	Three Months Ended			Six Months Ended
	June 30, 2012			June 30, 2012
	(In millions)
Operating Revenues	$	12		$	22
Operation and Maintenance	5			10
Depreciation, Depletion and Amortization	6			11
Taxes Other Than Income	1			1
Operating Income	—			—
Other (Income) and Deductions	2			3
Income Tax Benefit	(1		)	(2		)
Net Income Attributable to DTE Energy Company	$	(1	)	$	(1	)

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Significant Accounting Policies (Details Textuals) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Significant Accounting Policies [Line Items]
Effective Income Tax Rate, Continuing Operations	29.00%	32.00%	30.00%	32.00%
Unrecognized Tax Benefits	$ 3		$ 3
Unrecognized Tax Benefits, Decreases Resulting from Settlements with Taxing Authorities			$ 1
Time Period of Decrease in Unrecognized Tax Benefits			12 months
Minimum [Member]
Significant Accounting Policies [Line Items]
Finite Lived Asset Useful Life			3 years
Maximum [Member]
Significant Accounting Policies [Line Items]
Finite Lived Intangible Asset, Useful Life 1			28 years

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Common Stock

6 Months Ended

Jun. 30, 2013

Stockholders' Equity Note [Abstract]

Schedule of Stock by Class [Table Text Block]

COMMON STOCK

Common Stock

On March 12, 2013, the Company contributed $50 million of DTE Energy common stock to the DTE Energy Company Affiliates Employee Benefit Plans Master Trust. The contribution consisted of 750,075 shares valued at $66.66 per share. On June 12, 2013, the Company contributed $50 million of DTE Energy common stock to the DTE Energy Company Affiliates Employee Benefit Plans Master Trust. The contribution consisted of 753,579 shares valued at $66.35 per share. The shares for both contributions were valued at the closing market price of DTE Energy common stock on the contribution dates in accordance with fair value measurement and accounting requirements.

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Stock-Based Compensation (Details 1) (USD $) In Millions, except Share data, unless otherwise specified	6 Months Ended
	Jun. 30, 2013
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options outstanding	1,192,670
Exercised	(370,959)
Forfeitured and expired	(10,370)
Options outstanding	811,341
Options exercisable	811,341
Weighted Average Exercise Price Per Share - Options outstanding	$ 41.86
Weighted Average Exercise Price Per Share - Exercised	$ 40.53
Weighted Average Exercise Price Per Share - Forfeitured or expired	$ 41.46
Weighted Average Exercise Price Per Share - Options outstanding	$ 42.48
Weighted Average Exercise Price Per Share - Options exercisable	$ 42.48
Aggregate Intrinsic Value - Options outstanding	$ 22
Aggregate Intrinsic Value - Options exercisable	$ 22

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Financial and Other Derivative Instruments (Notes)

6 Months Ended

Jun. 30, 2013

Derivative Instruments and Hedges, Assets [Abstract]

FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

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

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

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

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

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

Power and Industrial Projects — Business units within this segment manage and operate onsite energy and pulverized coal projects, coke batteries, landfill gas recovery and power generation assets. These businesses utilize fixed-priced contracts in the marketing and management of their assets. These contracts are generally not derivatives and are therefore accounted for under the accrual method.

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

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

Corporate and Other — Interest Rate Risk — The Company uses interest rate swaps, treasury locks and other derivatives to hedge the risk associated with interest rate market volatility. In 2004 and 2000, the Company entered into a series of interest rate derivatives to limit its sensitivity to market interest rate risk associated with the issuance of long-term debt. Such instruments were designated as cash flow hedges. The Company subsequently issued long-term debt and terminated these hedges at a cost that is included in Other comprehensive loss. Amounts recorded in Other comprehensive loss will be reclassified to interest expense through 2033. In 2013, the Company estimates reclassifying less than $1 million of losses to earnings.

Credit Risk — The utility and non-utility businesses are exposed to credit risk if customers or counterparties do not comply with their contractual obligations. The Company maintains credit policies that significantly minimize overall credit risk. These policies include an evaluation of potential customers’ and counterparties’ financial condition, credit rating, collateral requirements or other credit enhancements such as letters of credit or guarantees. The Company generally uses standardized agreements that allow the netting of positive and negative transactions associated with a single counterparty. The Company maintains a provision for credit losses based on factors surrounding the credit risk of its customers, historical trends, and other information. Based on the Company’s credit policies and its June 30, 2013 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to have a material adverse effect on the Company’s financial statements.

Derivative Activities

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

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

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

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

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

The following tables present the fair value of derivative instruments as of June 30, 2013 and December 31, 2012:

	June 30, 2013					December 31, 2012
	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	—		$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	—		(1		)	—		—
Commodity Contracts:
Natural Gas	504		(510		)	645		(661		)
Electricity	317		(307		)	360		(351		)
Other	55		(52		)	11		(7		)
Total derivatives not designated as hedging instruments:	$	876	$	(870	)	$	1,016	$	(1,019	)
Total derivatives:
Current	$	757	$	(750	)	$	862	$	(879	)
Noncurrent	119		(120		)	154		(141		)
Total derivatives	$	876	$	(870	)	$	1,016	$	(1,020	)

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

The Company also provides and receives collateral in the form of letters of credit which can be offset against net derivative assets and liabilities as well as accounts receivable and payable. The Company had issued letters of credit of approximately $37 million and $63 million at June 30, 2013 and December 31, 2012, respectively, which could be used to offset our net derivative liabilities. Letters of credit received from third parties which could be used to offset our net derivative assets were not material for the periods presented. Such balances of letters of credit are excluded from the tables below and are not netted with the recognized assets and liabilities in the Consolidated Statements of Financial Position.

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

As of June 30, 2013, the total cash collateral posted, net of cash collateral received, was $2 million. As of December 31, 2012, the total cash collateral received, net of cash collateral posted, was $20 million. As of June 30, 2013, derivative assets and derivative liabilities are shown net of cash collateral of $14 million and $19 million, respectively. There was no cash collateral related to unrealized positions to net against derivative assets and liabilities as of December 31, 2012. The Company recorded cash collateral paid of $6 million and cash collateral received of $3 million not related to unrealized derivative positions as of June 30, 2013. The Company recorded cash collateral paid of $4 million and cash collateral received of $24 million not related to unrealized derivative positions as of December 31, 2012. These amounts are included in accounts receivable and accounts payable and are recorded net by counterparty.

The following table presents the netting offsets of derivative assets and liabilities at June 30, 2013 and December 31, 2012:

	June 30, 2013									December 31, 2012
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position			Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position
	(In millions)
Derivative assets:
Commodity Contracts:
Natural Gas	$	504		$	(490	)	$	14		$	645		$	(605	)	$	40
Electricity	317			(220		)	97			360			(258		)	102
Other	55			(49		)	6			11			(6		)	5
Total derivative assets	$	876		$	(759	)	$	117		$	1,016		$	(869	)	$	147
Derivative liabilities:
Foreign currency exchange contracts	$	(1	)	$	—		$	(1	)	$	—		$	—		$	—
Interest rate contracts	—			—			—			(1		)	—			(1		)
Commodity Contracts:
Natural Gas	(510		)	469			(41		)	(661		)	605			(56		)
Electricity	(307		)	247			(60		)	(351		)	258			(93		)
Other	(52		)	48			(4		)	(7		)	6			(1		)
Total derivative liabilities	$	(870	)	$	764		$	(106	)	$	(1,020	)	$	869		$	(151	)

The following table presents the netting offsets of derivative assets and liabilities at June 30, 2013 and December 31, 2012:

	June 30, 2013												December 31, 2012
	Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent			Current			Noncurrent			Current			Noncurrent
	(In millions)
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	757		$	119		$	(750	)	$	(120	)	$	862		$	154		$	(879	)	$	(141	)
Counterparty netting	(653		)	(92		)	653			92			(754		)	(115		)	754			115
Collateral adjustment	(14		)	—			7			12			—			—			—			—
Total derivatives as reported	$	90		$	27		$	(90	)	$	(16	)	$	108		$	39		$	(125	)	$	(26	)

The effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for the three and six months ended June 30, 2013 and 2012 is as follows:

	Location of Gain (Loss) Recognized in Income on Derivatives	Gain (Loss) Recognized in Income on Derivatives for the Three Months Ended June 30,					Gain (Loss) Recognized in Income on Derivatives for the Six Months Ended June 30,
Derivatives not Designated as Hedging Instruments		2013			2012		2013			2012
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	(1	)	$	1	$	(1	)	$	1
Commodity Contracts:
Natural Gas	Operating Revenue	46			1		36			3
Natural Gas	Fuel, purchased power and gas	(46		)	5		(32		)	(5		)
Electricity	Operating Revenue	10			37		30			35
Other	Operating Revenue	(1		)	3		—			11
Total		$	8		$	47	$	33		$	45

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

The effects of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position were $3 million and $4 million in unrealized gains related to FTRs recognized in Regulatory liabilities for the three and six months ended June 30, 2013, respectively.

The following represents the cumulative gross volume of derivative contracts outstanding as of June 30, 2013:

Commodity	Number of Units
Natural Gas (MMBtu)	574,820,998
Electricity (MWh)	64,291,746
Foreign Currency Exchange ($ CAD)	34,772,009
FTR (MWh)	16,224,782

Various non-utility subsidiaries of the Company have entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade. Certain of these provisions (known as “hard triggers”) state specific circumstances under which the Company can be asked to post collateral upon the occurrence of a credit downgrade, while other provisions (known as “soft triggers”) are not as specific. For contracts with soft triggers, it is difficult to estimate the amount of collateral which may be requested by counterparties and/or which the Company may ultimately be required to post. The amount of such collateral which could be requested fluctuates based on commodity prices (primarily natural gas, power and coal) and the provisions and maturities of the underlying transactions. As of June 30, 2013, 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 $313 million.

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Consolidated Statements of Cash Flows (Unaudited) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Operating Activities
Net Income	$ 342	$ 305
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	527	482
Deferred income taxes	123	81
Asset (gains), losses and reserves and impairments, net	0	(7)
Changes in assets and liabilities, exclusive of changes shown separately (Note 15)	275	300
Net cash from operating activities	1,267	1,161
Investing Activities
Plant and equipment expenditures — utility	(708)	(708)
Plant and equipment expenditures — non-utility	(197)	(131)
Proceeds from sale of assets	15	15
Restricted cash for debt redemption, principally Securitization	10	15
Proceeds from sale of nuclear decommissioning trust fund assets	27	36
Investment in nuclear decommissioning trust funds	(35)	(44)
Other	(23)	(15)
Net cash used for investing activities	(911)	(832)
Financing Activities
Issuance of long-term debt, net	371	496
Redemption of long-term debt	(515)	(140)
Short-term borrowings, net	(24)	(380)
Issuance of common stock	19	20
Dividends on common stock	(215)	(199)
Other	(11)	(9)
Net cash used for financing activities	(375)	(212)
Net Increase (Decrease) in Cash and Cash Equivalents	(19)	117
Cash and Cash Equivalents at Beginning of Period	65	68
Cash and Cash Equivalents at End of Period	$ 46	$ 185

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Fair Value (Details 7) (USD $) In Millions, unless otherwise specified	6 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2012
Fair Value, Option, Quantitative Disclosures [Line Items]
Nuclear decommissioning trusts	$ 1,080	$ 1,037
Unrealized Gains	176	149
Equity securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Equity securities	679	631
Unrealized Gains	161	122
Debt securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Debt securities	390	399
Unrealized Gains	15	27
Cash and cash equivalents [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Cash and cash equivalents	11	7
Unrealized Gains	$ 0	$ 0

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Fair Value Fair Value (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Fair Value, Inputs, Level 1 [Member]
Fair Value Transfers Between Level 1, Level 2 and Level 3 [Line Items]
Transfers into Level 2	$ 0	$ 0	$ 0	$ 0
Transfers into Level 3	0	0	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value Transfers Between Level 1, Level 2 and Level 3 [Line Items]
Transfers into Level 1	0	0	0	0
Transfers into Level 3	0	1	0	29
Fair Value, Inputs, Level 3 [Member]
Fair Value Transfers Between Level 1, Level 2 and Level 3 [Line Items]
Transfers into Level 1	0	0	0	0
Transfers into Level 2	$ 0	$ 0	$ 2	$ 2

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Segment Information (Details 1) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Segment Reporting Information [Line Items]
Operating Revenue	$ 2,225	$ 2,013	$ 4,741	$ 4,252
Net Income (Loss) Attributable to Parent	105	146	339	302
Electric [Member]
Segment Reporting Information [Line Items]
Operating Revenue	1,265	1,290	2,484	2,488
Net Income (Loss) Attributable to Parent	89	127	204	223
Gas [Member]
Segment Reporting Information [Line Items]
Operating Revenue	248	214	852	723
Net Income (Loss) Attributable to Parent	8	4	104	56
Gas Storage and Pipelines [Member]
Segment Reporting Information [Line Items]
Operating Revenue	31	27	58	52
Net Income (Loss) Attributable to Parent	16	17	33	34
Power and Industrial Projects [Member]
Segment Reporting Information [Line Items]
Operating Revenue	429	449	919	898
Net Income (Loss) Attributable to Parent	7	10	19	18
Energy Trading [Member]
Segment Reporting Information [Line Items]
Operating Revenue	451	239	844	500
Net Income (Loss) Attributable to Parent	(2)	4	5	2
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating Revenue	1	1	1	2
Net Income (Loss) Attributable to Parent	(13)	(15)	(26)	(30)
Corporate Elimination [Member]
Segment Reporting Information [Line Items]
Operating Revenue	(200)	(207)	(417)	(411)
Segment, Discontinued Operations [Member]
Segment Reporting Information [Line Items]
Net Income (Loss) Attributable to Parent	$ 0	$ (1)	$ 0	$ (1)

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Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2013

Long-term Debt, Unclassified [Abstract]

Schedule of Issued Debt [Table Text Block]

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

Company	Month Issued	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March	Mortgage Bonds (a)	4.00	%	2043	$	375
						$	375

_______________________________________

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

Schedule of Extinguishment of Debt [Table Text Block]

In 2013, the following debt was redeemed:

	Month	Type	Interest Rate		Maturity	Amount
						(In millions)
DTE Electric	March	Securitization Bonds	6.42	%	2013	$	88
DTE Electric	March	Tax Exempt Revenue Bonds (a)	5.30	%	2030	51
DTE Electric	April	Other Long-Term Debt	Various		2013	13
DTE Energy	Various	Other Long-Term Debt	Various		2013	3
DTE Gas	April	Senior Notes	5.26	%	2013	60
DTE Energy	June	Senior Notes	Variable		2013	300
						$	515

_______________________________________

(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.

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Segment Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	$ 2,225	$ 2,013	$ 4,741	$ 4,252
Electric [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	7	8	13	15
Gas [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	1	1	2	2
Gas Storage and Pipelines [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	2	3	4	4
Power and Industrial Projects [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	185	192	390	383
Energy Trading [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	12	10	23	24
Corporate and Other [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	(7)	(7)	(15)	(17)
Segment Inter Co [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	$ 200	$ 207	$ 417	$ 411

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Long-Term Debt (Details) (Mortgages [Member], USD $) In Millions, unless otherwise specified	Jun. 30, 2013
Mortgages [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.00%
Debt Instrument, Face Amount	$ 375

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Financial and Other Derivative Instruments (Details Textuals) (USD $)	3 Months Ended	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2013	Dec. 31, 2012
Derivative [Line Items]
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	$ 1,000,000	$ 1,000,000
Cash Collateral Remaiining Balance After Netting	0	0
Letters of Credit Issued	37,000,000	37,000,000	63,000,000
Cash Collateral Posted Net of Cash Collateral Received	2,000,000	2,000,000
Collateral Already Posted, Aggregate Fair Value			20,000,000
Cash Collateral Paid or Received for Derivative Assets	14,000,000	14,000,000	0
Cash Collateral Paid or Received for Derivative Liabilities	19,000,000	19,000,000
Cash Collateral Received	3,000,000	3,000,000	24,000,000
Cash Collateral Paid	6,000,000	6,000,000	4,000,000
Derivative Instruments Recoverable Through PSCR Mechanism	3,000,000	4,000,000
Value of Transactions Company Would Have Been Exposed to if Credit Rating Below Investment Grade	$ 313,000,000	$ 313,000,000

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Short-Term Credit Arrangements and Borrowings (Notes)

6 Months Ended

Jun. 30, 2013

Short-term Debt [Abstract]

SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

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

The agreements require the Company to maintain a total funded debt to capitalization ratio of no more than 0.65 to 1. In the agreements, “total funded debt” means all indebtedness of the Company and its consolidated subsidiaries, including capital lease obligations, hedge agreements and guarantees of third parties’ debt, but excluding contingent obligations, nonrecourse and junior subordinated debt and certain equity-linked securities and, except for calculations at the end of the second quarter, certain DTE Gas short-term debt. “Capitalization” means the sum of (a) total funded debt plus (b) “consolidated net worth,” which is equal to consolidated total stockholders’ equity of the Company and its consolidated subsidiaries (excluding pension effects under certain FASB statements), as determined in accordance with accounting principles generally accepted in the United States of America. At June 30, 2013, the total funded debt to total capitalization ratios for DTE Energy, DTE Electric and DTE Gas are 0.48 to 1, 0.53 to 1 and 0.44 to 1, respectively, and are in compliance with this financial covenant. The availability under the facilities in place at June 30, 2013 is shown in the following table:

	DTE Energy		DTE Electric		DTE Gas		Total
	(In millions)
Unsecured letter of credit facility, expiring in May 2014	$	50	$	—	$	—	$	50
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Unsecured revolving credit facility, expiring April 2018	1,200		300		300		1,800
Total credit facilities at June 30, 2013	1,375		300		300		1,975
Amounts outstanding at June 30, 2013:
Commercial paper issuances	101		96		19		216
Letters of credit	184		—		—		184
	285		96		19		400
Net availability at June 30, 2013	$	1,090	$	204	$	281	$	1,575

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $38 million which are used for various corporate purposes.

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 June 30, 2013, a $40 million letter of credit was in place, raising the capacity under this facility to $140 million. The $40 million letter of credit is included in the table above. The amount outstanding under this agreement was $64 million and $65 million at June 30, 2013 and December 31, 2012, respectively.

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Regulatory Matters (Notes)

6 Months Ended

Jun. 30, 2013

Public Utilities, General Disclosures [Abstract]

REGULATORY MATTERS

REGULATORY MATTERS

Energy Optimization (EO) Plans

In May 2013, DTE Electric and DTE Gas filed separate applications for approval of their respective reconciliations of their 2012 EO plan expenses. DTE Electric's EO reconciliation includes a cumulative $26 million net over-recovery and DTE Gas's EO reconciliation includes a cumulative $7 million net over-recovery for their 2012 EO plans. DTE Electric and DTE Gas proposed that the calculated over-recoveries for 2012 be carried forward into 2013 and used as beginning balances for the 2013 reconciliations. In July 2013, DTE Electric and DTE Gas filed separate applications with the MPSC for the biennial review of their EO plans.

Renewable Energy Plan (REP)

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

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

Accounting Authority

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

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

Transitional Reconciliation Mechanism (TRM)

On July 19, 2013, DTE Electric filed its TRM application proposing a transitional tariff option for certain former PLD customers and a modified line extension provision. The application also proposes a recovery mechanism for the deferred incremental revenue requirement described above. The application further discusses that DTE Electric will be requesting recovery, in subsequent PSCR cases, of PLD transmission delivery service costs incurred while DTE Electric is temporarily relying upon PLD to operate and maintain PLD's system during the system conversion period. If the MPSC determines that the transmission costs are not recoverable in the PSCR, the Company requested recovery as part of the TRM.

Power Supply Cost Recovery Proceedings

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

2010 PSCR Year —In March 2011, DTE Electric filed the 2010 PSCR reconciliation calculating a net under-recovery of $52.6 million that includes an over-recovery of $15.6 million for the 2009 PSCR year. In addition, the 2010 PSCR reconciliation includes an under-recovery of $7.1 million for the reconciliation of the 2007-2008 Pension Equalization Mechanism, and an over-refund of $3.8 million for the 2011 refund of the self-implemented rate increase related to the 2009 electric rate case filing. On April 25, 2013, the MPSC approved the 2010 PSCR net under-recovery of $52.6 million and the recovery of this amount as part of the 2011 PSCR reconciliation. The order also approved DTE Electric's Pension Equalization Mechanism reconciliation and authorized a one month surcharge in June 2013 and approved the recovery of the over-refund of the self-implemented rate increase related to the 2009 electric rate case filing as part of the 2011 PSCR reconciliation.

2012 Plan Year— In September 2011, DTE Energy filed its 2012 PSCR plan case seeking approval of a levelized PSCR factor of 4.18 mills/kWh above the amount included in base rates for all PSCR customers. The filing supports a total power supply expense forecast of $1.4 billion. The plan also includes approximately $158 million for the recovery of its projected 2011 PSCR under-recovery. On June 28, 2013, the MPSC approved DTE Energy's 2012 PSCR plan.

DTE Gas Revenue Decoupling Mechanism (RDM)

In May 2013, DTE Gas filed an application with the MPSC for approval of its RDM reconciliation for the period July 1, 2012 through October 31, 2012. DTE Gas's RDM application proposed the recovery of a net under-recovery of approximately $5.2 million.

DTE Gas Depreciation Filing

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

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Short-Term Credit Arrangements and Borrowings (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013
Availability under combined facilities
Total credit facilities	$ 1,975
Commercial Paper	216
Amounts Outstanding
Letters of credit	184
Total amounts outstanding	400
Net availability	1,575
Unsecured letter of credit facility [Member]
Availability under combined facilities
Total credit facilities	50
Unsecured letter of credit facility [Member]
Availability under combined facilities
Total credit facilities	125
Unsecured revolving credit facility [Member]
Availability under combined facilities
Total credit facilities	1,800
DTE Energy [Member]
Availability under combined facilities
Total credit facilities	1,375
Commercial Paper	101
Amounts Outstanding
Letters of credit	184
Total amounts outstanding	285
Net availability	1,090
DTE Energy [Member] | Unsecured letter of credit facility [Member]
Availability under combined facilities
Total credit facilities	50
DTE Energy [Member] | Unsecured letter of credit facility [Member]
Availability under combined facilities
Total credit facilities	125
DTE Energy [Member] | Unsecured revolving credit facility [Member]
Availability under combined facilities
Total credit facilities	1,200
DTE Electric [Member]
Availability under combined facilities
Total credit facilities	300
Commercial Paper	96
Amounts Outstanding
Letters of credit	0
Total amounts outstanding	96
Net availability	204
DTE Electric [Member] | Unsecured letter of credit facility [Member]
Availability under combined facilities
Total credit facilities	0
DTE Electric [Member] | Unsecured letter of credit facility [Member]
Availability under combined facilities
Total credit facilities	0
DTE Electric [Member] | Unsecured revolving credit facility [Member]
Availability under combined facilities
Total credit facilities	300
DTE Gas [Member]
Availability under combined facilities
Total credit facilities	300
Commercial Paper	19
Amounts Outstanding
Letters of credit	0
Total amounts outstanding	19
Net availability	281
DTE Gas [Member] | Unsecured letter of credit facility [Member]
Availability under combined facilities
Total credit facilities	0
DTE Gas [Member] | Unsecured letter of credit facility [Member]
Availability under combined facilities
Total credit facilities	0
DTE Gas [Member] | Unsecured revolving credit facility [Member]
Availability under combined facilities
Total credit facilities	$ 300

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Stock-Based Compensation (Notes)

6 Months Ended

Jun. 30, 2013

Share-based Compensation [Abstract]

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
	(In millions)
Stock-based compensation expense	$	35	$	23	$	63	$	40
Tax benefit	14		9		25		15
Stock-based compensation cost capitalized in property, plant and equipment	2		1		4		2

Stock Options

The following table summarizes our stock option activity for the six months ended June 30, 2013:

	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In millions)
Options outstanding at December 31, 2012	1,192,670		$	41.86
Exercised	(370,959	)	$	40.53
Forfeited or expired	(10,370	)	$	41.46
Options outstanding at June 30, 2013	811,341		$	42.48	$	22
Options exercisable at June 30, 2013	811,341		$	42.48	$	22

As of June 30, 2013, the weighted average remaining contractual life for the exercisable shares is 4.36 years. During the six months ended June 30, 2013, 200,844 options vested. As of June 30, 2013, all options were vested.

The intrinsic value of options exercised for the six months ended June 30, 2013 and 2012 was $10 million and $17 million, respectively. No option expense was recognized for the six months ended June 30, 2013 and $0.5 million of option expense was recognized for the six months ended June 30, 2012.

The Company includes both historical and implied share-price volatility in option volatility. Implied volatility is derived from exchange traded options on DTE Energy common stock. The Company’s expected option life estimate is based on historical data.

Restricted Stock Awards

The following table summarizes the Company’s restricted stock awards activity for the six months ended June 30, 2013:

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at December 31, 2012	597,648		$	48.33
Grants	118,610		$	64.52
Forfeitures	(2,996	)	$	51.33
Vested and issued	(212,191	)	$	50.21
Balance at June 30, 2013	501,071		$	68.35

Performance Share Awards

The following table summarizes the Company’s performance share activity for the six months ended June 30, 2013:

	Performance Shares
Balance at December 31, 2012	1,634,364
Grants	534,027
Forfeitures	(22,906	)
Payouts	(548,624	)
Balance at June 30, 2013	1,596,861

Unrecognized Compensation Costs

As of June 30, 2013, there was $84 million of total unrecognized compensation cost related to non-vested stock incentive plan arrangements. That cost is expected to be recognized over a weighted-average period of 1.41 years.

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Commitments and Contingencies (Notes)

6 Months Ended

Jun. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

Environmental

Electric

Air - DTE Electric is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze, mercury, and other air pollution. These rules have led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, mercury and other emissions. To comply with these requirements, DTE Electric spent approximately $1.9 billion through 2012. The Company estimates DTE Electric will make capital expenditures of approximately $335 million in 2013 and up to approximately $1.8 billion of additional capital expenditures through 2021 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants. The Cross State Air Pollution Rule (CSAPR), finalized in July 2011, required further reductions of sulfur dioxide and nitrogen oxides emissions beginning in 2012. On December 30, 2011, the U.S. Court of Appeals for the District of Columbia (D.C.) Circuit granted the motions to stay the rule, leaving DTE Electric temporarily subject to the previously existing Clean Air Interstate Rule (CAIR). On August 21, 2012, the Court issued its decision, vacating CSAPR and leaving CAIR in place. The EPA's petition seeking a rehearing of the U.S. Court of Appeals' decision regarding the CSAPR was denied on January 24, 2013. On June 24, 2013, the U.S. Supreme Court granted EPA's petition asking the Court to review the D.C. Circuit Court's decision on CSAPR. A ruling by the Supreme Court is not expected before 2014. Notwithstanding the appeal filed with the Supreme Court, the EPA and a number of states have started working on the framework of revised CSAPR regulations which we anticipate to be proposed in the next few years.

The Mercury and Air Toxics Standard (MATS) rule, formerly known as the Electric Generating Unit Maximum Achievable Control Technology (EGU MACT) Rule was finalized on December 16, 2011. The MATS rule requires reductions of mercury and other hazardous air pollutants beginning in 2015. 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 operate in compliance with MATS.

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

In August 2010, the U.S. Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and DTE Electric, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require DTE Electric to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require DTE Electric to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from DTE Electric's fleet of coal-fired power plants until the new control equipment is operating. On August 23, 2011, the U.S. District Court judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy and DTE Electric. On October 20, 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit. On March 28, 2013, the Court of Appeals remanded the case to the U.S. District Court for review of the procedural component of the New Source Review notification requirements.

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

On March 13, 2013, The Sierra Club filed suit against DTE Energy and DTE Electric alleging violations of the Clean Air Act at four of DTE Electric's coal-fired power plants. The plaintiffs allege 1,499 6-minute periods of excess opacity of air emissions from 2007-2012 at those facilities. The suit asks that the court enjoin the Company from operating the power plants except in complete compliance with applicable laws and permit requirements, pay civil penalties, conduct beneficial environmental mitigation projects, pay attorney fees and require the installation of any necessary pollution controls or to convert and/or operate the plants' boilers on natural gas to avoid additional violations and to off-set historic unlawful emissions. The resolution of this matter is not expected to have a material effect on the Company's operations or financial statements.

Water — In response to an EPA regulation, DTE Electric would be required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of completed studies and expected future studies, DTE Electric may be required to install technologies to reduce the impacts of the water intake structures. The initial rule published in 2004 was subsequently remanded and a proposed rule published in 2011. The proposed rule specified an eight year compliance timeline. In July 2012, the EPA announced that a notice of its final action on the rule will be issued in June 2013. On June 27, 2013, the EPA announced an agreement to extend the deadline for issuance of the final rule until November 4, 2013. On April 19, 2013, the EPA proposed revised steam electric effluent guidelines regulating wastewater streams from coal-fired power plants including multiple possible options for compliance. The rules are expected to be finalized by May 2014. DTE Electric is in the process of reviewing the proposal and will provide comments to the EPA within the allotted time. However, it is not possible at this time to quantify the impacts of these developing requirements.

Contaminated and Other Sites — Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. The facilities, which produced gas, have been designated as manufactured gas plant (MGP) sites. DTE Electric conducted remedial investigations at contaminated sites, including three former MGP sites. The investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites, including the area surrounding an ash landfill, electrical distribution substations, electric generating power plants, and underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is expected to be incurred over the next several years. At June 30, 2013 and December 31, 2012, the Company had $9 million accrued for remediation. Any change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows. The Company believes that the likelihood of a materially greater liability than the accrued amount is remote based on current knowledge of the conditions at each site.

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

Gas

Contaminated 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. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites. Cleanup activities associated with these sites will be conducted over the next several years.

The MPSC has established a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites. Accordingly, Gas segment recognizes a liability and corresponding Regulatory asset for estimated investigation and remediation costs at former MGP sites. As of June 30, 2013 and December 31, 2012, the Company had $30 million and $29 million accrued for remediation, respectively.

Any change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows. The Company anticipates the cost amortization methodology approved by the MPSC for DTE Gas, which allows DTE Gas to amortize the MGP costs over a ten-year period beginning with the year subsequent to the year the MGP costs were incurred and the cost deferral and rate recovery mechanism for Citizens Fuel Gas approved by the City of Adrian, will prevent environmental costs from having a material adverse impact on the Company’s results of operations.

Non-utility

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

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

The Company received two NOVs from the Pennsylvania Department of Environmental Protection (PADEP) in 2010 alleging violations of the permit for the Pennsylvania coke battery facility in connection with coal pile storm water runoff. The Company has implemented best management practices to address this issue. The Company recently received a permit to upgrade its existing waste water treatment system and is currently seeking a permit from the PADEP to upgrade its wastewater treatment technology to a biological treatment facility. The Company expects to spend less than $6 million on the existing waste water treatment system to comply with existing water discharge requirements and to upgrade its coal pile storm water runoff management program.

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

Other

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

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

Nuclear Operations

Property Insurance

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

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

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

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

Under the NEIL policies, DTE Electric could be liable for maximum assessments of up to approximately $33 million per event if the loss associated with any one event at any insured 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 $117.5 million could be levied against each licensed nuclear facility, but not more than $17.5 million per year per facility. Thus, deferred premium charges could be levied against all owners of licensed nuclear facilities in the event of a nuclear incident at any of these facilities.

Nuclear Fuel Disposal Costs

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

DTE Electric is a party in the litigation against the DOE for both past and future costs associated with the DOE's failure to accept spent nuclear fuel under the timetable set forth in the Federal Nuclear Waste Policy Act of 1982. In July 2012, DTE Electric executed a settlement agreement with the federal government for costs associated with the DOE's delay in acceptance of spent nuclear fuel from Fermi 2 for permanent storage. The settlement provided for a payment of approximately $48 million, received in August 2012, for delay-related costs experienced by DTE Electric through 2010, and a claims process for submittal of delay-related costs from 2011 through 2013. DTE Electric has begun the claims process and currently no claims submitted have been denied. The settlement proceeds reduced the cost of the dry cask storage facility assets. In February 2013, the U.S. Court of Appeals for the District of Columbia granted a motion to reopen the fee adequacy litigation to review the DOE's latest fee adequacy report which was released in January 2013. DTE Electric will continue to pay fees to the U.S. government's nuclear waste fund pending further action by the D.C. Circuit. 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 June 30, 2013 is approximately $1.2 billion. Payment under these guarantees is considered remote.

Reduced Emissions Fuel Guarantees

The Company has provided certain guarantees and indemnities in conjunction with the sales of interests in its reduced emissions fuel facilities. The guarantees cover potential commercial, environmental, and tax-related obligations and will survive until 90 days after expiration of all applicable statutes of limitations. The Company estimates that its maximum potential liability under these guarantees at June 30, 2013 is approximately $103 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 $61 million at June 30, 2013. Payment under these guarantees is considered remote.

The Company is periodically required to obtain performance surety bonds in support of obligations to various governmental entities and other companies in connection with its operations. As of June 30, 2013, the Company had approximately $41 million of performance bonds outstanding. In the event that such bonds are called for nonperformance, the Company would be obligated to reimburse the issuer of the performance bond. The Company is released from the performance bonds as the contractual performance is completed and does not believe that a material amount of any currently outstanding performance bonds will be called.

Labor Contracts

Our contracts with several bargaining units for the majority of our represented employees were due to expire in June and October 2013. Early negotiations resulted in new contracts that became effective March 23, 2013. The new contracts will expire in June and October 2017.

Purchase Commitments

As of June 30, 2013, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments and energy trading contracts. The Company estimates that these commitments will be approximately $4.4 billion from 2013 through 2052.

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

Bankruptcies

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

The Company's utilities provide services to the city of Detroit, Michigan (Detroit). Detroit filed for Chapter 9 bankruptcy protection on July 18, 2013. Based on average monthly revenues and typical billing and payment cycles, the Company estimates that it has pre-petition accounts receivable of approximately $18 million. Detroit has been paying amounts owed in a timely manner and its account is substantially current. The Company does not expect Detroit's bankruptcy filing to have a material impact on its financial results.

Other Contingencies

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

See Notes 4 and 7 for a discussion of contingencies related to derivatives and regulatory matters.

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DEI Document	6 Months Ended
	Jun. 30, 2013
Entity Registrant Name	DTE ENERGY CO
Entity Central Index Key	0000936340
Current Fiscal Year End Date	--06-30
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding	174,960,000

XML

Retirement Benefits and Trusteed Assets (Notes)

6 Months Ended

Jun. 30, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Pension and Other Postretirement Benefits Disclosure [Text Block]

RETIREMENT BENEFITS AND TRUSTEED ASSETS

The following table details the components of net periodic benefit costs for pension benefits and other postretirement benefits:

	Pension						Other Postretirement
	Benefits						Benefits
	2013			2012			2013			2012
Three Months Ended June 30	(In millions)
Service cost	$	25		$	20		$	12		$	18
Interest cost	47			51			21			31
Expected return on plan assets	(66		)	(61		)	(27		)	(23		)
Amortization of:
Net actuarial loss	50			43			15			20
Prior service credit	—			—			(36		)	(7		)
Net periodic benefit cost	$	56		$	53		$	(15	)	$	39

	Pension						Other Postretirement
	Benefits						Benefits
	2013			2012			2013			2012
Six Months Ended June 30	(In millions)
Service cost	$	49		$	41		$	28		$	36
Interest cost	95			102			45			61
Expected return on plan assets	(133		)	(122		)	(54		)	(46		)
Amortization of:
Net actuarial loss	101			85			32			39
Prior service credit	—			—			(59		)	(14		)
Net transition liability	—			—			—			1
Settlements	—			2			—			—
Net periodic benefit cost	$	112		$	108		$	(8	)	$	77

Pension and Other Postretirement Contributions

During the first six months of 2013, the Company contributed $150 million to its pension plans, including a contribution of DTE Energy common stock of $100 million. See Note 8. At the discretion of management, and depending upon financial market conditions, the Company may make up to an additional $125 million contribution to its pension plans in 2013.

In January 2013, the Company contributed $145 million to its other postretirement benefit plans. At the discretion of management, the Company may make up to an additional $120 million contribution to its other postretirement benefit plans in 2013.

Re-Measurement of Other Postretirement Benefit Obligation

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

Based on the impact of such benefit cost savings on the 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. As a result of the re-measurement, the accumulated postretirement benefit obligation (ABPO) was reduced by $258 million. The Company's Accrued postretirement benefit liability at March 31, 2013 was $721 million as compared to $1.2 billion at December 31, 2012, a reduction of $439 million. The reduction reflects the impact of the re-measurement of the plan, January 2013 plan contributions and recognition of first quarter 2013 postretirement benefit costs and benefit payments.

Beginning April 2013, net postretirement benefit costs were recorded based on the updated actuarial assumptions and benefit changes resulting from the new labor contracts. As a result of the re-measurement, fiscal year 2013 postretirement benefit costs are expected to decrease by approximately $69 million to an annual net benefit of approximately $40 million.

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Discontinued Operations Discontinued Operations (Details Textuals)	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of Equity Sold	100.00%

XML

Discontinued Operations Discontinued Operations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating Income (Loss)	$ 223	$ 294	$ 633	$ 606
Income Tax Expense (Benefit)	44	70	149	143
Segment, Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Revenue		12		22
Disposal Group, Including Discontinued Operation, Operating Expense		5		10
Depreciation and Amortization, Discontinued Operations		6		11
Taxes Other than Income Related to Discontinued Operations		1		1
Operating Income (Loss)		0		0
Other Nonoperating Income (Expense)		2		3
Income Tax Expense (Benefit)		(1)		(2)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent		$ (1)		$ (1)